diff --git "a/experimentation_mlops/mlops/data/2week_news_data.json" "b/experimentation_mlops/mlops/data/2week_news_data.json" new file mode 100644--- /dev/null +++ "b/experimentation_mlops/mlops/data/2week_news_data.json" @@ -0,0 +1 @@ +[{"Unnamed: 0":0,"body":" Uganda has resumed refined product imports through Tanzania's port of Dar es Salaam, its national oil company said Aug. 16, as restrictions on its fuel imports through Kenya have left it unable to source sufficient supply. The landlocked East African country has historically relied on oil products delivered through Kenya for almost 90% of its supply, relying on Kenyan oil marketing companies to import fuel to the port of Mombasa and supplementing supplies with product from Tanzania. In June, however, the country sought to overhaul its fuel supply links by agreeing a direct five-year exclusive supply agreement with Vitol Bahrain, which promised to deliver all of its refined product supply to Mombasa and bypass smaller oil marketing companies. Uganda National Oil Company received its first fuel cargoes at Mombasa July 2 , although new restrictions from Kenya on imports through its pipeline system have prevented adequate supplies from reaching the country. Speaking to Ugandan press, Anthony Ogalo, CEO of Uganda's Sustainable Energies and Petroleum Association said that Kenya's Ministry of Energy and Petroleum has restricted the volumes Uganda can import through its Kenya Pipeline Company connection, citing system constraints limiting maximum gasoline cargo sizes to 58,000 metric tons and diesel\/gasoil to 65,000 t. Proscovia Nabbanja, CEO of UNOC told Uganda Broadcasting Corporation Aug. 16 that the restriction had left Uganda with insufficient fuel supply to cover its demand, forcing the government to seek alternative supplies from Tanzania's Dar es Salaam. \"The decision to shift to Dar es Salaam was prompted by the technical and cost issues associated with using Mombasa, leading Uganda to seek the alternative through Dar es Salaam,\" she said. According to Nabbanja, Uganda received its first shipment of 18 million liters (around 110,000 barrels) of both gasoline and diesel Via Dar es Salaam Aug. 8 to alleviate supply issues and is expecting to increase imports to 36 million liters (around 226,000 barrels) monthly as it has started to shun the Mombasa route. Uganda imports an average of 2.5 billion liters (around 43,000 b\/d) of petroleum annually, according to 2022 bank of Uganda data. The company also engaged with the Kenyan government on the prospect of increased deliveries via truck from western Kenya to avoid pipeline restrictions, seeking to boost deliveries to the Kipevu Oil Terminal 2 (KOT2) at the port of Mombasa and use Kenya's state-owned pipeline facilities to transport supplies to the Kenyan city of Kisumu, although talks proved unsuccessful, Nabbanja said. Uganda's decision to shift imports to Dar es Salaam was triggered by pressure from its oil marketing companies (OMCs) under their umbrella body, SEPA, which demanded that the government shifts its sourcing to Tanzania to address energy security concerns. ","headline":"Uganda shifts oil product imports from Mombasa to Dar es Salaam","updatedDate":"2024-08-16T21:24:08.000"},{"Unnamed: 0":1,"body":" After six years of changes in the Mexican fuels sector from the federal government that effectively killed its liberalization process, market participants, observers and experts agree the sector badly needs clear rules as the new administration of President-elect Claudia Sheinbaum Pardo begins. The sector has many more needs, including long-term planning and urgent investments in storage facilities, but the main need, the one that is shared by most, is certainty in the rules of the game, they said. \u201cThe Mexican energy sector requires a legal framework that is clear and consistent, and investors need legal certainty to make investments,\u201d Pablo Necoechea, director of business school EGADE, said Aug. 15. Investments in the energy sector should be long term, not for just one six-year term, and this can only occur when the rules of the game are stable and applied evenly, Necoechea said during a panel discussion at a three-day energy forum organized by Mexico-based Oil&Gas Magazine. Only by having rules applied evenly can there be compliance and transparency, he said during the panel discussion, which S&P Global Commodity Insights moderated. Sheinbaum Pardo will take office Oct. 1, but she has already said she will continue with the basic principle of current President Andr\u00e9s Manuel L\u00f3pez Obrador, which is to strengthen the role of the state companies Pemex and CFE and to end the country's dependency on imports by using all the country's crude output to produce fuels. L\u00f3pez Obrador has promoted constitutional reform that will include the elimination of the independent energy regulators , which will fall back to the energy ministry, and the elimination of the antitrust watchdog. 'Made things worse' Panelists pointed out how during the current administration, the fuels market underwent a transformation that included the elimination of import and storage permits. \u201cSix years ago, a complete strategy was outlined to attend to the needs of the fuels and storage sector, but instead of implementing it or improving it, the current government ignored it and made things worse,\u201d Susana Cazorla, director of consultancy SICEnrgy & Madero, said Aug. 14. \u201cProduction continues to fall, imports are still on the rise, and we have no storage. The legal framework is weak and the refining system is in decay. The risks are high for Sheinbaum.\u201d Pemex production has stalled in recent years but is expected to increase by the end of 2024 as the new refinery in Dos Bocas, Tabasco, begins operation . During the pandemic, energy companies lost contact with regulators, and the window at government offices was shut for almost three years, which led to extra-official practices, providing fertile ground for corruption, Rocio Robles, director of consultancy LobbyingMexico, said Aug. 15. \"The government had a policy against some private investors, while others clearly benefited, when the main role of the government should be to promote investments in an even playing field,\" Robles said during the panel discussion. Robles served during the previous administration of President Enrique Pena Nieto and helped develop regulations for the fuels market. For some, the work of the government starts by deciding on a clear pathway. Cesar Cadena, CEO of Grupo Energ\u00e9ticos, one of Mexico's largest fuel distributors, said Aug. 14 during a panel discussion that it does not matter much what policy the government picks but its application. \u201cWhatever they choose, they should choose now,\" Cadena said. \"The country cannot remain in this uncertainty. One day they do something, the next day they do something different, and this is only bad for the country.\" Still some hope Despite the proposal to modify the constitution and eliminate the industry's independent regulators, some are confident that the new administration, given its more technical profile , will be more pragmatic and make decisions to solve the issues Pemex faces, such as its losses. \"I think Sheinbaum has the technical background to realize that what has been happening generates losses,\" Cazorla said Aug. 14. Diana Pineda, a partner at law firm Saenz Abogados, agreed that the new administration has the knowledge to make good decisions and added that Pemex could be part of the solution, as it could help anchor certain infrastructure projects, like storage terminals, like CFE did in previous administrations for constructing natural gas pipelines. Pemex already has land along with permits, Pineda said. \u201cThat would be one way it can be done, by sharing the risks,\u201d she said. Pemex's debt burden has kept increasing in recent years and has become normal, Cadena said, warning that \u201cthe money in the piggy bank is likely to end soon.\u201d There is hope that an energy minster who has a real background in numbers will realize it is unsustainable. If the government continues with the policy to save Pemex at any cost, the price will be enormous, Cadena said. \u201cIt will be like those big drinking parties,\" he said. \"When the barman comes with the bill, there will be no money on the table to pay it.\u201d ","headline":"Mexican fuels market in need of clear rules as new administration looms, observers warn","updatedDate":"2024-08-16T21:00:18.000"},{"Unnamed: 0":2,"body":" The US spot ethylene market reached price levels not seen since January and May 2022 in the week to Aug. 16, continuing its upward trend year to date. Platts assessed August spot Mont Belvieu ethylene at 33 cents\/lb Aug. 15. These levels were last seen on May 5, 2022, when it was assessed at 33.25 cents\/lb, according to Platts historical data. For spot Choctaw ethylene, the peak was reached Aug. 13 at 38 cents\/lb, the highest level since Jan. 25, 2022, when it was assessed at 40.50 cents\/lb. Platts is part of S&P Global Commodity Insights. The spread between Mont Belvieu and Choctaw reached a high of 7.75 cents\/lb at the end of July and has tightened since, with a current 5-cent\/lb difference between both locations. Sources said this has been in response to logistic issues between Texas and Louisiana, which have tightened supply conditions in the latter, which adds to ongoing supply issues. Nova Chemicals experienced an unplanned outage in its ethylene cracker in Geismar, Louisiana, a company representative confirmed July 25. The facility produces 1.95 billion pounds of ethylene annually, in addition to 114 million pounds of polymer-grade propylene and 13 million gallons of crude butadiene. Spot prices for both locations rose following supply and power disruptions from Hurricane Beryl. \u201cMarket was destabilized by fully integrated producers becoming buyers,\u201d a source said. Hurricane season is not over, and market participants have been on the look out to weather conditions that could impact production in the US Gulf Coast. Feedstock Enterprise ethane prices dropped significantly in the beginning of the month, being assessed at a four-year low at 11.375 cents\/lb Aug 3. This was in line with movements in natural gas prices and due to an oversupplied market because of ethylene outages. Commodity Insights analysts said that since the Ethane Cracker Margin has continuously risen -- reaching levels not seen in more than two years and last assessed at 29.91 cents\/lb Aug. 15 -- the US ethylene market is still at an advantage compared with Asia and Europe, despite spot prices being higher. The price increase is related to outages and supply issues, but there is still a regional feedstock advantage, they said. The market expectations are for prices to stabilize once the hurricane season is over, which could open arbitrage to other regions. However, downstream markets have been affected by this price hike. A PVC source said that rising ethylene prices are impacting producers' economics, highlighting that production costs are a significant factor. This is particularly relevant for the export PVC market, where upstream markets play a crucial role, the source said. ","headline":"Ethylene spot prices exceed two-year highs on tightened supply conditions","updatedDate":"2024-08-16T20:38:14.000"},{"Unnamed: 0":3,"body":" US refinery utilization rose to an average of 91.5% capacity for the week ended Aug. 9, according to most recent Energy Information Administration data, up from 90.5% capacity a week earlier. Rates in the Midwest averaged 86.2% capacity, but did not include the full restart of Joliet, completed Aug. 11. But US refiners, sensing weaker demand, have said they will run at lower rates in the third quarter than in Q2, collectively at about 90% capacity compared with the Q2 average of about 95%. \"We are actually guiding down right now because we see a softening in the market, and particularly on the coasts, both East and West,\" said Rich Harbison, the head of refining operations at Phillips 66 on the company's Q2 results call July 30. NORTH AMERICAN REFINERY OUTAGES 2024 ONGOING AND UPCOMING OUTAGES Q2-Q4 Owner Refinery Capacity (b\/d) Unit Name Unit (b\/d) Start End PADD I US ATLANTIC COAST Monroe Energy Trainer, PA 190,000 Unplanned shutdown and restart of FCCU 53,000 7\/15\/2024 7\/16\/2024 PBF Energy Paulsboro, NJ 160,000 Planned economic shutdown of smaller CDU 50,000 8\/1\/2024 N\/A PADD II BP Whiting, IN 435,000 Planned 1 CDU turnaround returned to September from July 255,000 9\/15\/2024 11\/15\/2024 Planned coker turnaround returned to September from July 9\/15\/2024 11\/15\/2024 Planned CDU turnaround moved up to July from September 255,000 7\/15\/2024 9\/15\/2024 Planned coker turnaround moved up to July from September N\/A 7\/17\/2024 9\/15\/2024 Cenovus Energy Toledo, OH 150,800 Unplanned FCCU work 55,000 7\/15\/2024 8\/1\/2024 Planned work CDU N\/A 9\/1\/2024 11\/1\/2024 Cenovus Energy Lima, OH 183,000 Unplanned CDU flaring and shutdown N\/A 7\/30\/2024 8\/4\/2024 Unplanned DHT flaring and shutdown 7\/30\/2024 8\/4\/2024 Large turnaround included coker reliability work N\/A 9\/1\/2024 N\/A Cenovus Energy Superior, WI 49,000 Crude rate to increase to near capacity 5\/1\/2024 7\/1\/2024 Restart of HF alkylation unit 1,700 4\/26\/2018 7\/1\/2024 Full start up by end of Q2 2024 4\/1\/2018 6\/30\/2024 Citgo Lemont, IL 182,685 Unplanned flaring due to unit upset\/loss of sulfur train 7\/8\/2024 N\/A CVR Wynnewood, OK 74,500 Plant damaged by storm-related fire N\/A 4\/28\/2024 6\/30\/2024 Planned alkylation expansion add 2,500 b\/d gasoline H1 2025 H1 2025 Diesel yield improvement project N\/A 2022 H12025 CVR Coffeyville, KS 132,000 Planned flaring due to planned CDU\/FCCU work 6\/28\/2024 N\/A Planned CDU turnaround Spring 2024 Spring 2024 Planned FCCU turnaround Spring 2024 Spring 2024 Planned alky and associated units turnaround Planned diesel improvement project (50%) 2025 2026 ExxonMobil Joliet, IL 251,800 Power restored, damage assessment , coker damage seen N\/A 7\/24\/2024 8\/12\/2024 Unplanned plant shutdown due to tornado-power outage N\/A 7\/15\/2024 7\/24\/2024 HF Sinclair El Dorado, KS 162,000 Planned 55-day turnaround on FCCU 44,000 9\/1\/2024 10\/26\/2024 Planned 55-day turnaround on alkylation unit 5,000 9\/1\/2024 10\/26\/2024 Planned 55-day turnararound on gasoil hydrotreater 54,000 9\/1\/2024 10\/26\/2024 Unplanned flaring from SRU leak, possible reformer outage N\/A 6\/5\/2024 6\/21\/2024 Tulsa, OK 85,000 Unplanned coker tower damage due to high winds 7\/6\/2024 N\/A Marathon Robinson, IL 253,000 Plant evacuation, SRU upset hydrogen sulfide release 253,000 6\/6\/2024 N\/A Valero Memphis, TN 180,000 Planned work on CDU 80,000 4\/17\/2024 5\/10\/2024 Planned work on reformer 36,000 4\/17\/2024 5\/10\/2024 Valero Ardmore, OK 86,000 Tornado-related power outage N\/A 5\/1\/2024 N\/A WRB Refining Wood River, IL 356,000 Unplanned flaring after process unit upset N\/A 7\/4\/2024 N\/A Unplanned flaring after process unit upset N\/A 6\/23\/2024 N\/A Unplanned flaring after process unit upset N\/A 6\/19\/2024 N\/A Unplanned flaring after process unit upset N\/A 6\/1\/2024 N\/A PADD III Citgo Corpus Christi, TX 167,500 Unplanned flaring after coker compressor trip N\/A 7\/26\/2024 7\/26\/2024 Unplanned rate cuts ahead of Hurricane Beryl 7\/6\/2024 7\/8\/2024 Planned flaring from SRU incinerator on unit startup 6\/23\/2024 6\/24\/2024 Unplanned flaring from crude unit due to controller snag 6\/19\/2024 6\/19\/2024 Citgo Lake Charles, LA 455,000 Restarted VDU shut since 2020 Q2 2024 Q2 2024 Restarted coker shut since 2020 Q2 2024 Q2 2024 Chevron Pasadena, TX 112,229 Unplanned rate cut at FCCU after leak 8\/10\/2024 N\/A Unplanned reformer outage 23,000 5\/11\/2024 N\/A Crude, jet expansion 125,000 Q42022 2024 Pascagoula, MS 356,440 Unplanned flaring while bringing system online 7\/12\/2024 N\/A Unplanned flaring during unit start up 6\/25\/2024 N\/A Delek US Krotz Springs, LA 80,000 Major turnaround planned, upgrade CDU, FCCU Q4 2024 Q4 2024 Big Spring, TX 73,000 Unplanned crude charge cut after compressor trip 7\/3\/2024 7\/4\/2024 5,000 b\/d CDU increase on reliability fixes Spring 2024 Spring 2024 Tyler, TX 75,000 Unplanned flaring due to weather event 7\/7\/2924 N\/A Planned flaring with start up of ESP 6\/26\/2024 N\/A ExxonMobil Baytown, TX 564,440 Flaring due to operational issues 7\/8\/2024 7\/9\/2024 Operations stable in Beryl's aftermath 7\/8\/2024 7\/9\/2024 Unplanned flaring due to hydrofining 10 unit 6\/17\/2024 6\/17\/2024 Minimal op impact from CDU leaky valve 6\/9\/2024 6\/9\/2024 ExxonMobil Beaumont, TX 609,024 Flaring due to operational issues 7\/31\/2024 8\/7\/2024 Planned flaring due to operational issues 7\/17\/2024 7\/19\/2024 Unplanned flaring due to hydrofiner shutdown 6\/17\/2024 6\/17\/2024 Flint Hills Corpus Christi, TX 343,000 Unplanned West plant FCCU flaring 6\/24\/2024 N\/A Unplanned East plant flaring TS Alberto boiler outage 6\/19\/2024 6\/20\/2024 LyondellBasell Houston, TX 263,776 Ramp down to permanent plant closure Q1 2025 Q1 2025 Unplanned flaring from unidentified process unit 7\/16\/2024 7\/16\/2024 Unplanned flaring from Unit 732 upset reduced rates 7\/3\/2024 N\/A Marathon Galveston Bay, TX 631,000 Unplanned flaring from FCCU 3 8\/1\/2024 N\/A Unplanned flaring from plant after Beryl power outage 7\/6\/2024 7\/27\/2024 Unplanned flaring from FCCU3 equipment upset 6\/20\/2024 6\/20\/2024 Unplanned flaring from hydrocracker 6\/12\/2024 6\/13\/2024 Unplanned flaring from RHU (resid hydrocracker) due to pump trip 17,000 6\/4\/2024 N\/A Marathon El Paso, TX 133,000 Unplanned shutdown of FCCU 35,000 6\/3\/2024 N\/A Motiva Port Arthur, TX 626,000 Unplanned shutdown and start-up of FCCU 3 N\/A 7\/24\/2024 8\/7\/2028 Unplanned flaring from alky, CDU4, FCCU 3 stacks N\/A 7\/24\/2024 N\/A Flaring from unspecified operations N\/A 6\/9\/2024 6\/13\/2024 Pemex Deer Park, TX 312,500 Flaring from unspecified work activities 6\/12\/2024 6\/17\/2024 Flaring from hydrocracker 6\/12\/2024 N\/A PBF Chalmette, LA 190,000 Planned FCCU 40 to 50 days 75,600 10\/1\/2024 11\/20\/2024 Planned alkyation 40 to 50 days 16,800 10\/1\/2024 11\/20\/2024 Phillips 66 Sweeny, TX 265,000 Unplanned flaring from coker flare N\/A 8\/14\/2024 N\/A Unplanned flaring from Unit 29.1 FCCU coker N\/A 8\/9\/2024 N\/A Unplanned flaring from Unit 27.1 FCCU regenerator N\/A 7\/9\/2024 N\/A Unplanned flaring from coking unit N\/A 7\/9\/2024 N\/A Unplanned flaring from unit upset due to Beryl N\/A 7\/8\/2024 N\/A TotalEnergies Port Arthur, TX 238,000 Unplanned flaring from unidentified process unit upset 8\/10\/2024 N\/A Unplanned flaring coker heating unit cogen shutdown 7\/19\/2024 7\/19\/2024 Unplanned flaring from plant power outage 7\/13\/2024 7\/13\/2024 Unplanned flaring after leak shut crude unit 2 6\/27\/2024 6\/27\/2024 Valero Corpus Christi, TX 290,000 East plant catalytic reformer shut 3\/5\/2024 3\/14\/2024 Unplanned West Plant flaring due to power outage 3\/5\/2024 N\/A Unplanned flaring due to Complex 7 process conditions N\/A 2\/9\/2024 2\/9\/2024 Unplanned maintenance on reformer N\/A 2\/3\/2024 N\/A WS Heather freeze impact-reformer N\/A 1\/14\/2024 1\/14\/2024 Unplanned work on VDU 91,000 1\/2\/2024 N\/A Unplanned work on hydrocracker N\/A 3\/3\/2023 N\/A Valero Port Arthur, TX 335,000 Restart of multiple units after power outage N\/A 7\/11\/2024 N\/A Unplanned power outage shuts multiple units N\/A 7\/6\/2024 7\/11\/2024 Unplanned SRU process unit upset N\/A 6\/12\/2024 N\/A Unplanned work on coker N\/A 5\/11\/2024 N\/A Houston, TX 205,000 Flaring from maintenance activities N\/A 6\/9\/2024 6\/10\/2024 WS Heather freeze impact-flaring from offline units N\/A 1\/15\/2024 1\/18\/2024 McKee, TX 195,000 Planned work on CDU N\/A 7\/17\/2024 8\/30\/2024 Planned work on FCCU 7\/17\/2024 8\/30\/2024 Planned flaring from sulfuric acid plant start up N\/A 6\/24\/2024 6\/24\/2024 Unplanned flaring from SRU on process unit upset 6\/21\/2024 6\/22\/2024 Start up of FCCU 56,000 5\/15\/2024 5\/28\/2024 Unplanned flaring from main flare N\/A 3\/21\/2024 3\/22\/2024 Unplanned flaring from FCCU outage N\/A 2\/20\/2024 N\/A Unplanned flaring from HCU outage N\/A 2\/20\/2024 WS Heather freeze impact-frozen equipment N\/A 1\/13\/2024 1\/17\/2024 Planned multiunit turnaround 7\/15\/2024 8\/24\/2024 St. Charles, LA 215,000 Planned work on coker 86,000 1\/24\/2024 3\/4\/2024 Planned work on VDU 180,000 2\/7\/2024 3\/18\/2024 Planned work HCU 28,000 2\/7\/2024 3\/18\/2024 Texas City, TX 205,000 Unplanned flaring from Beryl-related power blip N\/A 7\/6\/2024 N\/A Restart HCU, SRU, VDU, reformer N\/A 1\/16\/2024 2\/20\/2024 WS Heather freeze impact-frozen equipment N\/A 1\/16\/2024 1\/17\/2024 Three Rivers, TX 89,000 WS Heather freeze impact-SRU N\/A 1\/16\/2024 1\/16\/2024 Vertex Energy Mobile, AL 80,000 Planned 100% hydrocracker oil processing 9\/30\/2024 12\/31\/2024 Planned hydrocracker conversion back to oil 7\/1\/2024 9\/30\/2024 Planned reformer catalyst change, #1 CDU work 61,500 3\/1\/2024 3\/30\/2024 Planned replacement of electrical transformer 67,000 1\/1\/2024 1\/31\/2024 WRB Refining Borger, TX 149,000 Unplanned reduced SRU rates N\/A 8\/10\/2024 N\/A Planned flaring from FCCU 29 ESP work N\/A 7\/26\/2024 7\/27\/2024 Unplanned flaring from FCCU 29 , FCCU 47 N\/A 7\/23\/2024 N\/A Planned from Unit 40 FCCU ESP work 6\/24\/2024 6\/27\/2024 Unplanned flaring from FCCU 29 flare N\/A 6\/17\/2024 N\/A Unplanned flaring from FCCU, 4 refinery flares N\/A 6\/3\/2024 6\/6\/2024 Unplanned flaring from Unit 29 FCCU, Unit 34 SRU and other units N\/A 5\/8\/2024 N\/A Unplanned flaring from Unit 29FCCU N\/A 4\/18\/2024 N\/A Unplanned flaring from Unit 29 FCCU, GOHDS N\/A 4\/9\/2024 N\/A PADD IV Chevron Salt Lake City, UT 54,720 VDU shutdown 3\/25\/2024 N\/A FCCU shutdown 3\/25\/2024 N\/A FCCU shutdown 3\/16\/2024 N\/A CHS Laurel, MT 62,500 WS Indigo freeze impact-flaring N\/A 1\/18\/2024 1\/22\/2024 HF Sinclair Parco Sinclair, WY 75,000 Planned 40 day turnaround on hydrocracker 16,000 Q2 2024 Q2 2024 Planned 40 day turnaround on reformer 13,000 Planned 40 day turnaround on RD unit 10,000 Planned 40 day turnaround on coker 20,000 Q3 2024 Q3 2024 Planned 40 day turnaround on DHT 18,500 WS Indigo freeze impact-flare went out N\/A 1\/12\/2024 N\/A HF Sinclair Woods Cross Woods Cross, UT 39,330 Unplanned flaring after unit upset N\/A 5\/14\/2024 N\/A Crude unit shut and restarted N\/A 3\/21\/2024 3\/25\/2023 Naphtha hydrotreater restarted 12,500 3\/9\/2024 3\/19\/2024 Gasoil hydrotreater restarted 15,000 3\/9\/2024 3\/22\/2024 Par Pacific Billings, MT 61,500 Planned coker work Q3 2024 Q3 2024 Planned CDU, hydrotreaters, reformer outage 4\/1\/2024 5\/7\/2024 Phillips 66 Billings, MT 66,000 Unplanned coker outage 2\/12\/2024 2\/23\/2024 Fire in coker fines pit 2\/9\/2023 2\/12\/2024 Suncor Commerce City, CO 103,000 Unplanned reformer outage 3\/13\/2024 N\/A West plant DHT outage 3\/5\/2024 3\/15\/2024 36,000 East plant CDU outage 3\/4\/2024 N\/A 8,500 East plant VDU outage 3\/4\/2024 N\/A PADD V BP Cherry Point Ferndale, WA 238,500 Planned shutdown of hydrogen plant 4\/16\/2024 N\/A Chevron El Segundo, CA 269,000 Unplanned flaring after short FCCU turnaround N\/A 8\/15\/2024 N\/A Planned start up of unspecified units N\/A 5\/19\/2024 5\/20\/2024 Chevron Richmond, CA 245,271 Unplanned flaring N\/A 5\/27\/2024 N\/A HF Sinclair Anacortes, WA 145,000 Planned FCCU turnaround 38,000 2\/26\/2024 4\/15\/2024 Planned alkylation turnaround 12,500 2\/26\/2024 4\/15\/2024 Planned coker turnaround 23,500 2\/26\/2024 4\/15\/2024 WS Indigo freeze impact-frozen equipment N\/A 1\/12\/2024 1\/17\/2024 Marathon Anacortes, WA 119,000 WS Indigo unit shutdown after process unit upset N\/A 1\/13\/2024 N\/A Marathon Carson, CA 363,000 Planned flaring due to possible FCCU work N\/A 8\/14\/2024 8\/28\/2024 Unplanned flaring N\/A 8\/8\/2024 8\/9\/2024 Reliability and emissions regulations upgrades N\/A 1\/30\/2024 Q4 2025 Planned flaring on gasoline units work N\/A 10\/6\/2023 4\/1\/2024 Start-up of unspecified units N\/A 1\/24\/2024 1\/30\/2024 Power outage at legacy Wilmington plant N\/A 1\/21\/2024 N\/A Par Pacific Tacoma, WA 40,700 Planned 15-day outage for heater repair 31,000 3\/5\/2024 4\/15\/2024 Kapolei, HI 93,500 Planned turnaround and SAF plant startup N\/A 2025 2025 PBF Torrance, CA 160,000 Unplanned flaring due electrical malfunction N\/A 7\/25\/2024 N\/A Planned maintenance N\/A 6\/8\/2024 6\/14\/2024 Fire in three outer buildings, says no refinery impact N\/A 6\/1\/2024 N\/A Unplanned emergency flaring N\/A 5\/30\/2024 N\/A Possible HFC release N\/A 5\/10\/2024S N\/A PBF Martinez, CA 158,400 Unplanned flaring due to process unit trip N\/A 6\/6\/2024 N\/A Planned work on hydrocracker and associated units N\/A 5\/2\/2024 6\/30\/2024 Planned hydrocracker work 42,900 10\/15\/2024 11\/15\/2024 Phillips 66 Wilmington, CA 139,000 Unplanned flaring from unidentified unit(s) 8\/16\/2024 N\/A Unplanned flaring from unidentified unit(s) 5\/24\/2024 N\/A Unplanned flaring from two stacks\/refinery operating 5\/10\/2024 N\/A Valero Wilmington, CA 85,000 Unplanned emergency flaring from unit upset 6\/4\/2024 N\/A Unplanned emergency flaring from unit upset 5\/25\/2024 N\/A CANADA Cenovus Lloydminster, AB 110,000 Upgrade\/debottleneck add 3,000 b\/d 5\/6\/2024 6\/30\/2024 25,000 Upgrader diesel expansion project Q2 2024 Q2 2024 Imperial Oil Sarnia, ON 121,000 Planned turnaround 4\/6\/20254 5\/1\/2024 Imperial Oil Strathcona, AB 200,000 Planned turnaround (5,000 b\/d annual impact) 4\/15\/2024 5\/15\/2025 Coprocessing of vegetable feedstocks 2024 7\/16\/1905 Planned turnaround (2,000 b\/d annual impact) Q4 2024 Q4 2024 Renewable diesel project 20,000 N\/A Q1 2025 Imperial Oil Nanticoke, ON 112,000 Planned turnaround (12,000 b\/d annual impact) Q3 2024 Q3 2024 Imperial Oil Fort McMurray, AB 350,000 Planned Syncrude coker (25% stake) 182,500 3\/29\/2024 5\/15\/2024 Imperial Oil Fort McMurray, AB N\/A Planned Syncrude hydrocracker (25% stake) N\/A Q3 2024 Q4 2024 Irving Oil Saint John, NB 320,000 Unplanned work on two alkylation units 6\/15\/2024 N\/A Planned spring turnaround on 1 FCCU 4\/17\/2024 5\/19\/2024 Planned spring turnaround on Resid FCCU 4\/17\/2024 5\/19\/2024 Sulfur plant offline 4\/17\/2024 N\/A Planned larger fall turnaround Q4 2024 Q4 2024 Parkland Burnaby, BC 55,000 Planned maintenance 2025 2025 Valero Quebec City, QC 235,000 Unspecified planned work Q3 2024 Q3 2024 Source: Compiled from regulatory filings, company statements, and market sources ","headline":" ExxonMobil restarts Joliet plant, Midwest flows return to normal","updatedDate":"2024-08-16T20:04:38.000"},{"Unnamed: 0":4,"body":" The EU has pushed ahead with plans to impose antidumping duties of up to 36.4% on Chinese biodiesel imports, it said Aug. 16, after finding that European producers had struggled to breakeven in 2024 due to an influx of supply. Effective from Aug. 16, provisional measures will impose a 36.4% duty on biodiesel and hydrotreated vegetable oil from Chinese producers, while 40 companies that cooperated with the investigation will benefit from a lower 23.7% duty. Two other Chinese producers -- EcoCeres Group and Zhuoyue Group -- were also granted discounted duties of 12.8% and 25.4%, respectively, the EC said in a statement. The provisional duties are expected to be replaced with definitive measures Feb. 2025, while sustainable aviation fuel was exempted from existing tariffs. Citing data from the European Biodiesel Board, the EC reported that import volumes of biodiesel and HVO to the EU from China almost doubled from around 495,000 metric tons in 2022 to 973,000 t in 2022, before jumping close to 1.5 million in the investigation period starting December 2023. The surge in imports was unmatched by moderate consumption growth within the EU over the same period, the European Commission said, showing that total consumption within the union grew from around 17.6 million t to 18.1 between 2021 and 2022. Consequently, China\u2019s market share increased from 5.4% in 2022 to 8% during the 2024 investigation period, while the EU\u2019s domestic industry ceded some 10% of its market share. The erosion in market share was driven by discounts of around 5%-14% for Chinese biodiesel, the EC found, putting pressure on European margins to the extent that producers were struggling to cover operating costs. While Europe's largest player Neste incurred its steepest profit losses in over a decade and other large producers have scaled back investments, Chinese producers have been kept afloat by generous tax rebates, cheaper wages and other factors, the EC found. The EC dismissed criticisms that the tariffs would hamper the EU\u2019s progress in meeting its renewable energy goals for the transport segment for 2030, claiming that producers within the Union have sufficient capacity to service future demand. European investment challenge New measures mark the latest attempt by the EU to protect its domestic biofuels industry as a challenged market environment has caused several prominent producers to scale back on ambitious projects in the sector. In July, Chevron, Shell and BP all halted plans for standalone bio-refining units in Europe. Industry group European Waste-Based & Advanced Biofuels Association praised the new measures as a remedy to \"extremely adverse\" market conditions since late 2022, yet warned that exemptions for specific producers and SAF could continue to hamper European producers. \"[The new measures are] a missed opportunity to close the SAF loophole and increase extremely low individual duties for certain producers,\" EWABA Secretary-General Angel Alvarez Alberdi said Aug. 16. \"We hope these will be addressed by the time the Commission imposes definitive early next year.\" While European stakeholders hope that the measures will add much-needed stimulus and investment certainty to producers within the Union, Chinese suppliers have been forced to consider alternative outlets. In July, traders noted that export activity had already dovetailed, pointing to a vacuum left by European buyers that had previously accounted to up to 90% of offtake for many suppliers. Transport and Environment, a lobby group, also applauded the proposed duties when they were first proposed in June, but called for stronger certification measures for Chinese biofuel feedstocks, such as used cooking oil, which remain crucial to the operations of many European biodiesel producers and have made the green credentials of supply chains notoriously difficult to verify. \"Restrictions on imports from China are a step in the right direction, however, anti-dumping tariffs alone won\u2019t be enough to tackle UCO fraud. Without a complete overhaul of the certification process, the EU will continue to play out a game of whack-a-mole as fraudsters from other countries will simply fill the gap,\" said Cian Delaney, biofuels campaigner at T&E. Platts, part of S&P Global Commodity Insights, assessed the renewable diesel that complies with the EU's Renewable Energy Directive at a $1,535\/mt Aug. 16, down 1.32% on the day and 3.2% from when provisional anti-dumping measures were first announced. ","headline":"EU imposes anti-dumping duties targeting cheap Chinese biodiesel imports","updatedDate":"2024-08-16T19:51:15.000"},{"Unnamed: 0":5,"body":" Crude oil futures settled lower Aug. 16 against a backdrop of weaker outlooks in China demand and signs of progress in ceasfire talks between Israel and Hamas. NYMEX September WTI settled down $1.51 at $76.65\/b and ICE October Brent slid $1.36 to $79.68\/b. China's industrial production rose just 5.1% in July from the previous year, slowing from a 5.3% increase in June and missing the forecast of 5.2% growth. That has offered little support to investor confidence in the country's economic recovery, with expectations of weaker domestic demand in China hurting the outlook for refineries in Asia struggling with tight margins. The International Energy Agency said this week that the world is seeing a major deceleration in oil demand growth led by China, with inventories set to rise next year even if OPEC+ were to postpone its plans to ease output cuts. \"New demand concerns are weighing on the market,\" Commerzbank analysts said. \"OPEC and the International Energy Agency have revised their forecast for global oil demand slightly downward.\" Expectations of weaker domestic demand in China further compounds the outlook for refineries in Asia, which are already struggling against tight margins. \"What we are closely watching out for is that China's struggling construction and property sector could lead to a high volume of gasoil exports [due to weaker domestic sales]... an oversupply would extend the current lengthy downtrend in Asian benchmark crack spreads,\" said a middle distillate marketing manager at a major South Korean refiner. Chinese refineries' crude throughputs continued on a downtrend in July, falling 2% from June to a 21-month low of 13.96 million b\/d (59.06 million metric tons), data from the National Bureau of Statistics showed Aug. 15. NYMEX September RBOB declined 4.78 cents to $2.3102\/gal and September ULSD declined 4.92 cents to $2.3287\/gal. Meanwhile, no further escalation in violence in the Middle East through the week ended Aug. 16 has calmed some investors. \"The feared retaliatory strike by Iran has so far failed to materialize, which has probably favored a partial pricing out of the risk premium,\" Commerzbank analysts said. US Secretary of State Anthony Blinken will travel to Israel Aug. 17 to push for a new ceasefire agreement supported by the US, Egypt, and Qatar, the US State Department said Aug. 16. \u201cOur statistical analysis of energy supply risks also suggest that supply risk premia is seeping out of energy markets once again, suggesting traders are curiously disregarding the risk of geopolitical aggressions ahead of the weekend,\u201d TD Securities Senior Commodity Strategist Daniel Ghali said. ","headline":" Crude slides as market eyes weaker China demand, progress on Gaza war ceasefire","updatedDate":"2024-08-16T19:47:31.000"},{"Unnamed: 0":6,"body":" Only four parcels were offered at the US Bureau of Land Management federal oil and natural gas lease sale in south Texas, but all received high seven- to eight-figure bids, with a combined high-dollar total figure of $61 million, bidding platform Energynet.com data showed. The Aug. 15 auction featured two parcels in each of Live Oak and McMullen counties, with tract sizes ranging from 1,269 acres to 2,518 acres, according to Energynet data. Ten bidders placed a total 207 bids across a combined 6,8712 acres, according to Energynet. Highest winning bid in the sale was $22.7 million for a 1,720-acre parcel in McMullen County, while the lowest winning bid was $8.3 million for a 1,259 acre parcel in Live Oak County. Opening bids started at just $10\/acre, but the location, big tract sizes and geology of the acreage appeared responsible for pushing up that amount astronomically -- and in the cases of winners, by multiples of one or two million. Texas BLM oil, gas sale results: Parcel number County location (Texas) Bid\/acre Bonus bid TX-2024-08-0010 Live Oak $6,548 $8.315 million TX-2024-08-0018 Live Oak $6,403 $9.38 million TX-2024-08-0009 McMullen $9,001 $22.673 million TX-2024-08-0011 McMullen $12,001 $20.641 million Total sum of high bids: $61 million Source: Energynet.com Acreage spans two Eagle Ford Shale counties Both counties are sited in the Eagle Ford Shale, a play that currently has about 1.04 million b\/d of oil production and about 5.7 Bcf\/d of gas output, according to S&P Global Commodity Insights data. In addition, 52 rigs were running across the play for the week ended Aug. 7, Commodity Insights data shows. It is not clear whether the participants were chasing oil or gas, or which subsurface interval they planned to target, since there are many \"stacked\" or discrete subsurface geological layers that exploration and production producers can drill into in the basin. Some of those formations include the Eagle Ford, the Austin Chalk and the Anacacho. However, one factor that may have hiked the value and therefore the relatively large amounts bid, is the relative scarcity of prime Eagle Ford acreage, geologists say. In addition, E&P operators have optimized their completion techniques in the South Texas play, as is also true in other US onshore unconventional basins, and have become effective at lowering costs while raising the amount of oil and gas per well. Since it is a well-known play for producers, repeating their success formulas may be appealing to them, experts say. ","headline":"Four parcels offered in Texas BLM federal oil, gas sale capture $61 million total in high bids","updatedDate":"2024-08-16T19:35:17.000"},{"Unnamed: 0":7,"body":" A pipeline disruption between Libya's Waha oilfields and Es Sider, a key export terminal, has been resolved, according to trade sources, after a fire Aug. 13 triggered production cuts. \"The maintenance was completed last night and the pipeline was replaced and is ready,\" said one oil trader, while a second source confirmed that fears of loading delays from Es Sider had eased as operations continue as normal. A fire that broke out on the Gazout \"Zaqout\"- Es Sider pipeline around 30 km from the port had affected crude flows for several days, with traders reporting that flows through the supply link had been reduced by around 100,000 b\/d. Waha oil, which operates the impacted oilfields in a joint venture with TotalEnergies and ConocoPhillips and NOC, declined to comment on the volume of production cuts. In a statement Aug. 14 on X, Libya's National Oil Corp. confirmed it was seeking ensure that production was restored to previous levels, without confirming losses owing to the bottleneck. The larger of Waha oil's two pipeline links acts as key outlet for crude oil from its four main oilfields in the Sirte Basin, which accounts for around a third of exports from Es Sider, according to S&P Global Commodity Insights analysts. According to S&P Global Commodities at Sea data, the Es Sider terminal exports around 300,000 barrels of crude per day, providing a key source of sweet crude oil to refiners in the Mediterranean. Despite news of supply shut-ins on the week, Mediterranean crude markets maintained a sense of calm as loadings from Es Sider continued largely uninterrupted. According to CAS data, the BP-chartered T.Kurusceme loaded 600,000 barrels of crude from the port Aug. 15 as planned, while two further vessels, Aegean Harmony and Sea Panther, are both expected to face minimal disruption to scheduled loadings in the coming days, shipping sources said. Oil traders said that buyers continued to take Libyan grades despite the disruption, while Es Sider FOB Libya prices only climbed slightly from a discount of 35 cents\/b to Dated Brent Aug. 13 to a discount of 25 cents by Aug. 15, according to assessments by Platts, part of Commodity Insights. Expectations of a swift maintenance turnaround and ample availability of rival sweet crude grades in the Mediterranean mitigated the impact of price rises on the week, traders said. For Libya, Es Sider crude has taken on growing prominence since its 300,000 b\/d Sharara oil field was shut down Aug. 5, causing the NOC to declare force majeure Aug. 7. El Sharara crude is Libya's third-largest export grade, behind Es Sider and Sarir supplies, according to CAS data. The country is aiming to restore its oil output to 1.6 million b\/d after a rare period of stability after years of disruption to its oil production, and in June pumped 1.16 million b\/d, according to the latest Platts OPEC Survey from Commodity Insights. ","headline":"Crude flows to Libya's Es Sider restored after pipeline fire","updatedDate":"2024-08-16T17:31:15.000"},{"Unnamed: 0":8,"body":" Finnish ferry operator Viking Line is seeking to achieve deep decarbonization by introducing biofuels, including liquefied biogas, into its bunker mix, the company said Aug. 16, announcing it will run ferries out of Turku only on biogas for a week. In a company statement, Viking Line suggested \u201cgreen\u201d fuels derived from biofeedstocks have been utilized more by its ships on the Turku-Mariehamn, Turku-\u00c5land-Stockholm, Helsinki-Tallinn and L\u00e5ngn\u00e4s-Stockholm routes, without providing detailed figures. The company has been operated the Viking Glory and Viking Grace ships from Turku on LNG, which can reduce CO2 emissions by 20%-30% compared with conventional, oil-based fuels. From Aug. 29 to Sept. 4, the two ships will only be using waste-based liquefied biogas supplied by Gasum to further reduce CO2 emissions by up to 90%, equivalent to a cut of 2,600 metric tons of greenhouse gas emissions, according to Viking Line. \u201cFor the first time, we are operating for a whole week using only biogas, which is unique,\u201d Dani Lindberg, sustainability manager at Viking Line, said. \u201cThere is still limited access to renewable fuels, and the price for such fuels is at least twice as high compared to LNG. It is important to create demand in order for supply to rise and the price to fall.\u201d The monthly average delivered bunker price for LNG was $14.81\/Gigajoule in Rotterdam for ships in intra-EU trades last month, already lower than $16.13\/Gj for 0.5%-sulfur marine fuel oil, according to Platts data from S&P Global Commodity Insights. However, liquefied biogas costs much more due to its scarcity. Having identified the lack of \u201calternative fuels at realistic prices\u201d as \u201cthe greatest challenge for the industry,\u201d Viking Line has offered its customers an option to purchase biofuels to be used for their ships in proportion to their travel over the past year. \u201cThe number of trips using biofuel increased 500% immediately when we highlighted the option earlier in our booking system,\u201d Lindberg said. ","headline":"Finnish Viking Line shifts to biofuels, to run ferries on biogas from Turku","updatedDate":"2024-08-16T16:40:58.000"},{"Unnamed: 0":9,"body":" Jet fuel and kerosene inventories in the Amsterdam-Rotterdam-Antwerp refining hub rose 29,000 metric tons to 911,000 metric tons in the week to Aug. 15, following two consecutive weeks of draws, data from market research company Insights Global showed. The stocks were 27.6% higher than the year-ago week. The stocks have risen as refineries prioritize jet fuel over diesel in Europe and around the globe, said a Europe-based trade source. \u201cAs diesel remains weak, refineries have maximized jet fuel locally and globally, and Europe is a high price center, so all the Far East and AG [Arabian Gulf] oil flows are now coming into Europe,\u201d he said. Jet fuel inflows from the East of Suez into Europe are expected to rise 100,000 metric tons on the month to 1.8 million metric tons in August, according to S&P Global Commodities at Sea shipping data from Aug. 16. \u201cWeakness is being seen in the US too, and they\u2019ve got too much oil, so they are sending barrels over to Europe. The Far East is also exporting more than what Europe requires,\u201d the trade source said. US jet fuel output dipped to a nearly three-month low in the week ended Aug. 9, according to Energy Information Administration data Aug. 14, but inventories grew over the same period amid a drop in domestic air travel demand. US stocks rose from a monthly low, by 141,000 barrels to 46.241 million barrels in the week ended Aug. 9. US Gulf Coast and West Coast inventories, meanwhile, gained 592,000 barrels to 14.258 million barrels and 613,000 barrels to 11.820 million barrels, respectively. \"ARA tanks have been nearly empty, and that\u2019s normal in this peak season,\u201d said the trade source. The weekly rise is \"just a wave\" as cargoes come in, and there will be more of a build in early September as the summer flying season comes to an end. ","headline":"ARA jet fuel, kerosene stocks rise 29,000 metric tons on week","updatedDate":"2024-08-16T15:21:26.000"},{"Unnamed: 0":10,"body":" Marine fuel supplier Peninsula has expanded its physical supply operations in the North Sea and English Channel, according to a Peninsula news release Aug. 16, which was expected to improve the company's footprint in Northwest Europe. Peninsula announced that it will expand its physical supply network to improve coverage in the Amsterdam-Rotterdam-Antwerp region, along with Skaw and Copenhagen. Two tankers were set to be deployed to this end, and the firm has also increased its trading and operating team accordingly, according to the news release. The firm was set up in 1996 in Gibraltar and has since evolved to have facilitated over 22,000 total deals. Bunker market conditions in the ARA region have recently been weak and described as \u201cvery quiet,\u201d according to various traders and regional suppliers active in the area. A quiet August, in terms of market activity, was attributed to the European holiday season, which meant that many market participants were off on vacation. Platts, part of S&P Global Commodity Insights, assessed the value of delivered Rotterdam HSFO at $470 per metric ton Aug. 15, up 3.52% on the day. Meanwhile the VLSFO equivalent was assessed at $555\/t, up 1.09% on the day. ","headline":"Peninsula expands operations in the English Channel, North Sea","updatedDate":"2024-08-16T14:45:29.000"},{"Unnamed: 0":11,"body":" Freight for ships carrying LPG on the Persian Gulf-Japan route jumped 17.4% on the day to a one-month high of $54 per metric ton, according to Platts assessments from S&P Global Commodity Insights, driven by increased trading activity along the US Gulf Coast-Japan\/East route. That also boosted rates on the Persian Gulf-Japan\/East LPG shipping routes, industry sources said, with rates expected to head higher in the near term. Several shipping sources said the US Department of Treasury's overnight announcement of a fresh round of sanctions on companies, ships and one individual involved in trading Iranian oil and LPG had little effect on the freight rates. \"Activity has picked up, hearing around nine ships were fixed ex-USGC yesterday (Aug. 15),\" a shipping broker based in Asia said. \"I doubt this (US sanctions) would have affected US liftings.\" The broker expects Persian Gulf-East\/Japan shipping rates for LPG to trade in the $55-$57\/t range in the near term. The US sanctions come after multiple attacks Aug. 13 on a Liberian-flagged oil tanker in the Red Sea that were confirmed by the Joint Maritime Information Center. Regional tensions stemming from the Israel-Hamas war continue to threaten oil supply routes. \"The jump [in freight] is mainly because the US market is improving, lots of vessels [are] being booked. Hence, [there are] fewer vessels available in the [Middle East] region,\" another shipping broker based in the West said. With shipping fixtures from the Middle East ramping up in preparation for September deliveries to India and the East, shipowners can \"ask for higher rates because of lesser competition,\" the broker said. Platts assessed Persian Gulf-Japan freight at a six-month low of $40.50\/t on Aug. 8 as spot trading activity in the Middle East slowed, resulting in the number of available and idle gas carriers to rise substantially. However, rates have been rebounding since Aug. 12, coinciding with stronger spot trading activity and term deliveries. About nine to 10 ships were fixed on the US Gulf Coast to the East route overnight, propelling Platts-assessed VLGC rates from the US Gulf Coast to Chiba, Japan higher. ","headline":"Persian Gulf-Japan LPG freight jumps 17.4% on day due to stronger USGC-East activity","updatedDate":"2024-08-16T13:08:43.000"},{"Unnamed: 0":12,"body":" Russia's Omsk refinery was due to restart a CDU unit affected by fire around Aug.19, according to market sources Aug. 16. The unit was previously expected to restart towards the end of August. The refinery reported fire at a pumping station Aug. 1, adding that operations continued normally. However, according to market sources and media reports, the fire affected an 8.6 million metric tons crude and vacuum distillation complex AVT-10. Processing however has not been affected significantly as a reserve unit ahs been brought in operation for the duration of the outage. Platts, part of S&P Global Commodity Insights, assessed Urals CIF Rotterdam at $73.285\/b on Aug. 15. Separately, Omsk will carry out maintenance on its aromatics complex in September which is expected to affect its gasoline production. ","headline":" Russia's Omsk on track to restart CDU, plans partial works","updatedDate":"2024-08-16T13:08:14.000"},{"Unnamed: 0":13,"body":" Fuel oil stocks in the Amsterdam-Rotterdam-Antwerp refining hub slipped 0.3% in the week to Aug. 15 to 1.358 million metric tons, representing the fourth consecutive weekly decline, Insights Global data showed. Fuel oil\u2019s share of overall oil product inventories in the ARA region was 23%. Insights Global does not differentiate by type of fuel oil. The Northwest European high sulfur fuel oil complex has seen an uptick in demand following expectations of reduced supplies from the Americas, with the US-Europe arbitrage status considered closed. Middle Eastern utility demand for HSFO in the Mediterranean has persisted for cooling purposes as the region experiences higher temperatures. However, bunkering demand is said to have slowed in the East Mediterranean with the transit risk premium of travelling via the Red Sea deterring vessels from setting voyage through the Suez Canal. Platts, part of S&P Global Commodity Insights, assessed the HSFO paper front-month to second-month spread at a backwardation of $10\/mt on Aug. 15, compared with a backwardation of $7.75\/mt on Aug. 8. In the very low sulfur fuel oil market, traders said bunkering demand continues to improve into the second half of the year, with an open Europe-Asia arbitrage acting as a major source of consumption for the region. \"Major players working the arbitrage,\" a trader said. A second trade source said they are seeing increased VLSFO supply tightness in the region. EU fuel oil 0.5% marine fuel swaps also had a backwardated structure, on par with the higher sulfur equivalent. The VLSFO 0.5% paper equivalent was assessed at a backwardation of $6.75\/mt on Aug. 15, compared with a backwardation of $6\/mt on Aug. 8. Retail bunker markets in the ARA region have seen seasonally calm conditions through the week to Aug. 16, amid slow demand and healthy availability. Traders said conditions in the ARA region were \"poor,\" with low levels of inquiries. Market weakness was attributed to the holiday season in many parts of Northwest Europe, along with the Mediterranean. This meant that various trading houses were closed for business. Platts assessed the value of delivered Rotterdam HSFO at $470\/mt on Aug. 15, rising 3.5% on the day. Meanwhile the VLSFO equivalent was assessed at $555\/mt, increasing 1.1% on the day. ","headline":"ARA fuel oil stocks decline marginally on week to 1.36 mil mt: Insights Global","updatedDate":"2024-08-16T12:27:54.000"},{"Unnamed: 0":14,"body":" Developments about refinery upgrades have been in the spotlight in the Middle East. Petro Rabigh's refinery on the west coast of Saudi Arabia will be upgraded as shareholders Saudi Aramco and Sumitomo Chemical agreed to a phased waiver of their loans to the company totaling $1.5 billion after Petro Rabigh's accumulated losses reached 53% of capital as of June 30, according to Aug. 7 statements by all three companies. Aramco will also buy some Petro Rabigh shares from Sumitomo Chemical for $702 million, increasing its stake to 60% and leaving Sumitomo with 15%. Moreover, Aramco will provide another $702 million to Petro Rabigh, for a total aggregate injection of $1.4 billion. Upgrade of the gasoline complex has also been progressing at Iran's Tehran refinery. Meanwhile, Iraq's ambitions to expand its refining capacity to capture more exports of higher-valued refined products is closer to being achieved with two more refineries in the works. Refining capacity at OPEC's second biggest crude producer, excluding all but one refinery in the Kurdish region, has reached 1.215 million b\/d, according to oil ministry data provided exclusively to S&P Global Commodity Insights. The two refineries in the works consist of the Fao Investment refinery to add 300,000 b\/d of capacity while another one in Kirkuk to add 150,000 b\/d was approved by the council of ministers on May 7. A major step ahead was set in motion in July when Iraq completed the upgrade of a gasoil pipeline from the Shuaiba projects depot next to the Basrah refinery to the southern port of Khor Al-Zubair to resume exports of gasoil, signaling the first exports of the product since 2003. That was on top of the new 70,000 b\/d crude distillation unit at the Basrah refinery started in December 2023 and the 150,000 b\/d Baiji North refinery completed in February. \"It is expected that the ramp-up of these new capacities will be a gradual process,\" said Rahul Chatterjee, a principal research analyst at Commodity Insights. New and ongoing maintenance Refinery Capacity b\/d Country Owner Unit Duration Sohar 198,000 Oman OQ Full Aug Upgrades Ruwais 837,000 UAE ADNOC Expansion NA Zarqa 102,000 Jordan JPRC Expansion NA Sitra 267,000 Bahrain Bapco Expansion NA Basra 210,000 Iraq SRC Expansion 2025 SASREF 305,000 S Arabia Aramco Expansion NA Abadan 360,000 Iran Joint Upgrade NA Bandar Abbas 320,000 Iran Bandar Abbas Upgrade NA Tehran 250,000 Iran Joint Upgrade NA Tabriz 115,000 Iran Joint Upgrade NA Kasik 20,000 Iraq Oil Ministry Upgrade Ongoing Arak 250,000 ` NIORDC Upgrade NA Isfahan 370,000 Iran NIORDC Upgrade 2025 Lavan 150,000 Iran NIORDC Upgrade NA Petro Rabigh 400,000 Saudi Arabia Rabigh Upgrade NA PGulf Star 400,000 Iran NIORDC Expansion NA Riyadh 140,000 Saudi Arabia Saudi Aramco Upgrade NA Kermanshah 25,000 Iran NIORDC Expansion NA Shiraz 50,000 Iran NIORDC Expansion NA Baiji 280,000 Iraq Oil Ministry Expansion NA Haditha 16,000 Iraq Government Expansion NA Homs 107,100 Syria Homs Upgrade Ongoing Banias 120,000 Syria Banias Upgrade Ongoing Ecomar 22,000 UAE Ecomar Expansion 2024 Launches Al-Zour 615,000 Kuwait KPC Launch 2023 Duqm 230,000 Oman Joint Launch 2023 Duqm CBH 300,000 Oman CBH Launch 2023 Jizan\/Jazan 400,000 Saudi Arabia S Aramco Launch 2022 Basra NA Iraq State Launch NA Kerbala 140,000 Iraq South Ref Co Launch NA Al-Fao 300,000 Iraq Oil ministry Launch NA Nassiriya 150,000 Iraq Oil ministry Launch NA Kirkuk 70,000 Iraq Oil ministry Launch NA Qayarah 100,000 Iraq Oil ministry Launch NA Kirkuk 12,000 Iraq Al-Barham Launch NA Kut 100,000 Iraq Oil ministry Launch NA Diwaniya 70,000 Iraq Oil ministry Launch NA NA 600,000 UAE ADNOC Launch 2025 Kuwait NA Kuwait KNPC Launch NA Brooge 180,000 UAE BPGIC Launch NA Brooge 25,000 UAE BPGIC Launch NA Mosul 150,000 Iraq Joint Launch NA Anahita 150,000 Iran Joint Launch NA Zubair 300,000 Iraq Joint Launch 2025 Condens ref 120,000 Iran Khatam Launch NA Dhi Qar 100,000 Iraq South Ref Co Launch NA Qeshm Island 70,000 Iran Pars Behin Launch NA Soleimani 300,000 Iran NIORDC Launch 2027 Al-Farkas 140,000 Syria Joint Launch NA Pearl of Makran 300,000 Iran NIORDC Launch 2027 New and ongoing maintenance New and revised entries ** Oman's Sohar refinery was heard to have undergone an unplanned shutdown in the week of Aug. 5, trade sources said Aug. 7. Refinery operator OQ could not be immediately reached for comment. The refinery was targeting a restart date in about a week. ** Production at the Fort Energy Refining in Fujairah will be increasing \"in the near future,\" according to owner Montfort. \"The refinery remains operational. As with any refinery there will be fluctuations in production over time due to a variety of usual operational and market factors,\" Montfort said. Upgrades New and revised entries ** Petro Rabigh's refinery on the west coast of Saudi Arabia will be upgraded as shareholders Saudi Aramco and Sumitomo Chemical agreed to a phased waiver of their loans to the company. Aramco will also buy some Petro Rabigh shares from Sumitomo Chemical, increasing its stake to 60% and leaving Sumitomo with 15%. Previously, Petro Rabigh has awarded US-based Jacobs a contract to provide front-end engineering and design work, as well as project management consultancy, for a fuel oil upgrade project dubbed \"Bottom of the Barrel,\" Commodity Insights has reported ** Tehran oil refinery's gasoline production project, which includes a CCR, or continuous catalytic reformer, has reached 86% progress, the plant's managing director, Mohsen Iranzad, said Aug. 14 in a statement posted on the National Iranian Oil Refining and Distribution Co. website. The gasoline project will become operational next year, Mohsen Iranzad, the plant's managing director, said, with the CCR going onstream in June 2025. The CCR project will improve the quality of gasoline and increase the amount of gasoline meeting Euro V specifications. The first phase of the complex includes the construction of a 16,000 b\/d heavy naphtha hydrotreating unit, or NHT. Existing entries * Iran's Abadan oil refinery June 24 inaugurated a hydrocracker unit under the second phase of the plant's upgrade project, oil ministry news service Shana reported. \"The biggest hydrocracker in the Middle East ... to produce light and valuable products was operational with a capacity of 42,000 b\/d,\" National Iranian Oil Engineering and Construction Co. managing director, Farhad Ahmadi, was quoted as saying. \"Processing units under the phase 2 of Abadan oil refinery development plan including a 75 million cubic feet hydrogen unit, a 17 MMcf amine unit ... a 580 metric tons per day sulfur unit will be operational to make exports possible,\" Ahmadi said. Construction will start this summer as part of the second phase of upgrades with a focus on the gasoline production unit expected to be put in service in 2026. The third phase of development and stabilization of the Abadan refinery has been incorporated in the second phase. The fourth phase aims to lower fuel oil output to below 10% and raises the quality of all our products to the level of Euro 5. ** Four units including a gasoil hydrotreater, hydrogen, sulfur recovery unit and gas treatment became operational June 24 at Tabriz oil refinery, oil ministry news service Shana reported. The $120 million projects will increase production of Euro 5 diesel from 2 million liters per day to 5 million l\/d. In addition, 110 t\/d of sulfur will be produced. In another development, the refinery broke ground June 24 on a fuel oil purification unit, Shana reported. Following its upgrade project, Iran's Tabriz refinery expects to reduce its fuel oil production. The refinery produces 4 million l\/d (1.416 t\/year) of fuel oil, which is primarily used as a feedstock for tar. The refinery is expected to reduce fuel oil production from around 25% of product output to below 5%. ** The expansion of Bahrain's Bapco refinery to 380,000 b\/d will enter the pre-commissioning phase in the first quarter of 2025, a source with knowledge of the project said May 21. All equipment has been delivered and construction is complete for the $7 billion upgrade at the refinery, formerly known as Sitra. The pre-commissioning phase signals a delay after Bapco Energies said in March that the expansion, which includes a focus on middle distillates such as diesel and jet fuel, would be completed \"later this year.\" When the upgrade is complete, the refinery will focus on producing middle distillates like diesel and jet fuel, with its fuel oil output set to decrease significantly. The residual hydrocracking unit, with 65,000 b\/d capacity, will convert 78% of feedstocks into distillates, which will be further processed into kerosene and diesel, according to the company's website. The new 225,000 b\/d integrated CDU 7 - VDU 7 will replace CDU 1,2 and 3 and VDU 1 and 3. A second hydrocracker will be built with 58,000 b\/d VGO capacity, according to the company's website. ** A plan to improve the quality of heavy products by producing 350,000 t\/y of sponge coke is underway at Iran's Bandar Abbas oil refinery, the plant's managing director Ahmad Hashemi said May 15. \"In the first phase of the products' quality upgrade, we tried to reduce the fuel oil's sulfur from 3.5% to 0.5%,\" Hashemi said. In the second phase, the refinery plans to lower the share of fuel oil in the products' basket from around 26% to 10%, he said. Separately, Hashemi said another project is to produce 500,000 t\/y of base oil. The second phase includes building a delayed coker which has not started yet, according to Fardin Bahrampour, deputy head of the refinery for planning, engineering and development. As part of the upgrade, the refinery will produce more gasoil and sulfur. However, by choosing to proceed with a delayed coker the refinery has decided to abandon the previously considered residue fluid catalytic cracking project, Bahrampour, said, adding that instead of developing an RFCC the refinery will concentrate on coke production. Currently the refinery is also building a solvent deasphalter and DAO purification, which have reached 10% progress. It is also building gasoil hydrotreater, with the project expected to finish in 42 months, Bahrampour, said. Bahrampour also said the refinery was studying the possibility of boosting refining capacity. ** Iran's Shazand oil refinery is set to choose a contractor to start eliminating fuel oil from its products and start producing needle coke. \"At the moment, we have roughly 5 million l\/d of fuel oil which is under 10% of the total items produced in the refinery,\" Mohsen Yazdani, an engineer at the refinery said May 11. \"Once we build the needle coke unit and make it operational, we will become zero fuel [oil],\" the company's representative at the Tehran oil fair said. ** Iraq's Basrah refinery is building a new fluid catalytic cracking unit. The 34,500 b\/d unit is funded via a Japanese ODA loan from the Japan International Cooperation Agency. The upgrade of the Shuaiba refinery also includes a vacuum distillation unit (55,000 b\/d) and a diesel desulfurization unit (40,000 b\/d). ** In Iran's Shiraz oil refinery, a new unit will become operational by September 2024 to upgrade gasoline quality to Euro 4. The refinery's upgrade has been accelerated after delays and involves upgrading the gasoline quality initially followed by a diesel upgrade. An isomerization unit and diesel hydrotreater will be built. Shiraz has around 50,000 b\/d current capacity and the expansion will add 26,000 b\/d. ** Saudi Aramco and French energy company TotalEnergies on June 24, 2023, kicked off construction of their Amiral petrochemicals project at their existing SATORP refinery in Jubail, Saudi Arabia, with engineering, procurement and construction contracts awarded to seven companies including Hyundai Engineering & Construction, Maire Tecnimont and Sinopec Engineering (Group) Saudi Co. The companies in December decided to move ahead with the project -- an $11 billion expansion at the 460,000 b\/d SATORP refinery. Hyundai was awarded the EPC contract for the mixed feed cracker which will have the capacity to produce up to 1.65 million metric tons per year of ethylene and related industrial gases, Aramco and TotalEnergies said in a statement after a signing ceremony held in Dharhan, Saudi Arabia where Aramco has headquarters. Commercial operations are targeted to start in 2027. ** Technip Energies had been awarded a contract to upgrade the sulfur recovery facilities at Saudi Arabia's Riyadh refinery. The contract includes the implementation of three new tail gas treatment units (TGT), as well as improving the performance of the existing sulfur recovery units, it said in a statement. The existing sulfur recovery units were designed and built by Technip Energies in the early 2000s. Separately, Saudi Aramco has awarded a contract to KBR to provide technology, license, basic engineering design and equipment for its solvent de-asphalting for the Riyadh refinery residue upgrading and clean fuels project. ** The quality upgrade of gasoil at Iran's Persian Gulf Star has reached 90% progress, which will allow it to produce Euro 5 standard product, plant Managing Director Alireza Jafarpour said on National Iranian Oil Products Refining and Distribution's website Oct. 2022, adding that the facility will soon enter its final stage of production. \"At the moment 16 million liters\/d of regular gasoil are being produced in this refinery,\" Jafarpour said. \"From the two hydrogen purification units [diesel hydrotreating units] needed for this project, one of them has been operationalized and the second unit is in the last stages [to go on stream],\" he said. Persian Gulf Star mulls further expansion. The condensate refinery eyes to add 90,000 b\/d to the current nameplate refining capacity, Mohammadali Dadvar, managing director of the Persian Gulf Star Refinery said. \"The plant's initial design envisaged 360,000 b\/d of gas condensates. Right now, with the implementation of an expansion project, the capacity has reached 450,000 b\/d. We can raise this to 540,000 b\/d in the future,\" Dadvar said. ** A new structure will be added to Iran's 25,000 b\/d Kermanshah refinery to triple its capacity with a $930 million investment, NIORDC's website reported May 2022, citing Farhad Kaviani, the refinery's managing director. \"A 50,000 b\/d plant is due to be built next to the current one to this end ... and the existing plant will continue its production. The primary studies have been carried out and the new refinery will go on stream in three years,\" Kaviani said. The new refinery will produce more gasoline, including Euro 5 specification gasoline, and less fuel oil. It will also reduce sulfur in the mazut or heavy, low-quality fuel oil it is producing, Kaviani said. ** Iraq's government decided North Refineries Co. should upgrade Haditha refinery and work directly with Honeywell. The government plans to build two units of total capacity of 20,000 b\/d at the site, which will raise the capacity of the plant to around 35,000 b\/d. International companies will be approached to bid for building an additional 35,000 b\/d at the refinery, which will raise its overall capacity to 70,000 b\/d. ** Ecomar Energy Solutions has agreed to expand its refinery and build new storage capacity at Fujairah. Refinery capacity will be increased to 62,000 b\/d from 22,000 b\/d currently, and inland storage capacity will be increased more than fivefold to 1 million cu m in the phase 3 expansion, which should be completed by the end of 2024. Ecomar's refinery will add an additional CDU, bringing the total to two CDUs. ** A gas condensate project is under construction in Iran as part of eight planned 60,000 b\/d condensate refineries around Siraf, Bushehr province. ** There is a program in Syria's ministry of oil for the Homs Refinery to reach the highest possible production capacity. ** Iraq has added another 10,000 b\/d of refining capacity after completing the rehabilitation of a CDU at the Kasik refinery in the north of the country. Rehabilitation work continues at the refinery's other 10,000 b\/d CDU. ** Saudi Aramco plans to complete a $2.5 billion clean fuels project at its Ras Tanura refinery. Work on the clean fuels project at Ras Tanura started in 2018. ** US engineering company CB&I has been awarded a $95 million contract for the expansion and modernization of Sasref. Launches Existing entries ** Kuwait's Al-Zour refinery conducted a performance guarantee test run at the designed maximum production capacity and has since had maintenance at its main conversion units that led to varying production rates, a spokesperson for the refinery's owner Kuwait Integrated Petroleum Industries told S&P Global Commodity Insights. The test run was \"satisfactory,\" Ali Mohammad al-Ajmi said June 10 in response to a question about production rates. \"In addition to the turnaround activities, the heavy crude processing is a major factor in reducing the operating capacity,\" he added, but declined to say what production currently is. On May 30, KIPIC announced the official start of Al-Zour, after taking the refinery to its full 615,000 b\/d capacity last year and again in February. Commercial operations began in November 2022. The company said maintenance at two of the units was completed in January. ** Basic design of Soleimani oil refinery will be completed by the end of current Iranian year on March 20, 2025, managing director of National Iranian Oil Engineering and Construction Co., Farhad Ahmadi, said May 11, quoted by NIORDC. \"Afterwards, we hope to start building every phase one after another,\" said Ahmadi, whose company is in charge of basic design of licensed and non-licensed units of the refinery. The project started in 2022. Soleimani is located in the southern province of Hormozgan at the port of Bandar Abbas. In November 2023, officials reported progress with the Soleimani and Makran Pearl refineries, although did not specify when construction would start following some delays. The Soleimani construction was previously expected to start in 2023. In addition to Soleimani, Iran aims to build Pearl of Makran, a second plant in the Makran region at the Sea of Oman, also with a refining capacity of 300,000 b\/d, and another 120,000 b\/d plant. Iran is also building a 180,000 b\/d plant in Khuzestan in a 20-80 investment by the NIORDC and private sector. The oil for this plant will come from the West Karun area. ** Saudi Aramco's Jazan Refinery Complex is running at around 70%, according to sources in June 2024. ** Iraq's state-owned Southern Refineries Company and China's China National Chemical Engineering Corporation on May 15 signed a contract to build the new Fao refinery. The refinery will be part of the greater Fao Port project. The refinery will be built in two stages: Initially a 300,000 b\/d refinery will be built followed by a petrochemical complex of 3 MMt\/y capacity, as well as a 2,000 MW power station. The refinery will be offered under the build-operate-transfer or build-own-operate-transfer investment models. The petrochemical facility could be integrated into the refinery at a later stage. ** Since startup in late 2023, OQ8 continues to operate at full production capacity the Duqm refinery of 230,000 b\/d. Expansion plans into petrochemicals are also at an early stage. The refinery will add another 5%-10% of output in 2024 and is considering an upgrade of its naphtha production for use in gasoline. Duqm started test runs at its primary CDU in April 2023. ** Iraq's Kerbala refinery has completed its test runs and the contractual commissioning process and is running at full capacity, the Iraqi News Agency (INA) quoted the refinery manager as saying at the end of December 2023. ** Iran is looking to build a new 110,000 b\/d refinery in the southwestern province of Kohkiluyeh-Bohrahmad, oil minister Javad Owji said July 17, the ministry's news service Shana reported. More than a quarter of the country's crude oil is produced in Kohkiluyeh-Boyrahmad province. The local Gachsaran Oil and Gas Co. produces 17% of the country's crude with production capacity at 650,000 b\/d of oil and 1.2 Bcf\/d of gas. ** Qatar's family-owned Sadara Commercial Representative and the Iraqi government have signed a memorandum of understanding to build a 150,000 b\/d refinery in the city of Mansouriya in OPEC's second biggest producer, its chair told the official Qatar News Agency in June 2023. The operation of the refinery in the Diyala governorate in eastern Iraq will be for 25 years, Ahmad al-Khalaf, the chair of Sadara, told Qatar's news agency. Another MOU was signed with the Iraqi government to build, operate and invest in a 300,000 b\/d refinery in partnership with Sadara, and specialized international and Malaysian companies, he said. He did not disclose if the 300,000 b\/d refinery will be built in Iraq or mention the names of the partners. ** Iran's Persian Gulf Mehr gas condensate refinery will come on stream in the next Iranian year or by the end of the following year (March 2026), according to a state television report. \"In the current year's budget, Eur500 million have been granted to this project so that it becomes operational in the next [Iranian] year or at the end of the year after,\" Jalil Salari, managing director of National Iranian Oil Products Refining and Distribution Co., was quoted as saying. In the first phase, the plant will produce LPG, purified naphtha, kerosene, gasoil and atmospheric residue. In the second phase, the purified naphtha will be used to produce gasoline (regular unleaded). \"The refinery will have storage tanks and some processing units have been altered to produce maximal gasoline,\" he said. Construction of the refinery, which started in October 2020 is being carried out by Khatam-al Anbiya, the engineering arm of the Islamic Revolutionary Guard Corps. As of July 2022, the plant's construction was 45% complete, according to local media reports. ** Brooge Energy Ltd.'s Brooge Petroleum & Gas Investment Co. still plans to build a modular refinery at the city-port of Fujairah on the east coast of the UAE. The planned refinery would have a capacity of 25,000 b\/d, capable of producing IMO 2020-compliant 0.5% sulfur fuel. The modular design would permit for future expansion. Brooge Energy Ltd. said in July 2021 that it had signed an agreement to sublease land to Blue Ocean Energy FZE over 20 years, on which it will construct a 25,000 b\/d modular refinery in the UAE's Fujairah. Blue Ocean Energy will be responsible for building the refinery and financing the cost of construction, while Brooge will oversee operating the refinery and earning revenue from tolling fees on a take-or-pay basis. It will be focused on the production of VLSFO. The company is also in advanced stages of planning for a refinery with a capacity of 180,000 b\/d. ** Iraq is open to attracting foreign investment for six new refineries with a combined capacity of 570,000 b\/d, the country's oil minister said in March. The planned facilities open for foreign investment are a 150,000 b\/d Maysan refinery in the south-eastern province of Maysan; a 70,000 b\/d Qayara refinery in the northern province of Nineveh; a 150,000 b\/d Nassiriya refinery in the southern province of Dhi Qar; a 100,000 b\/d Kut refinery in the eastern province of Wasit; a 70,000 b\/d Samawa refinery in the southwestern province of Muthana and a 30,000 b\/d crude hydrogenation unit in the southern province of Basrah. At a later stage, the ministry will also attempt to attract investment for a 70,000 b\/d Haditha refinery in the western Anbar province. ** Iran's under-construction 60,000 b\/d condensates Queshm refinery will add 6 million liters\/d of gasoline to the country's output once it is built within three years, the plant's managing director, Hamed Doshmanfana-Yazdi, said September 2022, quoted by state-owned news agency IRNA. \"At the moment, the second phase (the gas condensates refinery), has 30% progress. But we plan to negotiate with the licensor to optimize the second phase's products with higher values,\" said Doshmanfana-Yazdi who runs Pars Behin Palayesh Naft Qeshm. The refinery will produce 30,000 b\/d of gasoline from heavy naphtha, which means 2 billion l\/year. The products will be exported, he said. The first phase of the Qeshm Pasargad heavy crude refinery went on stream in 2021. It receives 35,000 b\/d of Soroush and Norouz oil fields in the Persian Gulf. The main product in the oil refinery 1.8 million barrels of bitumen. ** Iran has started engineering studies and financial talks with banks to build a refinery on the island of Lavan in the Persian Gulf. The refinery will produce oil products in its first phase and petrochemical products in the second phase. The 150,000 b\/d refinery will have a solvent production unit and a new distillation unit. The new refinery will be located next to an existing plant. ** The National Iranian Oil Products Refining and Distribution Company said in April 2022 that after completion of studies in a Syrian refinery the project is close to the financing stage. In October 2017, oil ministry news service Shana reported that Syria has signed a $2.6 billion contract with Iran, Venezuela and Malaysia to build a 140,000 b\/d refinery near the city of Homs in Al-Farkas. Venezuela owns 33% of the refinery's revenue, Iran and Malaysia take 26% and Syria will have the remaining 15%, it said. ** Iran plans to build a new plant in the southwestern, oil-rich province Khuzestan. Design and construction will start in the next Iranian year (2022-23). ** Iran has launched the first phase of a 70,000 b\/d extra heavy crude plant in the Persian Gulf's Qeshm island. \"This is the first extra heavy oil refinery in the country that in its first phase has a refining capacity at 35,000 b\/d of extra-heavy oil,\" oil minister Javad Owji said. The primary product of the plant, built by Pars Behin Qeshm Oil Refining Co., is bitumen. Naphtha, kerosene and gasoil are added to the basket during the distillation process. The second phase will add another 35,000 b\/d. ** China's CNCEC will build a refinery and petrochemical complex in southern Iraq. The 300,000 b\/d refinery will be built at the port of Fao on the Gulf. The refinery will be offered under the Build Operate Transfer or Build Own Operate Transfer investment model. ** Iraq has been in talks with Eni to build a 300,000 b\/d refinery near the Zubair oil field operated by the Italian company in the southern part of the country. The first phase of the project includes commissioning 150,000 b\/d by 2025. ** Angola's state-owned oil company, Sonangol, is working with Iraq's ministry of oil to build a complex refinery in Mosul. The discussions between Sonangol and the ministry are for a refinery with a capacity of 100,000-150,000 b\/d of complex products. ** Canada's Pacific Future Energy has been awarded a contract to build a 150,000 b\/d refinery outside the southern Iraqi town of Nassiriya. ** Canada Business Holdings' 300,000 b\/d ultra-low sulfur fuel oil refinery project at Duqm, Oman, will process residue from OQ and Kuwait Petroleum International's 230,000 b\/d Duqm refinery project, CBH CEO Moses Solemon said. \"The CBH refinery complements the Oman-Kuwait refinery. Therefore, we are in synergy and not in competition,\" Solemon said. The company is targeting the end of 2023 for the refinery to process its first batch of products. ** Iran is aiming to start construction of the Anahita oil refinery in the western province of Kermanshah designed to process 150,000 b\/d of crude oil. ** Kuwait may add a new refinery in the south of the country, which could add 130,000-160,000 b\/d of capacity. ","headline":" Upgrades in focus in Middle East","updatedDate":"2024-08-16T12:25:57.000"},{"Unnamed: 0":15,"body":" Bunker prices were little changed in the week to Aug. 15 amid mixed signals from macroeconomic news and geopolitical tensions, with the low-sulfur grade slightly outperforming high-sulfur on occasionally supply tightness. The Platts Bunkerworld 0.5% sulfur fuel oil index ended the week at $604.47 per metric ton, down $4.18\/t on the day, up $10.12\/t on the week and down $21.72\/t on the month. The BW380 index, which represents value for 3.5% sulfur fuel oil, ended the week at $513.47\/t, down $2.06\/t on the day, 29 cents\/t on the week and $29.21\/t on the month. While Iran\u2019s promised retaliation against Israel has add risk premiums to the oil markets as it could lead to supply disruptions, weaker-than-expected US employment data and contracting Chinese manufacturing activity are stoking concerns around potential demand weakness. \"Even the tense geopolitical situation of the Middle East and the possibility of another escalation between Iran and Israel don\u2019t cheer up oil investors enough to bet for a rise,\" said Ipek Ozkardeskaya, senior analyst at Swissquote Bank. In July , low sulfur fuel oil output at China's refiners rose 1.9% on the month to 1.318 million mt, though still 2.4% lower than the level seen in the same month of 2023, according to data from local energy information provider JLC. Premiums for Zhoushan ex-wharf marine fuel 0.5% bunker over FOB Singapore marine fuel 0.5% cargo values averaged $15.85\/t for Aug. 1-13, widening from the slim 30 cents\/t premium in July, S&P Global Commodity Insights data showed. In Singapore , commercial stockpiles of heavy distillates slipped 8% to a five-week low of 18.1 million barrels in the week ended Aug. 14, according to Enterprise Singapore data. Stocks at the world\u2019s largest marine refueling hub were currently at their lowest since the week ended July 10, when they were at 17.8 million barrels, the data showed. Mixed signals Ship fuel sales at the UAE Port of Fujairah climbed 1.7% in July to 625,883 cu m, hitting the highest level since April and rebounding from a seven-month low in June, according to Fujairah Oil Industry Zone. In Northwest European bunker markets, markets were seasonally calm due to holidays across Europe. With poor demand across the Amsterdam-Rotterdam-Antwerp region, Skaw and Hamburg, market participants will be tracking levels of inquiries which could potentially increase following the end of the holiday season. In the Mediterranean, demand levels have been low, due to holidays in various countries, notably Greece and Italy. Weak conditions were also reported in Gibraltar and Las Palmas in recent days, while market participants described Malta demand as healthy. Also, Latin American bunker markets saw scarce activity as the Feast of Assumption public holiday was observed in some countries in the region. The BW Indexes are weighted daily indexes made up of price assessments at 20 key bunkering ports. To obtain a representative geographical spread, the ports were selected by size with reference to their geographical importance. The BW 0.5% Sulfur Index ports are Hong Kong, South Korea, Shanghai, Singapore, Japan, Las Palmas, Durban, Fujairah, Gibraltar, Piraeus, Rotterdam, St. Petersburg, Houston, Los Angeles, New York, Balboa and Santos. The BW380 Index ports are Busan, Canary Islands, Colombo, Durban, Fujairah, Gibraltar, Hong Kong, Houston, Los Angeles, New York, Offshore Nigeria, Panama Canal, Piraeus, Rotterdam, Santos, Shanghai, Singapore, St. Petersburg, Suez and Tokyo. ","headline":" Traders await Mideast cues amid slow summer demand","updatedDate":"2024-08-16T12:01:08.000"},{"Unnamed: 0":16,"body":" Crude oil futures were lower in morning trading in Europe on Aug. 16, as weak China economic data raised concerns about the region's demand outlook and ceasefire talks in Gaza signaled the possibility of easing tensions in the Middle East. At 1143 GMT, the ICE October Brent futures contract was trading at $78.99\/b, down $2.05\/b from the previous close, while the September NYMEX light sweet crude contract was $2.44\/b lower at $75.92\/b. China's industrial production rose just 5.1% in July from the previous year, slowing from the 5.3% increase in June and missing forecasts of a 5.2% growth. That has offered little support to investor confidence in the country's economic recovery, with expectations of weaker domestic demand in China hurting the outlook for refineries in Asia struggling with tight margins. The International Energy Agency said this week that the world is seeing a major deceleration in oil demand growth led by China, with inventories set to rise next year even if OPEC+ were to postpone its plans to ease output cuts. \u201cNew demand concerns are weighing on the market,\u201d Commerzbank analysts said. \u201cOPEC and the International Energy Agency have revised their forecast for global oil demand slightly downward.\u201d Meanwhile, no further escalation in violence in the Middle East through the week ended Aug. 16 has calmed some investors. \u201cThe feared retaliatory strike by Iran has so far failed to materialize, which has probably favored a partial pricing out of the risk premium,\u201d Commerzbank analysts said. Investor are focused on comments from the Federal Reserve Chair Jerome Powell, who is slated to speak at the Jackson Hole Economic Symposium on Aug. 23, for fresh signals on the US central bank's interest rate outlook. \u201cThis week, we've seen both low inflation figures and strong growth figures from the US. This is a combination that the stock market especially loves, but it's also positive for the commodity markets,\u201d analysts at GRM said. ","headline":" Crude lower amid weak Chinese data, Gaza ceasefire talks","updatedDate":"2024-08-16T11:46:28.000"},{"Unnamed: 0":17,"body":" A petrochemical plant at Scotland's Grangemouth refinery will undergo planned maintenance starting Aug. 16, according to its owner Petroineos, which provided notice of the upcoming works to the south side of the site. Ineos, a part of joint venture Petroineos, warned of flaring from the plant as it begins to shut down units for planned works, writing in an Aug. 15 statement via X. Speaking to S&P Global Commodity Insights Aug 16, a representative for the company said that the maintenance is scheduled for the site's petrochemicals business, without confirming the duration of planned works. The planned turnaround marks the latest interruption to production from the south of the site, with a plant at Kinneil, part of the Forties pipeline system, undergoing works in mid-July and early August after experiencing an operational issue. Recent maintenance to the plant follows a series of outages affecting operations across both the north and south of the site over the last year, which have dented the refinery's profitability despite healthy oil product margins. The 100-year-old refinery's hefty maintenance requirements have been blamed as part of the reason the plant has been slated for transformation into an import terminal after 2025, though it remains to be seen whether support from the UK's new Labour government could extend its lifespan. Within the Labour government's first month in office, it announced GBP1.6 million ($2.04 million) of joint funding with the Scottish government to secure a future for Grangemouth, though funding details are yet to be made public. The previous government had abstained from offering state funding from the site, with Graham Stuart, the UK\u2019s former minister of state for energy security and net zero, saying that continued operations beyond May 2025 would require an investment of around GBP40 million ($51 million). ","headline":" UK's Grangemouth petrochemical plant begins planned maintenance","updatedDate":"2024-08-16T10:56:03.000"},{"Unnamed: 0":18,"body":" China's overall weak demand for oil products is likely to keep weighing on utilization gains in the country's small independent refineries, despite a slight recovery in crude runs in early August due to reduced refinery maintenance, refining sources and market observers said Aug. 16. The sources anticipate a weaker-than-usual peak demand season, typically seen in September and October, as autumn brings increased harvesting and fishing activity, ideal weather for construction and higher travel due to the Mid-Autumn Festival and National Day holidays. Small independent refineries refer to those with production capacities of 40,000-214,000 b\/d, most of which are located in the Shandong province. Shandong's independent refineries are typically a key indicator of China's oil demand, as they operate autonomously from state-owned entities in the refining sector. As of Aug. 14, the average utilization rate at these small independent refineries edged 0.61 percentage point higher on the week to 52.66%, according to the latest data from local energy information provider JLC. This was slightly higher than the 52% reported as of July 10. The 52% utilization rate was first seen in June, the lowest since March 2020. The previous low was 43.8% in February 2020, during the pandemic, the data showed. Refining margin narrows The margin from processing imported crude fell to about Yuan 195 per metric ton ($3.7\/b) on Aug. 14 from about Yuan 323\/t ($6\/b) on Aug. 7 due to rising crude prices, according to JLC data. Additionally, at least three leading independent refineries -- with a combined production capacity of 376,000 b\/d -- have extended their shutdowns since late May or early June for prolonged maintenance to avoid additional costs associated with resuming operations, market sources said. Despite expectations of a demand recovery in September, refiners remain cautious about increasing utilization rates due to weak signs of recovery, a Shandong-based analyst said. In July, Shandong's independent refineries saw gasoline sales drop about 10% on the month as they reduced gasoline output by 5% to 1.9 million metric tons, while stock levels rose 2% to about 489,000 metric tons over the same period, JLC data showed. The combined sales of gasoline and gasoil in July declined 25.2% on the year and 6.3% on the month. China's retail sales penetration of new energy vehicles reached a record 51.1% in July, the first time it has surpassed the 50% mark, according to the China Passenger Car Association. Passenger NEV retail sales totaled 878,000 units in July, the second highest on record, following the 947,347 units sold in December 2023. Market observers said this was the first time NEVs have overtaken conventional petroleum-fueled vehicles in new car sales, further impacting gasoline demand. State-run refineries to boost supplies Meanwhile, domestic oil product supplies are set to rise as state-owned refiners boost utilization rates in August, with more refineries expected to return to normal operations and reduce product exports. These factors would limit crude runs at small independent refineries until there is a notable uptick in oil demand. The sources estimate gasoline output will rise 3.7% on the month to 14.7 MMt in August, while gasoil production is expected to increase 4.4% to 17.7 MMt over the same period. There were talks that state-owned companies have been cutting oil product exports in August as the arbitrage window closes. As a result, they are likely to procure fewer oil products from independent refiners to increase sales from their own system refiners, the sources said. Market sources estimate China's oil companies will export around 3.19 MMt of clean oil products in August, down from the previously projected 3.27 MMt. Oil products at Shandong's independent refineries: ('000 metric ton) July '24 July '23 Change June '24 Change Output 5,300 6,853 -22.70% 5,376 -1.40% Sales 5,257 7,029 -25.20% 5,608 -6.30% Stocks 1,274 962 32.50% 1,230 3.60% Jan-July '24 Jan-July '23 Change Output 42,711 45,392 -5.90% Sales 42,717 45,776 -6.70% Stocks 9,043 8,424 7.30% Source: JLC ","headline":"Tepid demand to weigh on utilization recovery in China's small independent refineries","updatedDate":"2024-08-16T08:24:01.000"},{"Unnamed: 0":19,"body":" Taiwan's state-owned producer CPC has extended its shutdown of the 80,000-b\/d RFCC at its Dalin Refinery, which has an overall capacity of 400,000 b\/d, sources said. Company officials could not be reached for comment. The unit, originally scheduled to restart on Aug. 14, is now expected to restart tentatively by Aug. 31. The unit was forced to shut down on July 21 due to valve issues. Additionally, CPC has had to reduce the capacity of the 150,000-b\/d Crude 12 by 28%, while both the 100,000-b\/d Crude 10 and 100,000-b\/d Crude 11 have been derated by 25% since Aug. 10, due to the unplanned RFCC shutdown, according to trade sources. CPC is offering a VLCC-sized cargo of US WTI Midland crude due to the outage, sources said. Further details could not be ascertained. ","headline":" Taiwan's CPC Dalin refinery shutdown extended on RFCC outage","updatedDate":"2024-08-16T08:22:44.000"},{"Unnamed: 0":20,"body":" South Korea's imports of LNG jumped 17.6% year on year to 3.075 million metric tons in July on a sharp rise in supplies from the US, customs data showed Aug. 16. This marks the fourth straight increase in the country\u2019s LNG imports. The July imports were flat from June\u2019s 3.074 MMt. For the first seven months of 2024, South Korea imported 26.522 MMt of LNG, up 3.2% on the year. The country imported 44.117 MMt of LNG in 2023, 4.9% lower than the previous year. Customs data also showed South Korean LNG importers -- including state-run Korea Gas Corp. and private power utility SK E&S -- paid $1.85 billion for the shipments in July, compared with $1.62 billion a year earlier and $1.84 billion in June. This means importers paid an average of $11.57\/MMBtu in July, given 1 metric ton equals 52 MMBtu, down from $11.92\/MMBtu a year earlier but higher than the $11.51\/MMBtu paid in June. The country\u2019s LNG import bills have been slowly declining since late 2022 on lower crude oil prices and LNG spot prices. South Korea's LNG importers are less affected by spot prices because more than 70% of their purchases are based on long-term contracts, which are linked to international oil prices, according to importers. The US emerged as the biggest LNG supplier for South Korea in July as the Asian country imported 810,706 metric tons, up 150% on the year. This also marks the biggest import volume from the US since January 2022, when South Korea received 866,495 metric tons, and the second consecutive jump following a 69.2% rise in June. Over January-July, South Korea imported 3.222 MMt from the US, up 16.5% on the year. Another 617,953 metric tons of South Korea's total LNG imports in July came from Qatar, which had long been its biggest supplier. Qatar inflows declined 2.3% on the year. For the first seven months of 2024, imports of Qatari LNG climbed 1.4% year on year to 5.219 MMt. Imports from Australia climbed 0.8% to 508,535 metric tons in July, the sixth consecutive month of a year-on-year rise. Over January-July, imports from Australia increased 12.7% to 6.61 MMt. South Korea received 69,069 metric tons of LNG from Russia last month, up 11% on the year amid the Ukraine-Russia conflict. ","headline":" July LNG imports jump 17.6% on year with sharp rise from US","updatedDate":"2024-08-16T07:49:21.000"},{"Unnamed: 0":21,"body":" Crude oil futures were higher in mid-afternoon Asian trade Aug. 16 as weak China data continued to hang over the region's demand outlook, with investors beginning to look ahead to a critical week for US interest rate expectations. At 2:21 pm Singapore time (0621 GMT), the ICE October Brent futures contract was down 23 cents\/b (0.28%) from the previous close at $80.81\/b, while the NYMEX September light sweet crude contract fell 30 cents\/b (0.38%) to $77.86\/b. \"Oil prices fell as the market weighed strong US economic data and the potential threat of an attack by Iran or its proxies on Israel against weak demand in China,\" Saxo's APAC Research team said Aug. 16. A slate of mixed economic indicators from China this week offered little support to investor confidence in the country's economic recovery. While analysts have called for more stimulus in the world's largest importer of crude, the People's Bank of China is still anticipated to keep loan prime rates unchanged next week. \"Even the tense geopolitical situation of the Middle East and the possibility of another escalation between Iran and Israel don\u2019t cheer up oil investors enough to bet for a rise above the $80\/b level [for US crude],\" said Ipek Ozkardeskaya, senior analyst at Swissquote Bank. Expectations of weaker domestic demand in China further compounds the outlook for refineries in Asia which are already struggling against tight margins. \"What we are closely watching out for is that China's struggling construction and property sector could lead to a high volume of gasoil exports [due to weaker domestic sales]... an oversupply would extend the current lengthy downtrend in Asian benchmark crack spreads,\" said a middle distillate marketing manager at a major South Korean refiner. China's embattled property sector was once a key contributor to the country's crude and oil product demand. Crude oil prices did receive some support through the session from a slightly weaker US dollar, which made dollar-denominated assets such as oil futures cheaper for holders of other currencies. The ICE US Dollar Index was at 102.755 as of 0554 GMT Aug. 16, down 0.05% from the previous close. The softer dollar came ahead of the Federal Open Market Committee meeting notes due Aug. 22, which could offer more clarity on the Central Bank's impending policy easing cycle. \"The minutes are expected to have a dovish tone, reinforcing expectations for a Fed rate cut in September,\" IG Market Analyst Tony Sycamore said. \"The rates market has already priced in a full 25bps rate cut by September, with a cumulative 94bps of Fed rate cuts anticipated by year-end.\" Investor attention will also center on Fed Chair Jerome Powell, who is slated to speak at the Jackson Hole Economic Symposium on Aug. 23 for fresh signals on the Fed's interest rate outlook. Dubai crude Dubai crude swaps and intermonth spreads were higher in mid-afternoon Asian trading Aug. 16 from the previous close. The October Dubai swap was pegged at $78.42\/b at 2:00 pm Singapore time (0600 GMT), up 53 cents\/b (0.68%) from the previous Asian market close. The September-October Dubai swap intermonth spread was pegged at 81 cents\/b, up 1 cent\/b over the same period, and the October-November intermonth spread was pegged at 55 cents\/b, down 1 cent\/b. The October Brent-Dubai exchange of futures for swaps was pegged at $2.35\/b, up 29 cents\/b. ","headline":" Crude dragged by China sluggishness; Fed indicators awaited","updatedDate":"2024-08-16T06:35:52.000"},{"Unnamed: 0":22,"body":" State-owned PetroChina Xinjiang Oilfield's Hutubi natural gas storage has reached a record high injection level of 26 million cu m\/d, state media CCTV said in a report late Aug. 15. The storage facility has injected over 2 Bcm of gas since March 28, ensuring gas supply to cities along the West-East Natural Gas Pipeline during the summer season, according to the report. Hutubi is China's largest gas storage facility with a capacity of over 10 Bcm and the first to receive imported pipeline gas from Central Asia. It is the largest gas storage site in Asia and the sixth largest in the world, CCTV said. The gas injection volume at the Hutubi storage facility this year has increased by 11.5 million cu m\/d from last year and has been maintained at 26 million cu m\/d for 14 consecutive days. Strong gas injection levels will help stabilize domestic gas prices amid peak summer demand and reduce reliance on LNG imports, the report said. The facility is located in the remote northwestern province of Xinjiang and started operation in 2013 with a designed capacity of 10.7 Bcm, a working gas volume of 4.51 Bcm, a designed injection capacity of 15.5 million cu m\/d, and a designed extraction capacity of 28 million cu m\/d. Gas storage facilities play a significant role in peak-shaving by providing gas supply at peak demand levels, and valley-filling, which is the supporting of consumption during low demand periods. For example, the daily supply of pipeline gas imported from Central Asia usually falls by more than 50 million cu m in the winter, as supply is diverted to domestic markets to meet heating demand. At this time, gas storage facilities like Hutubi ensures stable supply to the arterial West-East Natural Gas Pipeline, sources said. China was estimated to have 33 underground gas storage facilities by the end of 2023, including 29 reservoir-type storage facilities and 4 salt cavern storage facilities, according to data from state media People's Daily in June. These storage facilities have a designed total working gas volume exceeding 30 Bcm, with a peak shaving capacity of 23 Bcm and a peak gas extraction capacity of nearly 300 million cu m\/d. The storage facilities are mainly operated by China National Petroleum Corp., China Oil & Gas Pipeline Network and China Petroleum & Chemical Corp., with the three state-owned enterprises accounting for 97% of facilities and over 98% of the working gas volume. ","headline":"PetroChina's Hutubi gas storage hits record high daily injection level","updatedDate":"2024-08-16T06:25:00.000"},{"Unnamed: 0":23,"body":" Australia\u2019s crude oil and condensate exports grew 23% on the month and 7% on the year to 8.91 million barrels in June amid bolstered Southeast Asian demand, data from the Department of Climate Change, Energy, the Environment and Water released late Aug. 15 showed. Singapore retained its spot as Australia\u2019s top export destination in the month, with volumes to the city-state growing 44.9% on the month and nearly sevenfold on the year to 4.44 million barrels. Exports to other Southeast Asian nations have also grown, with Indonesia seeing the largest increase, surging about fivefold on the month and on the year to 1.3 million barrels. Indonesia\u2019s state-owned Pertamina\u2019s higher-than-usual crude purchase volume in the month had been attributed to preparation for the increased demand from Eid festivities, market participants told S&P Global Commodity Insights. The company had purchased one cargo each of Australia\u2019s North West Shelf and Wheatstone condensate grades loading over June at a discount in the $7s\/b and $2s\/b respectively to the Dated Brent crude assessments, CFR Tuban. Meanwhile, volumes to South Korea slumped 92.4% on the month and 94.9% on the year, to 97,492 barrels, as the world\u2019s fourth-largest crude importer took in significantly more US light sweet crude this year, while South Korean end users had opted for Qatari condensates over Australian ones. South Korea\u2019s Hanwha TotalEnergies had purchased two June-loading deodorized field condensate at Dubai minus $5s\/b, FOB. Other South Korean buyers purchased two to three cargoes of low sulfur condensate in the month at Dubai minus $2\/b to minus $2.60\/b, FOB. Mixed sentiments ahead Looking ahead, market sentiment for October-loading condensate was mixed as the complex grappled with thin downstream margins coupled with more attractive naphtha prices, trade sources said. Two 650,000-barrel cargoes of NWS condensates have been scheduled to load over October, stable on the month, sources added. Oil major BP holds the first cargo for loading over Oct. 10-14, while Australia's Woodside Energy holds the second cargo for loading over Oct. 24-28. Valuations for October-loading NWS were heard at a discount ranging $7s\/b to $8\/b to Platts Dated Brent crude assessments, FOB. Meanwhile, only one cargo of Wheatstone condensate grade was available for the October-loading cycle this time, market sources said, compared with at least two Australian condensate cargoes in the previous cycle. \"Condensates this month are a little bit difficult to read -- there are not that many cargoes, so sellers are sure to be bullish and offer at stronger levels, although margins are still admittedly weak,\" a trade source said. Naphtha crack spreads have improved on the month, though market participants have emphasized that the strength was not reflective of the market, attributing the strength in crack spares to the decline in crude prices. The Platts second-month naphtha swap crack against Dubai crude swaps averaged minus $6.16\/b as of the Aug. 15 Asian close, compared with an average of minus $9.65\/b in July, Commodity Insights data showed. For light sweet crudes, Australia's Santos scheduled a cargo of Cooper crude to load over Oct. 8-14, according to market participants who valued the light sweet crude complex stable on the month. Meanwhile, the preliminary October-loading program for Australia's Ichthys Field condensate had emerged, with Japan's Inpex holding the first 650,000-barrel cargo for loading over Oct. 5-9 and the second and final cargo held by France's TotalEnergies for loading over Oct. 22-26, market sources said. October-loading Ichthys Field condensate had been valued at a premium in the $1s-$2s\/b to Dated Brent on an FOB basis. In the heavy sweet crude segment, Santos had offered a 350,000-barrel cargo of Van Gogh crude via a spot tender that closes Aug. 16 with same-day validity, according to trade sources. Bearish market sentiment was heard for October-loading heavy sweet Australian crudes on lackluster low sulfur fuel oil crack spreads. \"Fuel oil margins are not bad but not great,\" an Asia-based trader stated. The second-month low sulfur fuel oil swap crack spreads averaged $6.36\/b as of the Aug. 15 Asian close, compared with an average of $5.74\/b in July, Commodity Insights data showed. Australia's top 10 crude oil, condensate export destinations (in barrels) June 2024 May 2024 June 2023 M\/M Change Y\/Y Change Singapore 4,441,864 3,065,024 651,624 44.9% 581.7% Thailand 1,301,991 989,387 2,461,203 31.6% -47.1% Indonesia 1,298,846 265,430 230,836 389.3% 462.7% China (excludes SARs and Taiwan) 660,430 571,744 694,395 15.5% -4.9% Malaysia 438,400 377,389 1,444,140 16.2% -69.6% Japan 327,699 198,758 317,635 64.9% 3.2% Brunei Darussalam 313,233 211,967 603,822 47.8% -48.1% South Korea 97,492 1,280,605 1,925,311 -92.4% -94.9% Vietnam 8,806 10,064 6,919 -12.5% 27.3% Taiwan 8,177 0 8,806 NA -7.1% Australia's petroleum production (in barrels) June 2024 May 2024 June 2023 M\/M Change Y\/Y Change Crude Oil 2,314,650.1 2,302,070.5 2,214,013.1 0.5% 4.55% Condensate 5,975,319.5 6,025,638.0 6,421,896.0 -0.8% -6.95% LPG 3,321,019.7 2,798,965.5 3,088,296.7 18.7% 7.54% Crude & Condensate Total 8,289,969.6 8,321,418.6 8,635,909.1 -0.4% -4.01% Source: Australian Department of Climate Change, Energy, the Environment and Water ","headline":" June crude, condensate exports rebound 23% on month","updatedDate":"2024-08-16T05:57:21.000"},{"Unnamed: 0":24,"body":" South Korean refiners are generally content with a slight improvement in refining margin so far in the third quarter but China's ample clean oil product export quotas and tepid regional economic activity pose a serious threat to the overall cracks and export margins, industry sources said Aug. 13-16. Asia-wide refiners hardly faced any crude supply security or feedstock procurement issues despite the prolonged OPEC+ production cuts and geopolitical tensions in the Middle East. On the refining and oil product sales front, however, high inflation, lackluster consumer spending, and tepid industrial activity have constantly put margins under pressure, refinery sources and analysts based in Seoul and Ulsan said. The biggest concern for highly export-oriented South Korean refiners is that an oversupply of Chinese oil products in the second half of 2024 would be detrimental to already fragile Asian oil product cracks and refining margins, according to middle distillate marketers at three major South Korean refiners including S-Oil. Platts, part of S&P Global Commodity Insights, assessed the second-month Singapore gasoil swap crack against Dubai crude swaps at an average of $17.4\/b so far in Q3, up from $16.53\/b in Q2 but sharply below the average $22.12\/b in Q1 and 2023 average of $22.82\/b. South Korea's domestic refining margin has recovered to $7.5\/b in the first week of August from a low of $5\/b seen in May but remains sharply below the $15-$20\/b range seen in the first quarter, data from state-run Korea National Oil Corp. showed. In times of fragile demand fundamentals amid lackluster Asian macroeconomic conditions, an oversupply of Chinese oil products would be devastating for the regional light and middle distillates market. Traders across East Asia are all keeping a close watch on how keen Chinese refiners are willing to utilize their export quotas throughout H2, according to oil product trading and marketing sources at South Korean, Japanese, Thai, and Indian refiners. The Chinese government is considering the release of 15 million metric tons (around 112.5 million barrels) of oil product export quotas in September, which will bring the country's total clean oil product export quota to 48 MMt (around 360 million barrels) for 2024, Commodity Insights reported previously. In H1, China exported 19.86 MMt or around 865,000 b\/d of clean oil products comprising mainly gasoline, gasoil\/diesel, and jet fuel, leaving about 13.14 MMt of quotas available for the second half of the year until a new batch of quotas is released. In comparison, South Korea -- Asia's top middle distillate exporter and supplier -- sold 209.76 million barrels or around 1.17 million b\/d of the three products overseas in the first six months. South Korean and Chinese oil products often compete for market share dominance in various Asia-Pacific outlets such as the Philippines and Australia. Chinese traders and refiners may not necessarily fully utilize their export quotas but tepid domestic sales amid China's slowing economic and industrial activities may ultimately encourage them to export as much as they can, according to analysts at Korea Petroleum Association. Among recent economic indicators, China's industrial production grew just 5.1% in July from the previous year, slowing from the 5.3% increase in June, missing forecasts of 5.2% growth and marking the slowest growth rate in four months, latest data from the National Bureau of Statistics showed. \"What we are closely watching out for is that China's struggling construction and property sector could lead to a high volume of gasoil exports [due to weaker domestic sales]... an oversupply would extend the current lengthy downtrend in Asian benchmark crack spreads,\" said a middle distillate marketing manager at a major South Korean refiner. ","headline":"South Korean refiners wary of China's oil product export quota usage amid fragile margins","updatedDate":"2024-08-16T05:32:38.000"},{"Unnamed: 0":25,"body":" Singapore's commercial stockpiles of heavy distillates slipped 8% on the week to a five-week low of 18.1 million barrels in the week ended Aug. 14, Enterprise Singapore data released late Aug. 15 showed, amid higher exports from the world's largest bunkering hub. Stocks were currently at their lowest since the week ended July 10, when they were at 17.8 million barrels, the data showed. From a year earlier, stockpiles in the latest week were down 9.7%, according to the data. Residual fuel inventories in Singapore have averaged at about 20.3 million barrels so far in 2024, compared with a weekly average of 20.4 million barrels in 2023 and 20.9 million barrels in 2022, the data showed. Singapore exported 312,776 metric tons of fuel oil in the week to Aug. 14, up 4.2% on the week, according to the data. Exports to China rose nearly 56% on the week to 99,970 metric tons in the week ended Aug. 14, while outflows to Bangladesh were up 22% at about 36,730 metric tons over the same period, the data showed. Meanwhile, Singapore's fuel oil imports climbed 60.2% on the week to 935,849 metric tons in the week to Aug. 14, with inflows from Asian suppliers accounting for nearly 50% of the total volume at 467,580 metric tons, more than double the regional volume the preceding week, according to the data. The city-state imported about 345,874 metric tons of fuel oil from Malaysia in the week ended Aug. 14, surging from 79,234 metric tons the previous week, and 34,522 metric tons from India, rebounding from nil over the same period, the data showed. Imports from the Middle East slumped for the fourth consecutive week to 35,000 metric tons in the week to Aug. 14, with all shipments originating from Iraq, according to the data. Inflows from Europe more than doubled on the week to 167,852 metric tons in the week ended Aug. 14, while imports from Russia totaled 118,350 metric tons after a two-week hiatus, the data showed. Singapore's inventory data counts only stocks at onshore terminals. Enterprise Singapore describes heavy distillates as \"residues,\" which include cracked and straight-run fuel oil and low-sulfur waxy residue. Bunker demand moderate Downstream demand for low sulfur fuel oil around the Singapore hub has been capped by strong premiums, whereas refueling requirements for high sulfur fuel oil remained more stable, traders said. Although cargo availability in the downstream LSFO market has normalized over the past week, higher flat prices driven by steadier international crude oil rates since the week ended Aug. 8 have also limited shipowners' buying appetite on some trading days. Additionally, more suppliers have emerged with competitive offers for LSFO since the week started Aug. 12, amid improved availability for prompt refueling dates within about eight-day lead times, according to bunker suppliers. \"More [players] are able to offer even for prompt dates, but it is generally still competitive to get orders,\" a Singapore-based trader said, adding that it has been a \"difficult\" market to fix deals with higher crude oil prices and delivered offers still range wide. The Platts-assessed Singapore-delivered marine fuel 0.5%S bunker premium over the benchmark FOB Singapore Marine Fuel 0.5%S cargo value averaged $23.16 per metric ton over Aug. 1-15, above the $14.47\/t for all of July, S&P Global Commodity Insights data showed. HSFO downstream valuations have been more buoyed in recent weeks due to tighter-than-usual barge availability, as healthy term contract nominations and adequate spot demand filled some sellers' barging schedules for prompt refueling dates. Although HSFO inventories have been drawn down decently, stockpiles remain largely ample for the near term. Buyers are also able to meet refueling requirements within eight days ahead and onward, bunker suppliers said. The Platts-assessed Singapore-delivered 380 CST HSFO bunker premiums over the FOB Singapore 380 CST HSFO cargo values averaged at $20.22\/t so far in August, above the $15.12\/t for all of July, Commodity Insights data showed. ","headline":" Fuel oil inventories drop to five-week low on higher exports","updatedDate":"2024-08-16T04:58:58.000"},{"Unnamed: 0":26,"body":" The isomer-grade mixed xylene FOB Korea marker fell to an over 19-month low of $828 per metric ton on Aug. 15 amid ample MX supply from South Korea, a closed arbitrage to the US, poor gasoline sector demand and a slump in downstream prices. Isomer-MX FOB Korea prices were last lower Jan. 4, 2023, when they were at $823\/t, S&P Global Commodity Insights data showed. Market sources attributed the lower MX prices to several factors, including falling paraxylene values, the reduced operating rate at S-Oil's No. 2 PX plant after a fire in July, a closed arbitrage to the US and a slump in gasoline blendstock demand. On top of that, South Korea's Lotte Chemical plans to shut its No. 2 aromatics plant in Ulsan for about two months of turnaround starting mid-September. Lotte Chemical -- a key consumer of isomer-MX in Northeast Asia -- will likely free up more MX for sale in the broader market due to the maintenance. Another sign of weakness in the isomer-MX market is that prices have fallen below those of toluene FOB Korea since the start of August. Typically, MX is priced higher than toluene since toluene is a feedstock for MX. However, toluene FOB Korea closed at a $38\/t premium to isomer-MX FOB Korea on Aug. 15, with the spread reaching a low of negative $47\/t on Aug. 14. Meanwhile, PX physical spot prices also continue to slide. Platts assessed Asian PX down $13\/t on the day at $957.67\/t on Aug. 15, the lowest since June 1, 2023, when it was assessed at $955.33\/t, Commodity Insights data showed. China's sluggish downstream demand remains a major concern, with high polyester inventories leading producers to offer discounted prices to clear stockpiles. Market participants are banking on increased polyester demand in the upcoming winter season, but any potential upside may be limited, a trader in Singapore said. \"But [the fourth quarter] is a low season overall. I hope the market will be better, but [I am] not super optimistic,\" the trader said. Platts last assessed PX CFR Taiwan\/China at $957.67\/t on Aug. 15, the lowest since May 31, 2023, when it was assessed at $957.17\/t, Commodity Insights data showed. ","headline":"Asian isomer-MX prices hit 19-month low amid ample supply, sluggish demand","updatedDate":"2024-08-16T04:06:55.000"},{"Unnamed: 0":27,"body":" Singapore's bitumen exports soared 77.1% on the week to a four-week high of 49,565 metric tons in the week ended Aug. 14, data released by Enterprise Singapore late Aug. 15 showed. This was the highest volume of weekly bitumen exports from Singapore since the week ended July 17, when 67,102 mt bitumen was exported from the Southeast Asian hub, according to Enterprise Singapore data. The city-state exported 10,008 mt bitumen to Thailand in the week to Aug. 14, surging from 1,474 mt in the preceding week, while bitumen exports to Indonesia jumped 83% on the week to 11,040 mt in the latest week, the data showed. Singapore also exported 12,482 mt bitumen to Australia in the week to Aug. 14, against none the week before, and exports to Malaysia climbed 38% on the week to 9,815 mt, the data showed. Singapore\u2019s bitumen exports to China, however, slipped nearly 38% on the week to 6,219 mt in the week to Aug. 14, while there were no bitumen exports to Brunei, and Cambodia for a second straight week, according to Enterprise Singapore data. The Singapore bitumen market has found support in recent weeks amid tight supplies, with trade sources expecting firmer regional demand in the coming months. The FOB Singapore bitumen price, which was assessed at $489\/mt at the Asian close Aug. 15, has averaged at $491\/mt over Aug. 8-14, nearly in line with $491.70\/mt in the preceding week, Commodity Insights data showed. The differential for PEN 60-70 grade bitumen loading in Singapore to the benchmark Singapore 380 CST high sulfur fuel oil, which flipped into a positive territory on July 25 for the first time since late February, has averaged at a premium of $32.95\/mt over Aug. 8-14, compared with an average premium of $40.8\/mt in the previous week, Commodity Insights data showed. ","headline":" Bitumen exports jump 77% on week as outflows to Thailand, Indonesia surge","updatedDate":"2024-08-16T04:01:20.000"},{"Unnamed: 0":28,"body":" Singapore's onshore commercial stocks of middle distillates edged 0.25% higher over Aug. 8-14 to a fresh three-year high at 12.02 million barrels amid weak regional demand, Enterprise Singapore data showed. Gasoil and jet fuel\/kerosene stocks were last higher June 24-30, 2021, at 13.78 million barrels, historical Enterprise Singapore data showed. The city-state remained a net exporter of gasoil Aug. 8-14, with outflows rising 37.92% week on week to 262,817 mt. Malaysia was the top recipient at 96,739 mt, followed by Indonesia and Myanmar at 61,964 mt and 33,139 mt, respectively. Over the same period, gasoil imports fell 33.57% to a seven-week low at 43,666 mt, with inflows last seen lower in the week to June 26 at 42,791 mt, Enterprise Singapore figures showed Aug. 15. South Korea and India were the main suppliers of gasoil at 26,441 mt and 17,225 mt, respectively. In recent spot activity, South Korea's GS Caltex sold 300,000 barrels of 10 ppm sulfur gasoil loading Sept. 12-16 at a discount of 90 cents-$1\/b to the September average of Mean of Platts Singapore 10 ppm sulfur gasoil assessments, FOB Yeosu. \u201cThe award level seems reasonable and within market expectations,\u201d a regional gasoil trader said. Imports of India gasoil Meanwhile, trade sources said the presence of India gasoil imports was an indication of weak demand. \u201cRefiners in India would not typically send cargoes to Singapore unless they can\u2019t send it anywhere else in the West of Suez,\" a regional middle distillates trader said. \"Domestic demand in India must also be quite weak because of the monsoon.\u201d To be sure, India has been sending gasoil to Singapore for six consecutive weeks, with volume totaling 220,985 mt over July 4-Aug. 14. \"The middle distillates market is very quiet these days,\" a second regional middle distillates trader said. \"There is not much demand, and there is still a lot of supply in the region.\u201d Jet fuel exports fall for second straight week Singapore remained a net exporter of jet fuel\/kerosene Aug. 8-14, though outflows slid 75.64% to 13,849 mt, posting two consecutive weeks of decline. Jet fuel\/kerosene exports went to Australia and the US at 7,252 mt and 6,594 mt, respectively, Enterprise Singapore data showed. Meanwhile, jet fuel\/kerosene inflows, mainly from Belgium and Germany, trickled in at just 14.37 mt. In the near term, regional jet fuel\/kerosene supply could lengthen further as China's exports remain strong. China's jet fuel exports in August are estimated at 1.7 million mt, down from about 1.87 million mt in July, following the summer holidays. Sinopec could save more of its export quotas for jet fuel, which has been bringing in steady profits, S&P Global Commodity Insights reported, citing trade sources. The oil giant is targeting exports of 900,000 mt of jet fuel and 400,000 mt of gasoil in August. ","headline":" Middle distillate stocks hit 3-year high at 12.02 mil barrels Aug 8-14","updatedDate":"2024-08-16T00:21:21.000"},{"Unnamed: 0":29,"body":" Colombia's Grupo Ecopetrol confirmed a turnaround is taking place at its Barrancabermeja site in Colombia but did not disclose an exact end date in its Q2 earnings call on Aug. 14. A source closely related to the company said that LDPE production rate is expected to remain at around 30-50% of normal levels until Aug. 25, with normal operational rates being approximately 38,000-48,000 metric tons per year. Ecopetrol has an installed capacity of 66,000 metric tons per year for LDPE at the Barrancabermeja complex. A local player said that domestic LDPE supply is tight, with expectations to return to normal levels by September. Consequently, demand for domestic LDPE in the Colombian market is higher than the current supply levels. Sources estimate that total LDPE demand in Colombia stands at around 80,000 to 120,000 mt per year. Platts assessed spot LDPE at $1,290\/mt delivered Colombia on Aug. 14. Colombian polypropylene producer Esenttia, owned by Grupo Ecopetrol, stated in its quarterly report that in the first half of 2024, PP prices remained low due to a slowdown in demand and high inventories in the market, resulting in sales of 185,400 mt, 23.2% lower than in H1 2023. The company added that sales improved in Q2, especially in June, due to an increase in exports to Brazil, Mexico, Venezuela and Ecuador. Platts, part of S&P Global Commodity Insights, assessed spot import homopolymer prices at $1,230\/mt CFR Brazil and $1,150\/mt CFR WCSA on Aug. 14. Ecopetrol primarily operates in the oil and gas sector, but also participates throughout the hydrocarbon chain, being the sole producer of low-density polyethylene in Colombia. ","headline":"Ecopetrol confirms turnaround at Colombia's Barrancabermeja site","updatedDate":"2024-08-15T23:02:00.000"},{"Unnamed: 0":30,"body":" North Dakota's oil and gas output each fell slightly in June 2024, a function of fewer producing wells during that month, two top state Department of Mineral Resources executives said Aug. 15, although they noted that eastern Montana crude output has recently risen. North Dakota oil production fell by nearly 2% to 1.175 million b\/d, while natural gas production fell by 1% to 3.4 Bcf\/d, Mark Bohrer, Assistant Director of the DMR, said during a monthly production webinar. \"It wasn\u2019t all that surprising, [since] we had 121 fewer wells producing in June than in May,\" Bohrer said, adding that 18,973 wells were producing in June, a preliminary figure. \"And, our [well] completion numbers are still down a little bit.\" Completed wells totaled 79 in July, a preliminary figure, up from 55 in June and 67 in May, according to DMR figures released during the webinar. The larger number of July completions will have \"a positive impact on our production numbers\" when July numbers are released in September, Bohrer said. \"That's a nice uptick,\" Bohrer said of the July figure, adding that 90-100 completed wells per month are needed to grow North Dakota's production. Bakken comprises nearly 90% of producing wells Roughly 16,891 North Dakota wells, or 89%, are Bakken\/Three Forks wells and 2,082 wells, or 11% are from conventional or legacy pools, he said. Rig counts remain relatively low in the state owing to merger activity. According to S&P Global Commodity Insights data, there were 37 rigs active in the Bakken Shale -- the state's major oil reservoir, along with the Three Forks interval. Except for a handful of times when the state's rig count climbed into the 40s or dipped into the 20s, it has stubbornly remained mostly in the 30s for well over a year. M&A activity has also picked up in the Bakken, particularly in July when Devon Energy announced its intention to buy the Williston Basin assets of Grayson Mill Energy. Another notable transaction occurred in May when ConocoPhillips put a ring on Marathon Oil's finger, although these two companies, including Devon, have major operations in other large basins such as the Permian and Eagle Ford Shale. Low rig counts from increased M&A Bohrer attributed the relatively low rig counts in the Bakken to M&A activity, when companies tend to cut back while assessing their total asset portfolio, but said he hoped rig counts would return to the 40s in the next few years. Pre-pandemic Bakken rig counts were in the high 40s and 50s and even touched the low 60s in 2019. Meanwhile, eastern Montana oil production, which also encompasses part of the Bakken Shale, has crept up this year, Justin Kringstad, Director of Pipeline Authority, said. The latest Pipeline Authority figures show that in April 2024, the most recent month available, Montana produced about 71,400 b\/d of crude oil, up about 20% from 59,200 b\/d in January 2024. Kringstad did not immediately explain why Montana production had jumped. For the last 18 months or so it has been in the high 50,000s b\/d or 60,000s b\/d. Additionally, the state's crude oil movements were impacted by refineries entering planned maintenance, such as Marathon's Mandan Refinery which went down for a turnaround for the first time in seven years in June. The refinery resumed operations in late July, early August, Kringstad said. \"Where we saw the uptick was on pipeline movements, excess space that was available in our crude oil transportation network largely took all of that excess production that wasn't going to the refinery in that time frame,\" he said. The US West Coast accounted for majority of the crude rail transportation out of North Dakota, according to the DMR. ","headline":"North Dakota oil, gas production each falls slightly in June 2024: DMR","updatedDate":"2024-08-15T22:36:32.000"},{"Unnamed: 0":31,"body":" US Gulf Coast LPG Very Large Gas Carrier prices to both Chiba, Japan and Northwest Europe jumped on Aug. 15, while premium FOB prices fell from multiyear and multimonth highs. Platts assessed FOB propane, butane, and the propane\/butane blend down 3 cents\/gal, closing at 23 cents\/gal, 21 cents\/gal and 23 cents\/gal respectively. The lower prices led to FOB propane falling from four-year highs, while the butane and propane\/butane blend fall from all-time highs since Platts began to assess them in September 2021. VLGC freight to Chiba, Japan spiked on the day as it closed at $108 per metric ton, rising $16\/mt on the day. The cost of shipping to Northwest Europe followed in suit, moving up $9.00\/mt to $61.00\/mt. LPG shipping market participants said the arbitrage between Houston to Japan narrowed on the day, potentially acting as one of many factors that contributed to the rising freight costs. The US Department of the Treasury has imposed new sanctions on companies, ships and an individual involved in trading Iranian oil and LPG to finance Houthi rebels' attacks on commercial ships in the Red Sea. The fresh round of sanctions come after multiple attacks took place on Aug. 13 on a Liberian-flagged oil tanker in the Red Sea. However, it is not clear if there is a correlation between the new sanctions and the rising VLGC freight prices. S&P Global Commodities at Sea data showed that 21 VLGC ships are presently in transit to the Far East, carrying 11.8 million barrels of propane. The Port of Chiba in Japan will receive 2.3 million barrels of propane between Aug. 31 until Sept. 2. Meanwhile, four VLGC ships are in route with 2.2 million barrels of propane going towards Northwestern Europe. Port Terneuzen in the Netherlands will receive two shipments of propane on Aug. 27 and Aug. 30, totaling up to 1.6 million barrels. In Belgium, 556,900 barrels will be discharged at Port Antwerp on Aug. 31. US exports of propane and propylene were down in the week ending Aug. 9, falling 131,000 b\/d to 1.517 million b\/d, Energy Information Administration data showed Aug. 14. ","headline":"US Gulf Coast LPG FOB prices weaken from highs","updatedDate":"2024-08-15T21:34:25.000"},{"Unnamed: 0":32,"body":" The US oil and gas rig count jumped by six to 638 for the week ended Aug. 7, an S&P Global Commodity Insights analysis showed, as drilling activity changed little across the eight largest unconventional basins and the total count remained rangebound. Rig count additions came from the oil side, as these rigs totaled 540, up six on the week, as rigs chasing natural gas remained static at 98, the Aug. 15 analysis showed. Oil rigs haven't changed appreciably in 2024; they began the year at 543. In contrast, gas-directed rigs accounted for most of the drop this year, falling by 36 after beginning January at 134. For the rest of 2024, the rig count should be \"mildly upward,\" Imre Kugler, upstream research and analysis director for S&P Global Commodity Insights, said. \"It appears that group is happy to take efficiency gains as additional profits, not as production growth fuel.\" Independent E&Ps have made midyear adjustments and should hold \"pretty steady\" for the rest of this year, Kugler said. \"Private companies, particularly the very small ones, have regained confidence in the past two months and likely will account for the handful of rig increases for the rest of 2024.\" Conservative behavior seen for oil-focused E&Ps A long-awaited LNG demand pickup is projected in 2025, so natural gas operators \"should respond by both unwinding curtailments and should account for half of rig additions for [that] year,\" he said. \"We expect pretty conservative behavior for oil-focused operators, still pursuing cash flows, a shrinking pool of aggressive and sizable private companies and overall moderate rig increases.\" The domestic rig count has been rangebound in the 630s since mid-May, after starting the year at 677. In Q1, the rig count averaged 662; in Q2 it dropped to an average 641 and so far in Q3 the average has been 633. \"This scenario seems like [a trough],\" Kugler said. \"We are approaching \u2013 but not reaching \u2013 the level of rigs required to just keep production flat. We don\u2019t expect further drops from independents that made their adjustments in Q2. Smaller companies are adding rigs, so we are likely at the bottom.\" US oil production for May was just below 13.2 million b\/d, down from its all time monthly high in December 2023 of 13.3 million b\/d. In addition, the Lower 48 continues to experience high levels of rig churn, James West at Evercore ISI Group said in his latest monthly of Onshore Oracle report Aug. 15. Rig churn is normal turnover as equipment contracts expire and other operators pick up those units, which enables relatively steady activity. \"The impact from customer consolidation, low natural gas prices, and the majors and large publics controlling more of the industry activity is being felt in the active rig count,\" West said. \"Transactions are still closing, and more likely operators will wait until they form 2025 plans to determine their rig needs.\" As a result, a second-half 2024 rig count recovery is \"unlikely,\" he said. Budget exhaustion possible West added he expects some budget exhaustion as the end of the year approaches. \"[We] would not be surprised if E&Ps take some additional time to announce budgets in 2025,\" he said. \"We anticipate that the North America land recovery will begin to come through in the second half of 2025.\" Large merger and acquisition transactions have occurred in the past year, such as ExxonMobil's takeover of big Permian Basin producer Pioneer Natural Resources in May, and combinations of Chevron\/Hess and ConocoPhillips\/Marathon Oil are pending. Typically after a merger closes, the surviving company typically drops a rig or two as it digests the assets and works to optimize and high-grade its drilling program. ExxonMobil was running about 16-17 rigs in the Lower 48 prior to taking Pioneer under its wing, although its rig count more than doubled with the addition of the acquired company's rigs to 38. In the last few weeks it has run 36-37 rigs. Other mergers involving larger E&Ps that are in process are Diamondback Energy acquiring Endeavor Energy, and Devon Energy taking over Grayson Mill Energy's Williston Basin segment. For the week ended Aug. 7, The Marcellus Shale was up to rigs to 21, while the Utica Shale lost two rigs leaving eight. Two basins, the SCOOP-STACK play and DJ Basin, each gained a rig, making 23 and 11 rigs respectively. Three basins shed one rig apiece, leaving the Permian, at 297, the Eagle Ford Shale at 52 and the Williston at 37. The Haynesville Shale remained stable at 41. ","headline":"US oil, gas rig count jumps 6 to 638, as drilling activity remains rangebound","updatedDate":"2024-08-15T20:29:00.000"},{"Unnamed: 0":33,"body":" Crude oil futures settled higher Aug. 15 as stronger-than expected US economic data offset a mixed bag of indicators out of China released overnight. NYMEX September WTI settled $1.18 higher at $78.16\/b and ICE October Brent climbed $1.28 to $81.04\/b. US retail sales climbed 1% in July from the month prior, Census Bureau data showed Aug. 15, exceeding market expectations and marking the biggest increase since January 2023. The strong retail sale report offered a bullish counterpoint to data released by the Chinese National Bureau of Statistics Aug. 15 that revealed a mixed picture of firming consumer spending against softer factory output. China's retail sales rose 2.7% on the year in July, narrowly beating an estimate of a 2.6% increase, NBS data showed. While the uptick in retail figures was seen as a positive signal of stabilization in the Chinese economy, a slide in industrial production growth dampened market optimism. China's industrial production rose just 5.1% in July from the previous year, slowing from the 5.3% increase in June and missing forecasts of 5.2% growth. \"Growing demand in developed economies, such as the US, has been compensating for slackness in China,\" ANZ Research said. Meanwhile, China's crude throughput continued its downtrend in July, falling 6.1% on the year and 2% from June to a 21-month low of 13.96 million b\/d, or 59.06 million metric tons, NBS data showed. This was the first time the volume dropped below the 14 million b\/d mark since the previous low of 13.86 million b\/d in October 2022. NYMEX September RBOB settled 3.69 cents higher at $2.3580\/gal and September ULSD climbed 97 points to $2.3779\/gal. ","headline":" Crude prices climb as strong US retail sales boost confidence","updatedDate":"2024-08-15T20:25:00.000"},{"Unnamed: 0":34,"body":" Argentina's refinery utilization rate fell to 80.8% in June from 82.4% a year earlier, led by a decline in diesel and gasoline production, state-run statistics department Indec said Aug. 15. The rate was down from 84.1% in May, Indec said. Gasoline output fell 5.4% year on year in June , and diesel tumbled 6.8%, Indec said Aug. 8 in a separate report. Argentina has about 560,000 b\/d of installed refining capacity, but demand generally runs at 525,000 b\/d. All of the crude is supplied domestically from fields that produced an average of 660,000 b\/d in June. Refiners must import additional supplies of higher-grade products because of the lack of capacity to make them. ","headline":" Refinery utilization slips to 80.8% in June, government says","updatedDate":"2024-08-15T20:13:25.000"},{"Unnamed: 0":35,"body":" Shell Offshore, a subsidiary of Shell, announced Aug. 15 it has made a final investment decision to implement a \u201cwaterflood\u201d project at its US Gulf of Mexico Vito field. The process is slated to begin in 2027, Shell said, and involves injecting the reservoir with water to displace additional oil in order to re-pressurize the reservoir and enhance the field\u2019s volume capacity. \u201cOver time, we\u2019ve seen the benefits of waterflood as we look to fill our hubs in the Gulf of Mexico,\u201d said Zo\u00eb Yujnovich, Shell Integrated Gas and Upstream Director. \u201cThis investment will deliver additional high-margin, lower-carbon barrels from our advantaged Upstream business while maximizing our potential from Vito.\u201d The Shell announcement comes on the heels of Chevron on Aug. 12 announcing it has started production at its Anchor deepwater project. The Anchor semi-submersible floating production unit has a design capacity of 75,000 b\/d of oil and 28 MMcf\/d natural gas, Chevron said. US Gulf of Mexico crude output is expected to decline by 1.8% on the year to 1.83 million b\/d in 2024 from 1.863 million b\/d in 2023, S&P Global Commodity Insights data showed, but is expected to climb to 1.969 million b\/d in 2025. ","headline":"Shell reaches FID on waterflood project at US Gulf Vito field","updatedDate":"2024-08-15T19:31:25.000"},{"Unnamed: 0":36,"body":" Bermuda-based drilling operators Borr Drilling has committed its entire fleet with two newbuilds expected to see delivery later this year, executives said Aug. 15. The company noted that it continues to secure new contracts, which have offset the impact of the suspension of over 15 rigs in Saudi Arabia seen earlier in the year. \"We currently have about 73% of our capacity contracted, which aligns with our expectations for this time of the year,\" CEO Patrcik Schorn said during the company's second-quarter earnings call. \"All our 22 delivered rigs are contracted with only a few days left remaining available in 2024.\" So far in 2024, the company has secured 14 new commitments, which adds nearly 10 rig years and $651 million in backlog at market rates, Bruno Morand, vice president of commercial and business development, said. The company has reached 92% coverage with their fleet as a result of a nearly fully contracted fleet, averaging a day rate of $135,000\/day. Looking ahead, the company's contracted coverage for 2025 has already reached 70% and could increase to 73% at an average day rate of $148,000\/day. The strength in new contractual commitments offset Aramco's suspension of 22 modern rigs seen this year, which came after the company postponed its offshore expansion projects. Of the suspended rigs, five have already been re-contracted. Borr expects that only 12 of the 17 rigs remain suspended. \"Three months after Saudi Aramco suspended 22 jackups, the knock-on effect on the market here is becoming clearer,\" a Petrodata by S&P Global Commodities Insights report from July notes. \"Until all the suspended units return to work for Aramco, are scrapped or find alternative charters, the market will likely see more of the excess supply compete with the region's existing fleet.\" According to the report, the suspended units were being re-contracted to locations in Southeast and Far East Asia. Additionally, fleet demand was tight globally as majority of rigs were aging and the industry hasn't seen an order for a newbuild in nearly a decade, Schorn said. \"The global jackup fleet age profile with now 30% of the rigs being over 35 years old is expected to drive incremental retirements, coupled with the fact that no new rigs have been ordered in the past decade, these conditions create a favorable environment for our company,\" he added. Borr, which operates the youngest fleet of 24 premium rigs in the industry, forecasts an incremental demand of 15 to 20 rigs in the next 12 to 18 months. Petrodata shows the current global jackup rig count at 363, and sees Middle East demand continuing to decrease through the year to about 150 to 153 rigs, while demand in Southeast Asia is expected to average 34.4 units this year. In 2025, jackup rig demand is forecast to reach 155 to 157 and 39.7, respectively. According to Petrodata, there are three jackup rigs to be delivered this year, two of which could belong to Borr Drilling. Vale, one of Borr's newbuild jackup rigs, was delivered on Aug. 15, but Borr declined to comment on its contractual commitment or where it was headed. According to Petrodata, the Vale is supposed to head to Libya in early January 2025. Borr's final jackup newbuild for the year, Var, remains on schedule to be delivered in late Q4. ","headline":"New contractual commitments offset Aramco suspensions in Q2: Borr Drilling","updatedDate":"2024-08-15T19:25:45.000"},{"Unnamed: 0":37,"body":" The United States Department of Energy has completed its latest purchase for the Strategic Petroleum Reserve, adding 1.5 million barrels of crude to the emergency stockpile. The agency's purchase fulfilled a solicitation first announced Aug. 6. The barrels are scheduled for delivery January 2025 to the DOE's Bayou Choctaw site in Louisiana, fulfilled by ExxonMobil (1 million barrels) and Shell (500,000). While it did not disclose the latest purchase price, as ever, DOE touted the \"good deal for taxpayers\" the deal represented. In 2022, US President Joe Biden released 180 million barrels from the SPR in response to Russia's invasion of Ukraine, at an average price of $95\/b. DOE has since directly repurchased 45 million barrels at an average price of $77\/b. As of Aug. 2, the SPR held 375 million barrels, down from the 638 million it held in January 2021, when Biden took office. Alongside cancellations of 140 million barrels of congressionally mandated sales from 2024 to 2027, the agency has now accounted for all of the crude it sold in 2022. Meanwhile, DOE announced another pending solicitation for 6 million barrels, to be delivered to the recently renovated and reopened Bryan Mound site in January, February and March of 2025. The agency initially announced that it wanted to purchase 2 million barrels, but expanded that guidance Aug. 12. Bids are due no later than August 20. \"The Biden-Harris Administration is opening up more capacity for potential return in 2025 as market conditions have shifted in favor of the taxpayer,\" a DOE spokesperson said. ","headline":"Biden administration finalizes latest SPR purchase, adds 1.5 million crude barrels","updatedDate":"2024-08-15T19:19:59.000"},{"Unnamed: 0":38,"body":" Brazilian state-led oil company Petrobras plans to invest $158 million to restart fertilizer production at the idled Araucaria Nitrogenados, or ANSA, fertilizer plant in Parana state amid ongoing efforts to boost fertilizer output in Latin America's biggest economy, the company said Aug. 15. \"The fertilizer sector is of strategic importance to the country and Petrobras, allowing the diversification of the company's business, integration of the natural gas supply chain and actions to reduce carbon emissions in line with the energy transition,\" CEO Magda Chambriard said during an event to kick off the restart. Petrobras plans to restart fertilizer production at ANSA -- which was shuttered in 2020 during the global coronavirus pandemic -- in the second half of 2025, according to the company. ANSA has installed capacity to produce 720,000 metric tons\/year of urea and 475,000 mt\/year of ammonia, as well as up to 450,000 cu m\/year of gasoline additive ARLA 32. Initial activities to restart production at the plant have already started, Petrobras said. \"The plant is in the process of hiring services and acquiring materials, with an estimate for local content of more than 85%,\" Petrobras said. \"After this step is completed, contracts for services and equipment maintenance will be mobilized for the start of activities.\" Petrobras had previously intended to sell ANSA under its asset-sales program, but removed the facility as well as other fertilizer plants and projects from the sales process in 2022. The return of activity at ANSA represented the latest move by Petrobras to return to Brazil's fertilizers industry amid a strategy shift implemented by administration of Luiz Inacio Lula da Silva and his ruling Workers' Party, or PT. Lula, and the PT favor a state-led model for economic development that includes heavy investments by major companies such as Petrobras, often using state companies as investors of last resort. The Lula administration overhauled executive management and Petrobras' board of directors, halted the company's asset-sales program and ended the use of import-parity pricing. In addition, Petrobras raised investment spending to $102 million under its five-year plan for 2024-2028. Chambriard highlighted potential investments in fertilizers shortly after taking the top job at the state-run company in May. \"Brazil imports about 80% of the fertilizers it consumes, and a large part of this volume is nitrogen fertilizers made with natural gas,\" Chambriard said. \"Petrobras sells gas. If it has a product that makes sense to sell to make fertilizers, we want to help develop the market.\" In addition to the ANSA restart, Petrobras' fertilizer investments also include plans to complete construction of the Unidade de Fertilizantes Nitrogenados, or UFN-III, fertilizer plant at Tres Lagoas in Mato Grosso do Sul state by 2028. Work on the plant, which was planned to produce 2,200 t\/d of ammonia and 3,600 t\/d of urea, was halted in 2014 at about 80% complete. Petrobras also signed a tolling contract in January with local petrochemicals producer Unigel Participacoes to produce fertilizers at two idled plants in Bahia and Sergipe states. Unigel had been operating the plants under a 10-year lease signed in 2019, but the company was forced to suspend operations in 2023 amid a spike in gas prices and other terms related to the deal. The tolling contracts, however, have been suspended amid questions by federal auditors. The Fabrica de Fertilizantes-Bahia, or FAFEN-BA, has installed capacity to produce about 1,300 mt\/d of urea as well as gasoline additive Arla 32 and ammonia. The Fabrica de Fertilizantes-Sergipe, or FAFEN-SE, fertilizer plants in Sergipe state can produce up to 1,800 mt\/d of urea. ","headline":"Brazil's Petrobras kicks off work to restart ANSA fertilizer plant","updatedDate":"2024-08-15T19:06:22.000"},{"Unnamed: 0":39,"body":" GeoPark plans to step up oil production the Llanos basin in Colombia after positive exploration results, while it expands output in Argentina\u2019s Vaca Muerta shale play, executives of the Latin America-focused company said Aug. 15. \u201cWe expect to drill three to five new wells before the end of the year,\u201d CEO Andr\u00e9s Ocampo said about its activities in Llanos, on a conference call with investors. The Bogot\u00e1-based company was producing 35,500 b\/d in the second quarter of this year, according its data. The company is also widening its exploration to make new discoveries for future growth in the Llanos basin, with several finds recently made near its productive Llanos 34 and CPO-5 blocks. The finds there have increased in production to up to 1,800 b\/d from from as little as 100 b\/d at the start of 2023. Vaca Muerta development 'encouraging' In Argentina, GeoPark is working with London-based Phoenix Global Resources on developing several blocks in the Vaca Muerta shale play, where the results so far have been \u201cencouraging,\u201d said Rodrigo Dalle Fiore, the firm\u2019s new development and portfolio director Mata Mora Norte is producing 12,500 b\/d, and the partners have put into production a fourth pad of four wells that should take output from the block to 13,000-14,000 b\/d by the end of this year, Delle Fiore said. The partners are also exploring neighboring Confluencia Norte with a three-well drilling pad that it aims to complete in October and test production by the end of the year. GeoPark is seeking to increase its Vaca Muerta production to 40,000 boe\/d and 60,000 boe\/d over the next five years. ","headline":"GeoPark aims to boost oil output in Argentina, Colombia: execs","updatedDate":"2024-08-15T18:30:24.000"},{"Unnamed: 0":40,"body":" The US Department of the Treasury announced a fresh round of sanctions on companies, ships and one individual involved in trading Iranian oil and LPG used to finance the Houthi rebels' attacks on commercial ships in the Red Sea, as well as one company accused of shipping LPG on behalf of Hezbollah in Lebanon. The sanctions come after multiple attacks Aug. 13 on a Liberian-flagged oil tanker in the Red Sea that were confirmed by the Joint Maritime Information Center. Regional tensions stemming from the Israel-Hamas war continue to threaten oil supply routes. \"We will continue to use the tools at our disposal to deprive the Houthis of revenue to carry out their attacks on international shipping, and we will continue to confront Iran's enabling Houthi attacks,\" US State Department Principal Deputy Spokesperson Vedant Patel said Aug. 15 in a statement. Iran's oil output holds steady The actions are the latest attempt to stifle the network of Houthi financial official Sa'id al-Jamal. Treasury says the network is backed by the Islamic Revolutionary Guard Corps-Qods Force and is responsible for financing the Houthis' attacks on shipping and civilian infrastructure in the Red Sea. The latest vessel sanctions name the LPG Om, Divine Power, and Raha Gas, whose captain, Arif Ibrahim Khot, was also designated. Separately, Treasury sanctioned Kai Heng Long Global Energy Limited, which it said was the \"ship manager, operator and registered owner\" of two ships that the Lebanese Hezbollah-controlled Talaqi Group used to ship tens of millions of dollars worth of LPG to China. Four of its vessels, Fengshun, Victoria, Lady Liberty and Parvati, were sanctioned. \"Today's action underscores our continued commitment to disrupting Iran's primary source of funding to its regional terrorist proxies like Lebanese Hizballah and the Houthis,\" Bradley Smith, acting under secretary of the Treasury for terrorism and financial intelligence, said in a statement. \"Our message is clear: those who seek to finance these groups' destabilizing activities will be held to account.\" Despite the continuing drumbeat of US sanctions on Iran's oil industry, more of the country's crude output continues to make its way to market. The latest Platts OPEC+ survey by S&P Global Commodities Insights has Iranian crude production at 3.2 million b\/d in July, steady from June but up from 2.7 million b\/d in July 2023. ","headline":"US targets LPG ships in latest sanctions aimed at Houthis, Hezbollah","updatedDate":"2024-08-15T18:13:06.000"},{"Unnamed: 0":41,"body":" A.P. Moller-Maersk, one of the world's largest marine energy consumers, has launched a study with Lloyd's Register and Core Power on how to regulate nuclear energy in maritime applications, according to a joint statement released on Aug. 15. The involved parties said they will investigate safety requirements and aim to understand more about nuclear energy in terms of operational and regulatory needs in a bid to reduce greenhouse gas emissions. The study will focus on the regulatory feasibility and frameworks that would need to be established for a nuclear container ship using a fourth-generation reactor to undertake cargo operations at a European port. \u201cNuclear power holds a number of challenges related to, for example, safety, waste management, and regulatory acceptance across regions,\u201d said Ole Graa Jakobsen, head of fleet technology at Maersk. \u201cSo far, the downsides have clearly outweighed the benefits of the technology. \u201cIf these challenges can be addressed by development of the new so-called fourth-generation reactor designs, nuclear power could potentially mature into another possible decarbonization pathway for the logistics industry 10 to 15 years in the future.\u201d Nuclear power is a low-carbon energy, but its applications in merchant shipping have been limited. Relevant safety and environmental regulatory frameworks are yet to be fully established. \u201cA critical key to unlocking the vast potential for nuclear energy [for shipping] \u2026 is the standards [regulator] framework for commercial insurability,\u201d said Mikal Boe, CEO of Core Power, a nuclear technology firm. Nick Brown, CEO of Lloyd's Register, one of the largest classification societies, said \u201cnuclear propulsion shows signs of playing a key role\u201d on the industry's \u201cmulti-fuel pathway\u201d toward the International Maritime Organization's net-zero emissions target by 2050. When biofuels are excluded, S&P Global Commodity Insights expects low-carbon energy sources, like ammonia, to make up 33.2% in the global bunker mix in 2050, compared with 0.6% in 2023. ","headline":"Maersk, Core Power and LR launch study on marine nuclear power regulation","updatedDate":"2024-08-15T17:59:16.000"},{"Unnamed: 0":42,"body":" Crude oil output from production sharing fields in Brazil's offshore subsalt region jumped 14.2% year on year in June, rising to the second-highest level ever recorded to fall just short of the output record set in January, government subsalt management company Pre-Sal Petroleo SA, or PPSA, said Aug. 15. The eight fields covered by production-sharing contracts pumped 1.006 million b\/d in June, up from 881,000 b\/d in June 2023, PPSA said in its latest production report. That was second-largest subsalt production volume since the fields pumped 1.009 million b\/d in January. June's production-sharing output also advanced 2.8% from the 978,850 b\/d produced in May. The production surge also pushed the government's share of profit oil to a fresh record high, topping the previous mark set in May, PPSA said. Brazil's portion of production sharing output was 65,940 b\/d in June, up 56.3% from 42,180 b\/d in June 2023. June's share of profit oil also advanced 24.5% from the May's 52,970 b\/d. Brazil's government received more profit oil after recent adjustments to accounting at the Mero field in the Libra production sharing area, where recovery costs were reduced during the month, PPSA said. Mero accounts for about 73% of the country's total profit oil from production-sharing fields. The jump in production-sharing output was attributed to growth at the Atapu field, which was boosted by improved performance by the FPSO P-70 floating production, storage and offloading vessel that handles production from the medium-oil producer, PPSA said. In addition, state-led oil company Petrobras and its partners recently completed a series of maintenance shutdowns at subsalt FPSOs. Petrobras typically concentrates maintenance shutdowns in the first quarter of each year, according to the company. The first quarter in Brazil is usually the weakest for domestic demand because of the fallow season between sugarcane and oil seed harvests, which start in March-April each year depending on weather conditions. The work partially offset the ongoing ramp-up of FPSOs installed over the past 18 months, the PPSA data showed. Petrobras and its partners installed the FPSO Sepetiba at the Mero field on Dec. 31, 2023; the FPSO P-71 at the Itapu field in December 2022; and the FPSO Almirante Barroso at the Buzios field in May 2023. In 2024, Petrobras and its partners plan to install the FPSO Marechal Duque de Caxias at the Mero field. The FPSO, which has installed capacity to produce 180,000 b\/d and process 12 million cu m\/d, is expected to pump first oil in the second half of the year. The FPSO arrived offshore Brazil on May 27. The expected production growth as the recently installed FPSOs reach full output capacity is expected to drive subsalt output and the government's slice of profit oil even higher in 2024, according to interim PPSA CEO Tabita Loureiro. \"Our studies indicate that, by the end of the year, we should reach nearly 100,000 b\/d\" worth of profit oil, Loureiro said. Buzios, Mero lead production Buzios and Mero remained the top two subsalt fields in terms of production in June, although output remained mixed at Mero, the PPSA report showed. Buzios produced 509,990 b\/d in June, up from 459,000 b\/d in June 2023, PPSA said. June's oil output from Buzios also advanced 6.9% from 477,190 b\/d in May. Brazil receives 23.24% of profit oil from Buzios, which represented 7,100 b\/d in June. Mero, meanwhile, produced 240,860 b\/d in June, up 15.2% from 209,000 b\/d in June 2023, PPSA said. June's oil output from Mero, however, fell 6.3% from the 256,930 b\/d pumped in May. Brazil's government receives a 41.65% share of profit oil from Mero, which represented 51,620 b\/d in June. Production from the Sepia field was 95,680 b\/d in June, down 5.3% from 101,000 b\/d in June 2023, PPSA said. June's oil output, however, was relatively stable compared to May's 96,680 b\/d. Brazil gets 37.3% of profit oil from Sepia, which was 2,020 b\/d in June. The Itapu field produced 73,030 b\/d in June, more than double the 36,000 b\/d produced at the field in June 2023, PPSA said. June's oil output also advanced 1.5% from 71,930 b\/d in May. First oil from Itapu was pumped in December 2022. Brazil's government received 840 b\/d in profit oil from the field in June. Output from the Atapu field also rebounded in June, climbing 16.4% to 76,830 b\/d versus 66,000 b\/d in June 2023, PPSA said. June's oil output also rose 16.2% from May's 66,130 b\/d. Brazil receives 31.68% of profit oil from Atapu, which represented 1,380 b\/d in June. Natural gas production, meanwhile, retreated in June from the fresh record high registered in May, PPSA said. Gas production has bounced back after the recent completion of a workover at the Mexilhao gas field platform. Mexilhao acts as a natural gas export hub for subsalt fields further offshore, connecting the light-and-medium oil producers to the 15 million cu m\/d Route 1 export pipeline and a Petrobras-operated gas treatment facility at Caraguatatuba in Sao Paulo state. Brazil's subsalt production-sharing fields yielded 3.721 million cu m\/d in June, up 37.9% from 2.698 million cu m\/d in June 2023, PPSA said. June's gas output, however, fell 0.6% from the record 3.744 million cu m\/d set in May. The government's share of gas production was 113,320 cu m\/d in June, down 6.4% from 121,060 cu m\/d in May, PPSA said. ","headline":" June production-sharing oil output jumps 14.2% on year","updatedDate":"2024-08-15T16:54:03.000"},{"Unnamed: 0":43,"body":" The aviation industry's need to use all available solutions and measures to decarbonize has earmarked Brazil as a prospective world-leading producer of sustainable aviation fuels (SAF), thanks to its unique natural endowments and existing experience with biofuels. S&P Global Commodity Insights interviewed Andre Defaveri, director of new business development for Latin America at US technology firm Honeywell UOP, who thinks opportunities for the adoption of alcohol-to-jet technology by the local ethanol industry are very clear, despite the challenges in taking projects on the drawing board through the construction and financing cycle. \"The hydroprocessed esters and fatty acids technology was the first wave of projects. But Honeywell has already announced four global initiatives using ethanol, and our belief is that this second wave could supply the worldwide market,\" Defaveri said in the interview. Following is a Q&A lightly edited for clarity. S&P Global: US investments in SAF seem closely tied to the Inflation Reduction Act . What challenges do the elections pose to the industry? Andre Defaveri: US regulations [for SAF] are very clear. There is concrete legal support for the projects to move forward, and global demand is already in place due to the pledge made by the International Air Transport Association and its members. Of course, regulations and incentives are still required to build the industry, but the demand alone creates a very strong foundation for what it needs to establish itself. It is important to understand that a biorefinery for SAF production is not the type of plant that will be online for a short period of time. Look at the refineries that are in operation in Brazil, of which many date back to the 1970s, and how many governments we have had. On a global scale, century-old refineries have gone through different governments, and they are still well-established. S&P Global: In Brazil, there is a consensus that the next step for the SAF industry is the approval of the Fuel of the Future program. What is the status of this bill, and what will change after it gets greenlighted? Andre Defaveri: It will be a major landmark for the industry. Of course, other needs will arise, but this is the first milestone to be met. I believe the government knows how urgent the approval is for the country not to lose potential projects because businesspeople seek legal certainty and to invest in a place where they know the rules. I believe the bill will provide a solid basis for investors, and it is very necessary so that we do not lose our opportunity to transform Brazil into a producer and exporter of SAF. S&P Global: Is this 1% mandate capable of boosting the SAF industry in Brazil? Andre Defaveri: It is an important step towards making Brazil a consumer of SAF, yes. This regulation not only reduces emissions by 1%, but also sets how much these emissions will be reduced over time and, consequently, how much of an increase in the percentage of SAF use will be necessary. It is crucial for the success of the industry in Brazil. S&P Global: Why is book & claim so fundamental to the development of the Brazilian SAF industry? Andre Defaveri: I see it having a very strategic role for Brazil, as a country with ample feedstock availability and the capacity to produce high levels of SAF. It is an alternative for companies to use the largest quantity of the fuel here, avoiding the need to transport the molecule over long distances to reach other destinations and then sell the carbon credits in regulated markets. The book & claim system still needs to reach great maturity \u2013 it is related to the carbon market, the carbon price \u2013 but it is an important tool to help Brazil become a strategic player in the industry. S&P Global: Large Brazilian sugarcane millers have yet to reveal any ethanol-based SAF projects. Is there any expectation of an announcement by one of the Brazilian sugar-alcohol companies, or will this sector remain a supplier of feedstock to international clients? Andre Defaveri: The HEFA technology was the first wave of projects. But Honeywell has already announced four global initiatives using ethanol, and our belief is that this second wave could supply the worldwide market. Brazil and the US, as the two largest ethanol producers, are indeed capable candidates for alcohol-to-jet SAF. That could be both from first- or second-generation ethanol, because the technology itself makes no distinction \u2013 the ethanol molecule is what counts. There is indeed a huge opportunity for ethanol producers to have a product with a much higher added value than the biofuel they currently produce. It is a window of opportunity that brings with it the expectation that more ATJ projects will be announced soon. S&P Global: The expansion of corn-based ethanol production in Center-West Brazil has leveraged multiple logistical investments, from the expansion of the pipeline operated by Logum to a boost in volumes transferred by railway. Could something similar happen as an offshoot of the SAF industry? Andre Defaveri: Our expectation is that the industry will identify the bottlenecks and prepare itself to be able, particularly for exports, to deliver the fuel with the least possible environmental impact. The main concern is the final product's carbon intensity, keeping in mind all the stages from the carbon being captured from the air up until the bio-jet fuel reaches the aircraft. The more efficient the production chain and the logistics infrastructure, the lower the level of CO2 emissions. S&P Global: From its conception to the testing and implementation phase, how long does it take for the first drop of SAF to fall? Andre Defaveri: It is hard to give you a precise answer. But these are projects that generally take around four to five years until implementation. You must look at the construction of a SAF biorefinery as an oil refinery. It does not have the same speed as an ethanol plant. There are economic, technical, and engineering studies to develop the concept and construction of a biorefinery. These are complex processes that require time for all equipment to be in place. There is also investor's appetite for risk, which changes a lot from region to region in the world. One may need more studies to make an investment decision than the other. Acelen's plan today is to have its plant in operation by the first quarter of 2027. Petrobras announced a project at a different speed, and there are other companies evaluating how to take advantage of Brazil's potential as producer-exporter of SAF, thanks to its feedstock availability. The expectation is that we are going to see more announcements and that we in Brazil will be able to surf this wave. Acelen is an energy firm created by Mubadala Capital, the asset management subsidiary of Mubadala Investment Company, Abu Dhabi's sovereign wealth fund. Petrobras is Brazil's state-led oil company. ","headline":" Honeywell UOP says alcohol-to-jet could lead second wave of sustainable aviation fuel projects","updatedDate":"2024-08-15T16:13:28.000"},{"Unnamed: 0":44,"body":" Nigeria and Equatorial Guinea have signed an agreement to develop a gas pipeline along the borders of the two countries for the supply of gas from Nigeria. Nigerian President Bola Tinubu and his counterpart from Equatorial Guinea, Teodoro Nguema Mbasogo, signed the agreement Aug. 14 in Malabo on the Gulf of Guinea pipeline project designed to help commercialize some of Nigeria\u2019s untapped gas resources. It was a follow-up on an earlier agreement signed by the two countries on the development of the offshore pipeline project in 2022, Ajuri Ngelale, spokesperson for the Nigerian president, said in a statement. The pipeline could help bolster the supply of gas feedstock to Equatorial Guinea's one train, 3.7 million metric ton\/year capacity LNG plant located on Punta Europa site on the island of Bioko. The agreement, according to Ngelale, covers legislative and regulatory measures for the gas pipeline, establishment and operation, transit of gas, ownership of the gas pipeline, and general principles. The statement quoted President Tinubu, who is currently on a three-day official visit to Equatorial Guinea, as saying that the signing of the agreement would open up new opportunities for gas exploration and employment. Nigeria and Equatorial Guinea share a common maritime boundary linked by close exclusive economic zones. Nigeria, Africa's biggest oil producer, has one of the world\u2019s largest proven gas reserves at 209 Tcf, according to official estimates. However, the country burns off vast amounts of associated gas produced due to a lack of infrastructure to make use of it. Equatorial Guinea, on the other hand, hopes to transform its Punta Europa site into a Gas Mega Hub that would aggregate gas discoveries from across the region -- from Nigeria and Cameroon in particular -- for export to global markets. According to data from S&P Global Commodity Insights, Equatorial Guinea has exported some 2 million mt of LNG so far in 2024. Last year, its LNG exports totaled 2.7 million mt. ","headline":"Nigeria, Equatorial Guinea sign key gas pipeline agreement","updatedDate":"2024-08-15T15:20:12.000"},{"Unnamed: 0":45,"body":" Iverson eFuels has partnered with Stavanger's port authority and others to develop a green ammonia bunker project in western Norway, the project developer said, aiming to supply the novel fuel to shipping companies within this decade. In a statement, the joint venture between Hy2gen, Trafigura, and Copenhagen Infrastructure Partners said it formed the strategic collaboration to create a \"value chain for the production, storage, distribution, and use of green ammonia\" for the shipping industry. Aside from Stavangerregionen Havn, the port authority, other partners in the collaboration are fuel supplier St1 and logistics company ASCO. \"Green ammonia has the potential to make large portions of the shipping fleet emission-free,\" said Eivind Hornnes, business developer at Stavangerregionen Havn. \"To drive the energy transition, ammonia must be as accessible as fossil fuels are today.\" Iverson is developing a green ammonia plant with a production capacity of 200,000 metric tons per year in Sauda based on a hydropower-based, 300-MW electrolyzer, which was expected to enter production by 2029, subject to a final investment decision in 2026, according to the company. It had previously said the plant would enter full operation in 2027. Ammonia is a low-carbon fuel when generated from renewable energy, but it is highly toxic and corrosive and the first ammonia-powered ships for deepsea trade are only due to hit the waters in the second half of this decade. As part of the collaboration, the partners will work together to establish safety standards. ASCO will build storage tanks and bunkering facilities at the port, while St1 has started to explore opportunities to supply ammonia to shipping companies. The monthly average price for green ammonia delivery into Northwest Europe was $50.09\/Gigajoule in July on a cargo basis, according to calculations based on S&P Global Commodity Insights data. The delivered bunker price for 0.5%-sulfur marine fuel, the prevalent bunker fuel, was $16.13\/Gj for ships in intra-EU trades. ","headline":"Iverson eFuels partners with Stavanger, others for green ammonia bunker project","updatedDate":"2024-08-15T14:04:17.000"},{"Unnamed: 0":46,"body":" The high sulfur (3.5%S) fuel oil arbitrage from the Americas into Europe is considered closed according to traders that have cited narrowing spreads between the two markets in August, leading to weaker economics. Platts, part of S&P Global Commodity Insights, assessed the US-Europe HSFO spread -- the premium of HSFO FOB Rotterdam barges against their RMG 380 US Gulf coast counterparts -- at $17.73\/mt on Aug. 14. However, the August average for the spread over Aug. 1-14 was $7.41\/mt after briefly turning negative at the beginning of the month, down from the July average of $20.66\/mt. Platts assessed the HSFO paper front-month to second-month spread at a backwardation of $9\/mt on Aug. 1, the most backwardated the HSFO market has been this month to date. A steeper backwardated structure indicates a stronger prompt month market compared with less prompt months and could be a factor contributing to the closed US-Europe arbitrage status, considering the time lag associated with the transatlantic voyage, trade sources said. Multiple market participants that deem the arbitrage status closed said the unfavorable economics has been the driving factor. A trader said while some cargoes had moved in July, \u201cI haven\u2019t seen anything move at all recently.\u201d Over the past few weeks, HSFO cargoes entered the European markets from regions such as the US Gulf Coast, Mexico and the Caribbean, with traders expecting volumes to arrive in the first half of August. A second trader said some HSFO volumes could still land in Europe in the near future despite the closed arbitrage status. The European HSFO market has been seeing higher demand for power generation in both Northwest Europe and the Mediterranean amid record high temperatures this summer. Meanwhile, a Middle Eastern demand pull for power generation for cooling purposes has persisted, with Saudi Arabia and Egypt having contracts with refineries in the Mediterranean to meet its own power generation needs, reducing the availability of HSFO in circulation in the region. ","headline":"Americas-Europe HSFO arbitrage seen closed as economics weaken","updatedDate":"2024-08-15T13:21:55.000"},{"Unnamed: 0":47,"body":" Iraq\u2019s oil ministry has initialed the 13 contracts for oil fields and exploration blocks that were awarded in the most recent licensing round held May 11-13. In an Aug. 14 ceremony in Baghdad, oil minister Hayan Abdul Ghani said the contracts, when fully developed, will add 750,000 b\/d of oil and 850 MMcf\/d of gas, offering flexibility to power stations supply and supporting the Iraqi energy sector, according to a ministry statement from the same day. The contracts signed were with: China's ZPEC for the East Baghdad and Middle Furat oil fields, and the Qurnain and Abu Khaima blocks; Hong Kong-based UEG for the Fao Block; China's Geo-Jade for the Zurbatiya and Jebel Sanam blocks; China's Sinopec for the Summer block; China's CNOOC for Block 7; China's Anton Oil for Al-Dhifriya oil field, and Kurdistan-based KAR for the Al-Dima, Sassan and Alan oil fields and the Khilaisiya exploration block. The licensing round 5 plus (LR5+) and licensing round 6 (LR6) auctioned 29 projects, but only 13 were awarded despite offering profit sharing contracts, the percentage of which was the bidding criteria and reduced royalties. The results further consolidate China\u2019s dominance in Iraq\u2019s oil and gas sector. The East Asian country, which imported 166.6 million barrels (915,385 b\/d) from Iraq in the first six months of 2024, relies heavily on Middle Eastern crude to meet domestic demand. China manages one-third of Iraq\u2019s proven reserves and two-thirds of Iraq\u2019s current production, according to S&P Global Commodity Insights estimates. \"China's appetite for Iraqi oil stems not only from its large crude import requirements -- averaging 11.1 million b\/d for H1 2024 -- but also due to large investments of Chinese oil companies in Iraq's upstream sector,\" said Kang Wu, global head of oil demand research at Commodity Insights in July. ","headline":"Iraq's oil ministry signs 13 contracts for oil field development and exploration","updatedDate":"2024-08-15T13:20:31.000"},{"Unnamed: 0":48,"body":" The transitioning of some crude tankers to carry refined products is set to lose pace as dirty tanker freight rates pick up later in the year, clean product company Torm said Aug. 15. Strong product carrier rates for the Middle East to Europe run have been luring vessels from the dirty tanker pool to the clean fleet, amid consistent export volumes of refined products from the Middle East compared with low volumes of crude. However, the premium for carrying a clean cargo over that for carrying a crude cargo on the same route has been losing altitude since early July. \u201c[The] seasonally improving crude tanker market toward fourth quarter-first quarter is likely to reduce the number of crude tankers lifting CPP [clean petroleum products] cargoes,\u201d Torm said in material accompanying its Q2 earnings report. Platts, part of S&P Global Commodity Insights, assessed the rate to carry a 75,000 mt cargo of clean products on a Long Range 2 tanker from the Persian Gulf to UK\/Continent at $50.80\/mt on Aug. 14, a $30.38\/mt premium over the rate to carry a 140,000 mt cargo of crude on the same route. The premium has declined steadily since July 10. The number of crude tankers transporting refined petroleum products has seen a substantial increase, rising to 151 vessels as of July 10, from 87 vessels at the end of 2023, Commodity Insights analysts said. While volumes are broadly steady, the longer distances are placing greater strain on the availability of tonnage, driving the strength in freight rates and encouraging the switch. Suezmaxes and Aframaxes have been called on in greater numbers than VLCCs because of restrictions the larger vessels run into at European ports, said Nikesh Shukla, a freight analyst at Commodity Insights. LR2s benefit most from structural support European Union sanctions and a G7 price cap on Russian oil products in response to Moscow\u2019s invasion of Ukraine in February 2022 have reshuffled trade flows, with both EU imports and Russian exports travelling longer distances and adding strain to the existing fleet capacity. Following on from this, Houthi attacks on vessels travelling through the Bab-Al-Mandab Strait have prompted mass rerouting of vessels away from the Red Sea via the Cape of Good Hope. \u201cWith the LR2 segment mostly affected by the Red Sea disruption, LR2 ton-miles have increased by 24% year on year so far in 2024,\u201d Torm said. So far in 2024, product tanker ton-mile has grown by 10%, mainly driven by vessel rerouting away from the Red Sea but also because organic trade growth has been strong, Torm said. Global product tanker ton-mile demand grew 8% on the year in 2023, mainly driven by trade recalibration due to sanctions against Russia. Headwinds for oil demand Market watchers expect weakening pull from China for crude and products and an increasing overhang of crude in the Middle East that may need to be transported. OPEC+ has yet to update its plan to gradually unwind voluntary production cuts starting in the fourth quarter. However, the International Energy Agency\u2019s current balances suggest that even if those cuts remain in place, global inventories could build by an average of 860,000 b\/d in 2025 as non-OPEC supply increases of around 1.5 million b\/d in 2024 and again in 2025 more than offset expected demand growth, the IEA said Aug. 13. The world is seeing a major deceleration in oil demand growth led by China and a current supply deficit, typical for the Northern Hemisphere summer, is set to evaporate in the fourth quarter of 2024, the IEA said. ","headline":"Winter boost to crude tankers will slow fleet clean up: Torm","updatedDate":"2024-08-15T12:33:20.000"},{"Unnamed: 0":49,"body":" Russian refineries have been gradually starting their autumn turnarounds, with plants in the Samara and Ufa hubs as well as in central and northern Russia expected to carry out works. In order to secure stability on the domestic gasoline market during the maintenance season and amid ongoing strong demand, the government, in a recent surprise move, extended the export ban until the end of the year, rather than until the end of October as previously indicated. Meanwhile, Kazakhstan's Ayrau refinery processed 2.911 million metric tons crude over January-June and produced 2.632 million metric tons of oil products. The output included 671,728 metric tons of 92 RON gasoline and 115,132 metric tons of 95 RON, 878,963 metric tons diesel, 95,296 metric tons jet fuel, 106,021 metric tons LPG. Its depth or processing was 86.6% with the light products yield accounting for 68.6%. The volume of oil processed by Azerbaijan's Heydar Aliyev refinery during July was reported at around 500,000 metric tons (about 123,333 b\/d), unchanged on the month and around 17% lower than a year earlier. Refinery throughput for the first seven months of the year was 3.7 million metric tons, down 0.5% from the same period in 2023. New and ongoing maintenance Refinery Capacity b\/d Country Owner Units Duration Shebelinka 11,500 Ukraine Naftogaz Halted ongoing Kremenchuk 240,000 Ukraine UkrTatNafta Halted ongoing Antipinsky 180,000 Russia Rusinvest Full Autumn Khabarovsk 100,000 Russia IPC Part Autumn Novokuybishev 166,000 Russia Rosneft Full Sep Syzran 178,300 Russia Rosneft Part Sep Novoil 142,000 Russia Rosneft Part Sep Ufaneftekhim 190,000 Russia Rosneft Part Sep Angarsk 204,000 Russia Rosneft Full Aug Perm 262,000 Russia Lukoil Part Sep Ukhta 80,000 Russia Lukoil Full Sep Upgrades Mariisky 34,000 Russia New Stream CDU, VDU NA Omsk 428,000 Russia Gazprom Neft Upgrade ongoing Moscow 243,000 Russia Gazprom Neft Upgrade 2025 Taneco 178,000 Russia Tatneft Upgrade NA Haydar Aliev 120,000 Azerbaijan Socar Upgrade Ongoing Turkmenbashi 210,000 Turkmenistan Turkmenistan Coker NA Afipsky 120,000 Russia SAFMAR Upgrade NA Ilsky (Yilsky) 132,000 Russia KNGK-Group Upgrade NA Orsk 120,000 Russia Forte invest Upgrade 2023 Bukhara 50,000 Uzbekistan Uzbekneftegaz Upgrade NA Fergan 109,000 Uzbekistan Uzbekneftegaz Upgrade NA Yanos 314,000 Russia Slavneft Upgrade 2024 Novoshakhtinsky 100,000 Russia Yug Energo Upgrade 2027 Antipinsky 180,000 Russia Socar Energ Upgrade NA Salavat 200,000 Russia Gazprom Upgrade NA Pavlodar 100,000 Kazakhstan KazMunaiGaz Upgrade NA Ryazan 342,000 Russia Rosneft Upgrade NA Achinsk 150,000 Russia Rosneft Upgrade NA Tuapse 240,000 Russia Rosneft Upgrade NA Novokuybishev 164,000 Russia Rosneft Upgrade NA Komsomolsk 160,000 Russia Rosneft Upgrade NA Syzran 178,300 Russia Rosneft Upgrade NA Perm 262,000 Russia Lukoil Upgrade 2025 Jalal-Abad 10,000 Kyrgyzstan Kyrgyzneftegaz Upgrade NA Kirishi 420,000 Russia Surgutneftegaz Upgrade NA Angarsk 204,000 Russia Rosneft Upgrade NA Yaisky 60,000 Russia Neftechimservis Upgrade 2026 Shymkent 120,000 Kazakhstan PetroKazakhstan Expansion 2029 Launches Khabarovsk 100,000 Russia IPC Launch NA Kulevi 80,000 Georgia Fazis Oil Launch 2024 Primorsk region 240,000 Russia Rosneft Launch 2029 Sakhalin 90,000 Russia Gazprom Launch NA New and ongoing maintenance New and revised entries ** Russia's Novokuybishev refinery, part of the Samara refinery hub, is expected to undergo full maintenance in September and October. ** Syzran refinery, part of the Samara hub, is due to carry out works on gasoline and diesel units in September and October. ** Russia's Novoil and Ufaneftekhim are scheduled to carry out works on diesel and gasoline units in September and October. Along with the Ufa (Ufimsky) refinery, they are part of the Ufa refinery hub. ** Russia's Angarsk refinery in Siberia is expected to start maintenance in late August which will last through September, according to market sources. The maintenance was initially expected to start earlier in August but has been deferred. One of the two CDU units will be affected. ** Russia's Ukhta refinery is expected to carry out maintenance starting late September and finishing around mid-October. The maintenance would most likely include the whole refinery. ** Russia's Perm refinery is scheduled to carry out works on diesel and gasoline units and on one crude distillation unit in September and October. ** Russia's Omsk refinery was expected to restart a primary processing unit affected by fire towards the end of August. The refinery reported fire at a pumping station Aug. 1, adding that operations continued normally. However, according to market sources and media reports, the fire affected an 8.6 million metric tons crude and vacuum distillation complex AVT-10. ** Volgograd refinery was on track to restart its hydrocracker after an unplanned outage. The unit has been offline since the last week of July and was expected back around mid-August, according to sources. As a result of the hydrocracker outage, Volgograd had also reduced crude processing, according to sources. ** The Novoshakhtinsky refinery in southern Russia is expected to increase processing in August following restart after a drone attack, according to sources. A fire June 6 affected both CDUs, leading to a halt of operations. Previously, the refinery resumed operations shortly after drones fell at the site March 13. The export-oriented refinery, which produces feedstocks, was partly offline in the summer of 2022 following a drone attack. ** Russia's Taif has completed its maintenance, according to market sources. It brought forward its regular maintenance to July from September when it typically carries out works. The maintenance was due to last one month. The refinery has resumed sales of oil products on the St. Petersburg exchange. Existing entries ** Ukraine's Kremenchuk refinery was the target of a Russian attack July 6, when storage reserves were hit by a strike on the site, Russia's RIA Novosti reported, following earlier reports by the Russian defense ministry about hitting an unspecified refinery in Ukraine. Kremenchuk, Ukraine's largest refinery, was once the country's key supply outlet for diesel and gasoline yet has largely suspended operations due to several Russian attacks since April 2022, most recently in January 2024. Kremenchuk is capable of processing about 12 MMt of crude, but prior to the invasion in February 2022 was refining around 2.5 MMt. Industry sources said Ukraine has been using different Kremenchuk installations for limited production of diesel and for storage to support the country's war effort. ** Russia's Antipinsky refinery has moved its maintenance to the autumn, according to market sources. It had been expected to carry out a full shutdown in April. ** The Khabarovsk refinery in the Far East will have a partial turnaround in the autumn, deferred from April. ** Belarus' Naftan is currently undergoing partial works, it said June 10. Works are underway at reformer No. 3. The refinery plans to carry out works at various units this summer. ** In July and August there will be partial works at Ryazan. ** Russia's Salavat refinery was carrying out partial maintenance in June as part of its first wave of annual maintenance. The turnaround proceeds in a staggered manner, so the refinery remains in operation. ** Kazakhstan's Atyrau is planning maintenance on both primary distillation units in the autumn. Repairs and maintenance at the first primary distillation unit will last 25 days from Oct. 1. The turnaround on the second CDU will last 15 days from Oct. 5. ** As of 2028, all the three Kazakhstan refineries will move to conducting maintenance halts every three years rather than once a year, KMG said. ** Shebelinka GPP, Ukraine's second-largest producer of diesel and gasoline, which operates under the Shebel brand name, suspended operations Feb. 26, 2022. Upgrades Existing entries ** Russian engineering company TopTech said July 2024 it had started work on a project to build a diesel hydrotreater and dewaxer unit at the Tomsk refinery in Siberia. The unit is part of the refinery's program for increasing the depth of processing and widening the product yield. The unit will produce summer, winter and arctic diesel grades. The project is due to be completed by the end of 2024. ** Russia's Lukoil is looking at further upgrades to its Volgograd refinery, the Kommersant daily reported July 11. The project includes a deep processing complex for the production of 1.2 MMt of diesel, including 500,000 metric tons of winter diesel for domestic consumption. As part of the upgrade, Lukoil is considering building a dewaxing unit and lubes hydroisomerization unit. The upgrade would help address the problem of winter diesel shortages, Kommersant said. As a result of the upgrade work, the refinery will be able to produce 200,000 metric tons per year of lubricants. ** China's CNPC is in talks with Kazakhstan over new terms for the expansion of the Shymkent refinery which it owns jointly with Kazakh state-owned KazMunaiGaz (KMG), mulling scaling down the latest plans, which envisage a capacity increase from 6 MMt to 12 MMt, according to sources familiar with the subject, as feedstock supply is the key challenge for the project. The Shymkent refinery expansion project is still being finalized, the KMG press office said. At the moment, the plan is to boost capacity to 12 MMt by 2030. According to KMG the refinery is expected to source crude oil from the Kumkol and Aktobe deposits in western Kazakhstan as well as from new large deposits due to become operational in the coming years. ** Russia's Ilsky refinery plans to commission its new gasoline and aromatics complex by December 2025, Interfax reported July 2024. Work on the new 1.5 MMt complex, which includes CCR and isomerization units, first began in 2021 and was set to be commissioned in 2023, however Western sanctions imposed in 2022 stalled it. Once online, the new complex will be capable of producing Euro-5 gasoline, high-octane components, LPG and xylene, the company previously announced, making it one of the region's largest producers. Currently, the project is in the active phase of construction, and works are underway on the complex's boiler room, nitrogen production plant and water recycling unit, KNGK told Interfax. Separately, Ilsky is also building a 2.4 MMt complex for diesel hydrotreatment and dewaxing aimed to be completed in 2027. ** The upgrade of the Omsk refinery has been completed in 2023 and will finish in 2025 at the Moscow refinery, Gazprom Neft's CEO Alexander Dyukov said during a June 2 meeting with President Vladimir Putin. As a result of the modernization Omsk has reached 99% depth of processing and Moscow will reach the same depth upon its completion. Omsk has increased the range of products as a result of its upgrades, including lubricants, bitumen, needle coke, catalysts. Moscow refinery is currently building a deep processing complex to allow it to cut fuel oil output. So far, the refinery has been 80% upgraded. The deep processing complex, which includes delayed coker, hydrogen and hydrocracker units, is due for completion in 2025. The delayed coker, which will have a 2.4 MMt capacity, will enable the refinery to increase the production of road fuels and start producing petroleum coke. The 2 MMt hydrocracker, a sulfur production unit and a hydrogen unit are also part of the complex. ** Azerbaijan's Heydar Aliyev refinery has started production of Euro 5 gasoline, plant owner Socar announced June 30. The state-owned company said that it had almost completed work on the initial stage of reconstruction of the refinery and that work on the diesel and gasoline units had now been completed. As a result, the AI-92 and AI-95 brand gasolines produced at the refinery have been brought up to Euro 5 standards and will replace imported 95 RON gasoline, Socar said. The Heydar Aliyev refinery has been undergoing a full reconstruction and modernization since 2015 which will increase the plant's overall capacity from 6 MMt to 7.5 MMt, and the capacity of the catalytic cracker from 2 MMt to 2.5 MMt. The work involves the merging, modernization and reconstruction of two existing refineries, the Azerneftyag and Baku plants, with the shutting of some units and the addition of some new units. The first stage of the revamp was completed in December 2018 with the commissioning of a new 400,000 t\/y bitumen plant followed by an LPG unit, after which the plant began again supplying the adjacent Azerkimya petrochemical plant with raw materials ** Uzbekistan's largest oil refinery, Fergana, plans to double its capacity to further 4 MMt through 2030, following the recent round of modernization slated to be completed by the end of 2024, Sanoat Energetika Guruhi Saneg press office said June 2024. Following the current modernization, the Fergana crude oil processing is set to rise to 2 MMt from 1.3 MMt, Saneg said, adding it aimed to ramp up crude oil production in the country to secure local feedstock supply to the facility. Under the current modernization project, worth $350 million, the Fergana refinery is targeting increasing the refining depth from 84% to 93% and expanding the range of oil products, Saneg said. In addition to switching from Euro 2 to Euro 5 gasoline production standards, Fergana is due to add Jet A-1 fuel to its production portfolio and start manufacturing Group II+\/III lubricants. As part of the Fergana modernization plan, by the end of 2024, Saneg plans to launch a steam boiler house, a hydrogen production unit and pressure-cycle adsorption (PSA) unit. The construction of five new technological installations and the reconstruction of 10 existing installations and refinery facilities are also underway, the company said. ** Kyrgyzstan's biggest oil refinery, the Chinese-owned Zhongda, has resumed operations after a five-year outage, the head of the country's oil traders' association said in mid-May. Modernization is also ongoing at the country's smaller refinery, state-owned Kyrgyzneftegaz in Jalal Abad in the south of the country, Eshatov said. The investment in the modernization of the two refineries is estimated at $900 million, with works at both facilities scheduled to be completed by the end of 2024. ** Russia's Slavyansk refinery, a small export-oriented plant on the Black Sea, has pushed back the schedule for completing its high-octane gasoline complex, it said on its website May 2024. The refinery is planning to launch the complex in 2025, having previously been slated for launch in 2024. Slavyansk is also planning to build a deep processing complex, a dewaxing unit and a distillate hydrotreater. ** Russia's Afipsky refinery and the regional government have signed an agreement about the next stage of the refinery's modernization, according to the Krasnodar regional governor. The plan includes completing in 2025 a deep processing complex, which will produce 2.5 MMt of Euro 5 fuel, local media reported. The complex, which includes a hydrocracker, was due to be completed in 2023. The upgrades will raise the depth of processing to 99.2% from 80.7%. The Afipsky refinery is also planning construction of a 1.6 MMt delayed coker. The Krasnodar refinery specializes in primary processing and Afipsky in secondary processing, after owner Safmar Group completed the reorganization of the two southern plants by merging them in May 2021. ** Uzbekistan's Bukhara refinery will help the government to achieve its plan to switch from Euro 2 to Euro 5 high-octane gasoline, Uzbekneftegaz said April 26. The refinery is expected to produce 60% 92 RON and 40% 95 RON with all the gasoline output of 1 MMt meeting the Euro 5 standard. As a result, the country will stop the use of 80 RON Euro 2 gasoline. France's Axens will design the technological units, which will include a naphtha hydrotreater with 360,000 t\/y capacity, isomerization unit with 380,000 t\/y capacity and a selective hydrogenation of pyrolisis distillate unit with 60,000 t\/y capacity. The design documentation is expected to take around five-and-a-half months. Bukhara refinery will also use Honeywell UOP technology to increase crude conversion and produce Euro-5 standard gasoline and diesel. Honeywell will provide \"licensing and basic engineering design services\" for a new naphtha hydrotreater, RFCC, SelectFining and Merox units. The existing diesel hydrotreater will be revamped. ** Turkmenistan's two refineries, Turkmenbashi and Seydi, have been undergoing upgrades. The Turkmenbashi refinery is building a delayed coker and a solvent deasphalter unit whose construction started in 2019. Seydi is building a new reforming unit and expanding its capacity. ** Belarus's Mozyr and Naftan refineries are considering further upgrades, mostly in the petrochemical sector. Mozyr plans to start propylene output in 2025 and polypropylene from 2028. In addition, it plans to launch a gasoline alkylation complex in 2030. Naftan is also looking to build a new ethylene-propylene unit at the Polymir facility, which will enable it to replace outdated equipment. As part of their upgrade, Mozyr commissioned a new hydrocracker in June 2023 and Naftan launched its delayed coker in early 2022. ** Russia's Orsk was expecting to start testing its new gasoline and diesel hydrotreater at the end of 2023. It continues work on its delayed coker complex, which is part of its upgrade, by currently installing the delayed coker furnace. The deep processing complex includes a 1.2 MMt delayed coker and a gasoline dewaxer with 600,000 t\/y capacity. Construction is due to be completed by the end of 2023 and the delayed coker is expected to be commissioned at the beginning of 2024. Previously, its launch had been planned for the end of 2023. The whole complex will be launched in Q1 2025. ** Russia's Afipsky refinery is continuing with its upgrades, according to the Krasnodar regional governor in September 2023. Construction is underway on a hydrocracker, whose launch will increase the refinery's depth of processing. The upgrades will raise the depth of processing to 99.2% from 80.7% and enable the production of Euro 5 diesel. The hydrocracker had been due for completion in 2023 but Russian refinery upgrades have faced delays. The Afipsky refinery is planning construction of a 1.6 MMt delayed coker. Russia's Glavgosexpertiza, the state construction and engineering auditor, has approved the construction of a gasoline stabilization unit at the Afipsky refinery which will produce feedstock for hydrogen production. Safmar Group has reorganized two of its refineries by merging the Krasnodar refinery with the Afipsky refinery in southern Russia, which retains the name Afipsky refinery. The Krasnodar refinery will specialize in primary processing and the Afipsky refinery in secondary processing. ** Rosneft plans to construct a hydrocracker complex at the Ryazan refinery. The new complex, with a 2.2 MMt capacity, will help the refinery to increase the depth of processing and achieve higher margins through the conversion of heavy into light products. It will include a hydrocracker, as well as hydrogen and sulfur units. ** Russia's Yaisky is carrying out the third phase of its upgrade, after works started in April. It plans to complete in 2027 a dewaxing complex with 2.5 MMt capacity and a delayed coker with 1.15 MMt capacity. The commissioning of those complexes will increase its depth of processing to 93% and enable it to produce diesel with improved cold properties, it said on its website. ** Russia's Novatek has launched a new hydrocracking unit at its Ust-Luga gas condensate fractionation facility, it said June 14. Separately, Novatek CEO Leonid Mikhelson told local media June 14 the company planned to launch the third stage of the gas condensate fractionation and transshipment complex in Ust-Luga in the middle of 2024, enabling it to process more of its gas condensate output. ** Russia's Salavat refinery said it has signed an investment agreement with the government of the Republic of Bashkortostan to upgrade and expand its reformer unit. The agreement foresees doubling the capacity of the L-35\/11-1000 reformer unit to 2 MMt. The reformer, which was commissioned in 1978, has 1 MMt capacity. After the upgrade, it will process additionally at least 1 MMt naphtha. The upgrade will also involve the reconstruction of the unit's equipment and the building of an amine gas-treating unit. ** Kazakhstan's KazMunaiGaz and Air Liquide signed an agreement June 8 for the construction of a hydrogen unit at the Pavlodar refinery, KMG said. The hydrogen unit will allow the refinery to produce up to 160,000 t\/y winter diesel. Separately, Pavlodar is looking to build a unit for the purification of LPG and has selected Merox technology. ** Russian oil company Tatneft said its Taneco refinery has launched its aromatics complex in test mode. The complex consists of eight units that have been gradually commissioned since 2018. They will enable the refinery to increase benzene production to 60,000 t\/y and also to produce 150,000 t\/y paraxylene. Separately, Taneco continues the construction of a second hydrocracker which has a 1.2 MMt VGO feedstock capacity. Its launch will further increase the refinery's depth of processing. Jet fuel output will rise by 21,100 t\/month and diesel output by 56,600 t\/m. The refinery has a 2.9 MMt hydrocracker. ** Russia's Novokuybishev aims to complete the construction of the hydrocracker and launch it in test mode by the end of 2022-early 2023, according to local media reports, citing a refinery source. Construction started in 2021. ** Russia's Syzran refinery has completed assembling the catalytic distillation column at a new MTBE unit. The MTBE units along with an FCC complex under construction form part of the refinery's modernization project. Once the new units are completed, the refinery will significantly increase the output of high-octane gasoline. ** Russia's Komsomolsk carries out a large-scale project involving the construction of a hydrocracker and hydrotreater with a 3.65 MMt capacity, which will enable it to increase the output of Euro 5 diesel. Once launched, the refinery's depth of processing will increase to 92%. ** Lukoil plans to build a new integrated MTBE and alkylation plant at its Perm refinery in Russia, as well as new FCC and Merox units. Lukoil will build a catalytic cracker complex at the plant. The complex will have a 1.8 MMt feedstock capacity. It will include a catalytic cracker and a high-octane gasoline components unit. The complex is expected to be launched in 2026 and will increase the output of high-octane gasoline. It will also allow the refinery to produce propylene to be used as petrochemical feedstock. ** Russia's Novoshakhtinsky has started the construction of its gasoline complex. It aims to produce around 670,000-680,000 t\/y and construction is due to start in 2021. The complex is due for launch in Q1 2024. It will process up to 894,000 t\/y of naphtha. It will include a gasoline hydrotreater, an isomerization unit and a catalytic reformer and will enable the refinery to produce Euro 5 gasoline. Separately, the refinery plans to launch a 1.8 MMt diesel hydrotreater in Q3 2024. Russia's Glavgosexpertiza, the state construction and engineering auditor, approved the construction of a sulfur unit as part of the diesel hydrotreater complex. In Q1 2027, it expects to launch a deep-processing complex, which includes a hydrocracker and delayed coker. It plans to launch an LPG production unit in Q1 2023. Following the completion of the upgrades, which are part of the third stage of upgrades, the refinery will be able to produce up to 3.2 MMt of diesel and 400,000 metric tons of petroleum coke. ** Russia's Angarsk has started assembling the main column at the catalytic cracker complex. The assembly of the column is part of the refinery's upgrade. The GK-3 unit is aimed to process 130 t\/hour vacuum gasoil and 520 t\/h desalted crude oil will produce over 43 components. ** Russia's Kirishi plans to upgrade for \"the conversion of heavy oil residues.\" ** Russia's Yanos refinery in Yaroslavl has started building a delayed coker complex. As a result, it will halt fuel oil output. Its depth of processing will exceed 99% and light products yield 70%. Construction is scheduled for completion in 2024. The complex will be built in two stages. Initially, a delayed coker will be built which will enable the processing of more than 3.4 MMt of heavy fractions, followed by a naphtha hydrotreater and light gasoil coker. They will provide feedstock for gasoline and diesel. ** Russia's Achinsk refinery will increase its depth of processing to over 95% and the light products yield to 88% upon completion of its upgrades, which will lead to the almost complete halt of fuel oil output. It is building a hydrocracker with an integrated hydrotreater. Its launch will enable it to almost double the output of motor fuel aimed at covering domestic demand predominantly in Siberia and the Far East. It is also building a delayed coker complex. ** Russia's Rosneft is working toward launching the hydrocrackers that it has built at four of its refineries -- Achinsk, Komsomolsk, Novokuybishev and Tuapse. Rosneft is expanding the capacity of its existing delayed coker at Novokuybishev. Rosneft plans to complete its refinery modernization program by 2025. The program includes the construction and reconstruction of over 50 units, with work on more than 30 of the units having been finished. ** Kyrgyzneftegaz plans to upgrade its Jalal-Abad refinery. Its strategy involves a unit for the secondary processing of fuel oil. ** The launch of four secondary units at the Mariisky refinery has been delayed. As per plans, after upgrades, it expects to increase the AT-2's capacity to 1.4 MMt from 900,000 t\/y and the VDU capacity to 1 MMt from 476,000 t\/y. ** The next stage of upgrades at the Antipinsky refinery in Russia involves increasing the capacity of crude and refined product pipelines. Antipinsky, which can process 9 million-9.5 MMt of crude, currently receives 7.5 MMt of crude. Launches Existing entries ** Russia's Khabarovsk refinery aims to complete its upgrade in 2024, Interfax news agency quoted the local governor, Mikhail Degtyarev, as saying. The upgrade will involve the construction of a vacuum gasoil hydrotreater and hydrogen production unit. The upgrade will increase the refinery's depth of processing and result in a higher output of diesel as well as International Maritime Organization-compliant marine fuel. The company has previously announced plans to double the refinery's capacity to 10 MMt and build an FCC, hydrotreater and delayed coker. ** Russia's Gazprom is mulling the possibility of building a refinery in Russia's Far East, on the island of Sakhalin, according to media reports. The company is expected to prepare an investment decision in 2023, according to the local government. The new refinery, with a 4.5 million metric tons capacity, is likely to process gas condensate and produce gasoline, diesel and kerosene. ** Russia's Rosneft could launch a planned new refinery as part of its VNHK (East petrochemical complex) in the Far East in 2029 and a petrochemical plant in 2026. The Far East refinery is planned to process 12 MMt of crude, while the petrochemical plant will have a 3.4 MMt capacity. Production will include 1.8 MMt of gasoline, 6.3 MMt of diesel and 4.5 MMt of petrochemical products. ** A new refinery is planned to be launched in Georgia, at the Black Sea port of Kulevi. Construction of the 4 MMt plant was due to start in 2021. The refinery is expected to have 98% depth of processing and produce Euro 5 and 6 gasoline and diesel and thus reduce Georgia's import needs for oil products by 15%-20%. ","headline":" New round of turnarounds in Russia","updatedDate":"2024-08-15T12:27:23.000"},{"Unnamed: 0":50,"body":" EU gas consumption in July dropped by 7% year on year on the back of continued demand reduction efforts and lower power sector demand, the Gas Exporting Countries Forum said in its latest monthly market report. In the report published Aug. 15, the GECF also said that for the period January-July, the EU's gas consumption declined by 4.5% on the year to 180 Bcm. \"In July, gas consumption in the EU recorded a year-on-year decrease of 7%, which was mainly driven by the continuous implementation of the gas demand reduction measures and higher hydro, nuclear and solar output,\" it said. The EU agreed earlier this year to extend its voluntary gas demand reduction target of 15% until March 2025. The GECF also said Aug. 15 that in the industrial sector, gas consumption showed a recovery in major industrialized European countries, boosted by the fall in gas prices. Platts, part of S&P Global Commodity Insights, assessed the Dutch TTF month-ahead price at an average of Eur32.48\/MWh in July, well down on the record levels seen in 2022. Other markets The secretariat of the GECF -- whose members include gas heavyweights Russia, Iran and Qatar -- is tasked with, among other things, publishing analysis of the global gas market. Previously, it only released annual market reports but now it also issues monthly reports similar to those published by OPEC on the oil market. In its latest monthly report, the GECF said that US gas consumption in July dipped by 1.4% year on year to 74 Bcm. \"The power generation sector led the decline. By contrast, the industrial, residential and commercial sectors recorded a growth in gas consumption of 0.6%, 2.6% and 1.8% year on year, respectively,\" it said. Japan and South Korea, meanwhile, both saw slight increases in gas consumption in July. Japanese consumption rose by 1.3% year on year to 7.8 Bcm driven by an increase in power demand for cooling, which boosted gas consumption in the power generation sector. Gas consumption in South Korea rose 0.2% year on year to 3.8 Bcm, also primarily due to power sector demand. The GECF also gave estimates for gas demand in China and India for the earlier month of June, pegged at 34.6 Bcm (up 6% year on year) and 6.2 Bcm (up 16%), respectively. China's gas consumption topped 400 Bcm for the first time in 2023, reaching 405 Bcm, according to the Energy Institute's Statistical Review of World Energy. EU imports In terms of gas imports, the GECF said pipeline deliveries to the EU in July totaled 13.3 Bcm, flat on the year. However, Europe witnessed another decline in LNG imports, recording a 26% fall to 6.34 million metric tons, the lowest level since September 2021, the GECF said. It said the weaker LNG imports were attributed to lower gas consumption, high gas storage levels, stable pipeline gas imports, and a significant spot LNG price spread between Asia Pacific and Europe. ","headline":"EU gas consumption down 7% on year in July on demand reduction efforts: GECF","updatedDate":"2024-08-15T11:48:33.000"},{"Unnamed: 0":51,"body":" Russia's Angarsk refinery in Siberia was expected to start maintenance in late August which will last through September, according to market sources Aug. 15. The maintenance was initially expected to start earlier in August but has been deferred. One of the two CDU units will be affected. Platts, part of S&P Global Commodity Insights, assessed Urals CIF Rotterdam at $72.205\/b on Aug. 14. ","headline":" Russia's Angarsk expected to start works late August: sources","updatedDate":"2024-08-15T11:45:51.000"},{"Unnamed: 0":52,"body":" The CIF NWE jet cargo differential fell to levels last seen in April, with Platts assessing it at a $43\/mt premium to the front-month ICE LSGO contract Aug. 14, as the market experiences headwinds from strong supply and slower-than-expected demand recovery in major world economies. The CIF NWE jet cargo differential was priced at a low of $42\/mt on April 4 and has been moving up since then as summer demand strengthened. The current weakness is stemming from sluggishness across the middle distillate complex, as refineries prioritize jet fuel over diesel both locally in Europe and globally, and major world economies experience a slower-than-expected demand recovery, said Europe-based sources. The jet vs diesel crack was priced at 16 cents\/b Aug. 14, as diesel continues its downward trend weakening the entire middle distillates complex amid strong imports. \u201cAs diesel remains weak, refineries have maximized jet fuel locally and globally, and Europe is a high price center so all the Far East and AG oil flows are now coming into Europe,\u201d said a source. Imports of jet fuel from East of Suez into Europe are set to hit 1.8 MMt in August, up from volumes of 1.7 MMt seen in the last three months, according to S&P Global Commodities at Sea data retrieved Aug. 15. \u201cWeakness is being seen in the US too and they\u2019ve got too much oil so they\u2019re sending barrels over to Europe. The Far East is also exporting more than what Europe requires,\u201d he added. US jet fuel output dipped to a nearly three-month low in the week ended Aug. 9, according to the Energy Information Administration Aug. 14, but inventories grew over the same period amid a drop in domestic air travel demand. US stocks rose from a monthly low by 141,000 barrels to 46.241 million barrels in the week ended Aug. 9. USGC and West Coast inventories, meanwhile, rose by 592,000 barrels to 14.258 million barrels and by 613,000 barrels to 11.820 million barrels, respectively. \"Still a lot of jet around, \"a US jet trader said Aug. 14. \"Maybe exports will clean up the USGC.\" Reflecting the persisting weakness, structure in outright jet swaps has been in contango throughout summer despite gains from peak seasonal demand, with Platts assessing the Jet CIF NWE M1 vs M2 spread at minus $2.75\/mt Aug. 14. \u201cAviation demand is good but not great: there have been aircraft delivery issues, so most airlines are having capacity issues which means less passengers; so, winter is looking a bit bearish, and I doubt demand will go beyond 2019 levels this year,\u201d said a source. Although global air travel measured by flights returned to pre-pandemic levels for the first time in mid-2023, jet fuel demand has not kept pace. So far, global jet demand in 2024 remains around 95% of 2019 due to supply chain issues, efficiency gains, larger planes, and a slower rebound in more fuel-intensive long-haul travel. \u201cICE LSGO has been in contango so that has been pulling jet down into contango too, and the weakness in the Chinese economy is impacting jet fuel demand a lot,\u201d the source added. China\u2019s economy has been recovering from the pandemic slower than expected, with growth much lower than expected in the second quarter of the year as a property downturn and job insecurity further hindered recovery, according to media reports. The world's second-largest economy, and a major oil consumer, grew 4.7% in April-June, official data showed, its slowest since the first quarter of 2023. It also slowed from the previous quarter's 5.3% expansion, according to reports. ","headline":"European jet differentials drop to 4-month lows amid strong inflows, high refinery output","updatedDate":"2024-08-15T11:36:48.000"},{"Unnamed: 0":53,"body":" Crude oil futures were higher in morning European trade Aug. 15 despite a mixed set of economic data from China and a rise in US crude stocks last week. At 1010 GMT, the ICE October Brent futures contract was trading at $80.41\/b, up 65 cents\/b from the previous close, while the September NYMEX light sweet crude contract was 61 cents\/b higher at $77.59\/b. Data released by the Chinese National Bureau of Statistics Aug. 15 revealed a mixed picture of firming consumer spending against softer factory output. \"Chinese data on investments and private consumption have been published this morning, and they were generally on the weak side,\" analysts at Global Risk Management said. China's retail sales rose 2.7% on the year in July, narrowly beating an estimate of a 2.6% increase, NBS data showed. While the uptick in retail figures was seen as a positive signal of stabilization in the Chinese economy, a slide in industrial production growth dampened market optimism. China's industrial production rose just 5.1% in July from the previous year, slowing from the 5.3% increase in June and missing forecasts of 5.2% growth. Meanwhile, China's crude throughput continued its downtrend in July, falling 6.1% on the year and 2% from June to a 21-month low of 13.96 million b\/d, or 59.06 million metric tons, NBS data showed. This was the first time the volume dropped below the 14 million b\/d mark since the previous low of 13.86 million b\/d in October 2022. In the US, the latest data from the US Energy Information Administration showed crude inventories moved higher in the week to Aug. 9. \"Oil came under pressure when the official weekly EIA inventory figures showed a surprising increase of 1.4 million barrels, after Tuesday's API figures had pointed to a significant drop of 5.2 million barrels,\" GRM analysts said. ","headline":" Crude higher despite weaker Chinese economic data, rise in US crude stocks","updatedDate":"2024-08-15T10:42:35.000"},{"Unnamed: 0":54,"body":" Thai refiner Star Petroleum Refining Company Ltd. (SPRC) reported a 90% utilization rate in the second quarter of this year, down slightly from 91% in the same period last year, the company said in its latest results report on Aug. 14. SPRC\u2019s utilization in Q2 was also lower than the rate of 96% in Q1 this year. The company said its Q2 financial performance dropped quarter on quarter mainly due to \u201ca combination of lower product crack spreads and reduced sales volume resulting from optimizing crude throughput at 158,000 b\/d (90% CDU utilization rate) and taking opportunity during low margin to do RFCCU (residue fluid catalytic cracking unit) maintenance to enhance reliability\u201d. SPRC did not immediately respond to queries about its RFCCU maintenance on Aug. 15. Its refinery at Map Ta Phut in southern Thailand's Rayong province processed 157,600 b\/d in Q2, falling from 159,000 b\/d in Q2 2023 and from 167,400 b\/d in Q1 this year. The company reported an average market gross refining margin (GRM) of $2.36\/b in Q2, higher than $1.34\/b in Q2 last year but tumbling from $8.31\/b in Q1 2024. SPRC said despite the lower quarter-on-quarter performance, the company remained focused on value optimization through its enterprise Bottom Line Improvement Program (BLIP). The initiative includes enhancements across the entire value chain, such as crude and feedstock procurement, optimizing run rates, improving process efficiency, product and channel optimization, and refining logistics operations. Since January 2024, SPRC's production has transitioned exclusively to Euro-V specification for both mogas and diesel. SPRC\u2019s utilization rate in the first half was at 93%, slightly higher than 92% a year earlier. Its refinery processed 162,500 b\/d of crude oil in the period, up from 160,600 b\/d in H1 2023. The company\u2019s H1 GRM was at $5.42\/b, an increase from $3.86\/b in the first six months of last year. ","headline":" Thailand's SPRC reports Q2 utilization of 90%","updatedDate":"2024-08-15T10:38:15.000"},{"Unnamed: 0":55,"body":" The Middle East sour crude complex saw no convergences during the Singapore Platts Market on Close assessment process Aug. 15, while the cash differentials for key sour crude markets strengthened. Platts, part of S&P Global Commodity Insights, assessed October cash Dubai at a premium of 78 cents\/b to same-month Dubai futures at market close, rising 15 cents\/b on the day, while October cash Oman was assessed at a premium of 78 cents\/b, increasing 8 cents\/b on the day. October cash Murban was assessed at $1.40\/b to same-month Dubai futures, gaining 18 cents\/b on the day. During the Platts Market on Close assessment process, 22 October Dubai partials of 25,000 barrels each traded, bringing the total number of partials traded so far this month to 319. The sellers were Exxon, Mercuria, Mitsui, PetroChina, P66 and Trafigura, while the buyers were Glencore, Gunvor and Vitol. No convergences were reached during the MOC. A convergence occurs when 20 partials are traded between two counterparties, resulting in a full 500,000-barrel physical cargo being declared from the seller to the buyer. Meanwhile, China's crude throughput continued in a downtrend in July, declining 2% from June to a 21-month low of 13.96 million b\/d (59.06 million metric tons), data from the National Bureau of Statistics showed Aug. 15, reflecting weak domestic demand. This was the first time the volume dropped below the 14 million b\/d mark since the previous low of 13.86 million b\/d in October 2022. On a year-on-year basis, the volume in July fell 6.1%, marking the steepest decline since the 6.5% drop in August 2022. The NBS releases data in metric tons, which S&P Global Commodity Insights converts to barrels using a conversion factor of 7.33. In metric tons, the country's throughput in July edged 1.3% higher from 58.32 MMt in June. ","headline":" Middle East sour crude complex sees no convergences, cash differentials rise","updatedDate":"2024-08-15T10:34:35.000"},{"Unnamed: 0":56,"body":" Tankers will burn an estimated 200,000 b\/d extra fuel oil in 2024 as they divert around the Cape of Good Hope to avoid attacks in the Red Sea, according to commodity trading house Trafigura. It comes after the International Energy Agency and shipping body BIMCO highlighted higher bunker consumption as vessels try to avoid the Red Sea due to attacks by Yemen\u2019s Houthi rebels on merchant shipping, in response to the Israel-Hamas war. \u201cThis equates to a 4.5% increase in annual emissions from oil tankers alone,\u201d Trafigura said in a statement Aug. 14. Factoring in containers and other types of vessel, bunker demand will rise by a further 500,000 b\/d of fuel because of the disruptions, Trafigura said. The IEA in March raised its estimate for 2024 oil demand by 110,000 b\/d to 1.3 million b\/d on higher bunker fuel consumption due to vessels avoiding the Red Sea and to an improved economic outlook for the US. Attacks on ships in the Bab al-Mandab Strait have forced nearly all container ships to sail around the Cape of Good Hope, avoiding the Suez Canal and adding 10% to average sailing distances and ship demand, BIMCO said in June. Among container ships, a 1% increase in speed typically leads to a 2.2% rise in fuel consumption. For example, accelerating from 14 to 16 knots increases fuel use per mile by 31%. As a result, the longer distances caused by rerouting from the Suez Canal to the Cape of Good Hope imply a 70% increase in greenhouse gas emissions for a round trip from Singapore to Northern Europe, the United Nations Conference on Trade and Development said in February. Transit through the Suez Canal, part of the route that goes past the Bab al-Mandab Strait and Houthi attacks, has slumped since the attacks on merchant vessels picked up in earnest at the end of 2023. On Aug. 11, 14 cargo ships and 11 tankers transited the chokepoint, part of a seven-day moving average of 31 vessels that was 54% lower on the year. Cape Town, Durban and Richards Bay in South Africa , Port Louis in Mauritius and Lome in Togo saw 648 bunker and ship-to-ship transfers in the month to Aug. 14, up 16% on the year, according to data from S&P Global Commodities at Sea. Platts, part of S&P Global Commodities Insights, assessed delivered 0.5% sulfur fuel oil at Durban at $750\/mt Aug. 13, a $196\/mt premium to Rotterdam. A year previously, the premium was $98\/mt. ","headline":"Trafigura sees 200,000 b\/d extra fuel burn for tankers in 2024 amid diversions","updatedDate":"2024-08-15T08:48:22.000"},{"Unnamed: 0":57,"body":" Norwegian oil company DNO is expanding operations in the semiautonomous Iraqi Kurdistan region for the first time since early 2023, according to the company's second-quarter financial results released Aug. 15. The company is preparing to mobilize a rig to drill the first new well on the Tawke license since last year and has put previously drilled wells into production to help address natural field decline. DNO increased spending in the second quarter to \"optimize production from existing wells at Tawke license,\" the company said. Production at DNO's oil fields in Kurdistan is up 9% from the last quarter, with pumped crude totaling 79,800 b\/d in the second quarter of 2024 as crude production continues its steady rise more than a year after the shutter of a key export pipeline . That production, spread across the Peshkabir and Tawke fields, is up slightly from 76,310 b\/d in the first quarter of 2024, the company's results showed. DNO holds a 75% operated interest in the two fields; Genel holds 25%. Meanwhile, the Baeshiqa field, where DNO holds a 64% stake, remains shut in since the pipeline's closure. However, a 72-day testing program has started on a newly drilled B-3 well at the Baeshiqa field. The Iraq-Turkey export pipeline has been closed since March 2023 and continues to weigh down production from the Kurdistan region. But international oil companies, including DNO, have found a new local market that has kept cash flow steady and allowed operations to continue, albeit at much lower sales prices. Sales to local traders in Kurdistan continue at prices in the upper $30s per barrel and payments made in advance to international bank accounts, DNO's results said. That price is roughly half the amount a barrel of Russia's Urals crude, another medium sour grade, would fetch at international markets. Platts, part of S&P Global Commodity Insights, assessed Russia's Urals crude on a CIF basis in the Mediterranean market at $65.43\/b on Aug. 14. \"We are not realizing the full value for our Kurdistan barrels with the shutdown of the Iraq-Turkiye export pipeline, now twisted into a Gordian knot,\" DNO Executive Chairman Bijan Mossavar-Rahmani said in an Aug. 15 earnings report. Ownership of oil resources in Kurdistan is at the heart of the issue stalling the resumption of flows through the Iraq-Turkey pipeline. The Kurdistan Regional Government signed production sharing contracts with the companies independently of the federal authority in Baghdad, which the federal government deemed illegal. Now, a stronger Baghdad has ratcheted up the pressure on the KRG and sought to reimpose its sovereignty over the region. In 2022, Iraq's Federal Supreme Court ruled that Kurdistan's independent oil and gas industry was unconstitutional and ordered the KRG to hand over its energy assets to Baghdad. The Iraqi oil ministry has sought to invalidate the PSCs and convert them into technical service contracts that are much less lucrative to the oil companies. Little substantial progress has been made toward reopening the ITP, though discussions are ongoing between Baghdad, the IOCs in Kurdistan and the KRG. \"Until the knot is cut, we will compensate by spending more to produce more and by requiring payments in advance to our international bank accounts,\" Mossavar-Rahmani said. The Kurdistan blocks make up the brunt of DNO's global production, with smaller portions coming from the North Sea and West Africa. ","headline":"Norway's DNO expands drilling operations in Iraqi Kurdistan","updatedDate":"2024-08-15T07:35:33.000"},{"Unnamed: 0":58,"body":" State-owned oil company Petronas set the September Malaysian crude oil official selling price differential at a premium of $7.90\/b to Platts Dated Brent crude assessments, up $1.70\/b from August, the company said in an Aug. 15 notice via email. Petronas also adjusted the price differential for its secondary crude grades against its main basket of crudes. The Tapis differential to the Malaysian crude oil OSP was set at a discount of $3.85\/b for September-loading cargoes, compared with a discount of $4.51\/b for August. Bintulu was set at a discount of $2.22\/b to the Malaysian crude oil OSP for September, compared with a discount of $2.03\/b for August. The Dulang and Cendor grades were set respectively at premiums of $1.40\/b and $2.11\/b to the Malaysian crude oil OSP for September-loading cargoes, compared with premiums of $2.51\/b and $1.66\/b to the Malaysian crude oil OSP for August. The Malaysian crude oil OSP differential takes into account a number of factors, such as the average premium or discount to Platts Dated Brent crude assessments in physical spot sales of the Labuan, Miri Light, Kikeh and Kimanis grades loading in the month. Petronas also considers the assessments of those grades during a specific period by price information providers and its buyers' views on trades and any recommendations they make on the value of the crude grades. Malaysian crude OSPs: (Unit: $\/b) Differential versus Dated Brent Grade June July August September Change MCO OSP alpha 7.15 5.40 6.20 7.90 1.70 Tapis 2.30 0.92 1.69 4.05 2.36 Differential versus MCO OSP Grade June July August September Change Tapis -4.85 -4.48 -4.51 -3.85 0.66 Bintulu -3.29 -2.46 -2.03 -2.22 -0.19 Dulang 2.23 2.44 2.51 1.40 -1.11 Cendor 2.22 2.26 1.66 2.11 0.45 Source: Petronas ","headline":"Petronas sets September Malaysian crude OSP at Dated Brent plus $7.90\/b","updatedDate":"2024-08-15T07:33:25.000"},{"Unnamed: 0":59,"body":" China's natural gas production rose 7.9% year on year to 20 Bcm in July, latest data released by the National Bureau of Statistics showed Aug. 15. The year-on-year growth rate slowed down from the 20-month high of 9.6% in June, but was still slightly higher than 7.6% in the same month last year, according to NBS historical data. For month-on-month comparison, July gas output edged down from 20.2 Bcm in June, mainly due to gas field maintenance and heavy rainfall, industrial sources said. State-owned PetroChina's Tarim Oilfield Company has shut two of its oil and gas production zones for scheduled maintenance starting from July 21 and July 23, respectively, the company said on its social media account Aug. 3. PetroChina Southwest Oil and Gas Field Company's natural gas purification plant also went through a 20-day scheduled maintenance in July and resumed operations on July 24, the company said on its social media account July 29. Apart from maintenance, heavy rainfall has also affected oil and gas production at some fields since July. PetroChina Liaohe Oilfield Company had shut some production wells due to heavy rainfall since July 25, which inevitably affected its oil and gas production, the company said via its social media account July 30. Over January-July 2024, China produced 143.6 Bcm of natural gas, up 6.2% year on year, according to the NBS data. The growth in natural gas production in the first seven months of this year was higher than the 5.7% seen over the same period of last year. This increase can be attributed to various factors, including increased investment in exploration and production activities, government policies promoting cleaner energy sources, and rising demand for natural gas. PetroChina's Southwest Oil and Gas Field, the fifth-largest oil and gas field in China, said July 25 that the company will further increase development efforts toward the goal of reaching a gas production capacity of 50 Bcm\/year. PetroChina's Southwest Oil and Gas Field achieved a historic milestone by producing 40 Bcm of natural gas in 2023, accounting for one-fifth of the country's total natural gas production, according to the company. ","headline":" July natural gas production rises 7.9% on year to 20 Bcm","updatedDate":"2024-08-15T07:10:25.000"},{"Unnamed: 0":60,"body":" Crude oil futures gave up early gains in midafternoon Asian trade Aug. 15 after a mixed set of economic data from China revealed firming consumer spending against softer factory output. At 2:35 pm Singapore time (0635 GMT), the ICE October Brent futures contract was up 12 cents\/b (0.15%) from the previous close at $79.88\/b, while the NYMEX September light sweet crude contract rose 15 cents\/b (0.19%) at $77.13\/b. China's retail sales rose 2.7% on the year in July, narrowly beating an estimate of a 2.6% increase, data from the National Bureau of Statistics revealed Aug. 15. While the uptick in retail figures was seen as a positive signal of stabilization in the Chinese economy, a slide in industrial production growth dampened market optimism. China's industrial production grew just 5.1% in July from the previous year, slowing from the 5.3% increase in June and missing forecasts of 5.2% growth. \"The demand-side weakness remains stubborn ... [while] the supply side is cooling,\" ANZ Research analysts commented following the latest NBS data. \"Fiscal spending will be key to achieving the 5% GDP target, but we have not seen the drive yet.\" China's crude throughput continued its downtrend in July, falling 2% from June to a 21-month low of 13.96 million b\/d (59.06 million metric tons), NBS data showed. This was also the first time the volume dropped below the 14 million b\/d mark since the previous low of 13.86 million b\/d in October 2022, the data showed. The volume in July was down 6.1% on the year, marking the steepest decline since the 6.5% drop in August 2022. \"Growing demand in developed economies, such as the US, has been compensating for slackness in China,\" ANZ Research said. US refinery net crude inputs climbed 70,000 b\/d to 16.47 million b\/d while overall refinery utilization jumped 1 percentage point to 91.5% of capacity, latest data from the US Energy Information Administration showed. While US crude inventories moved higher in the week to Aug. 9, nationwide gasoline stocks retreated 2.89 million barrels to 222.2 million barrels, falling 2.4% behind average, while distillate inventories declined 1.67 million barrels to 126.12 million barrels. Still crude prices remain precariously perched on the edge of a critical technical price support level as a fresh bearish signal starts to form. \"Buyers will want to see a revival today or in coming sessions that puts the price back above $78\/b [for US crude] and the 200-day [Simple Moving Average], in order to point the way to further gains,\" said IG's Chief Market Analyst, Chris Beauchamp. Dubai crude Dubai crude swaps and intermonth spreads were mixed in midafternoon Asian trading Aug. 15 from the previous close. The October Dubai swap was pegged at $77.70\/b at 2 pm Singapore time (0600 GMT), down 88 cents\/b or 1.12% from the previous Asian market close. The September-October Dubai swap intermonth spread was pegged at 76 cents\/b, up 3 cents\/b over the same period, and the October-November intermonth spread was pegged at 55 cents\/b, unchanged from the previous close. The October Brent-Dubai exchange of futures for swaps was pegged at $2.23\/b, down 27 cents\/b. ","headline":" Crude pares early gains on mixed China data","updatedDate":"2024-08-15T06:38:00.000"},{"Unnamed: 0":61,"body":" Japan cut its fuel subsidy for refiners and oil product importers for the fifth consecutive week to Yen 17.10\/liter (12 cents\/liter) for the week of Aug. 15-21, from Yen 21.40\/liter the previous week, the government said Aug. 15. The government, which reviews the subsidy every week, reduced it as the average price of Nikkei Dubai oil fell 3% on the week to $76.35\/b over Aug. 6-9. The Nikkei Dubai oil price is one of the factors that the government monitors to decide the subsidy. Japanese Prime Minister Fumio Kishida said June 21 that the government has decided to continue its current fuel subsidy policy until the end of 2024 to curb rising retail prices of oil products, including gasoline. In March, the government extended the subsidy program from end-April to support inflation-hit households, without setting a specific deadline. The policy has been extended seven times since its introduction. The national average retail price for regular gasoline remained unchanged week on week at Yen 174.60\/liter on Aug. 13, according to the Oil Information Center. The gasoil pump price was also unchanged at Yen 154.30\/liter, while the kerosene pump price rose Yen 0.10\/liter to Yen 117.20\/liter, according to the center. Without the subsidy, the retail price of gasoline would have risen Yen 21.60\/liter to Yen 196.20\/liter on Aug. 13, the Ministry of Economy, Trade and Industry said Aug. 15. The subsidy reduced gasoil and kerosene prices by Yen 21.60\/liter and Yen 21.50\/liter, respectively, the ministry added. Refiners use the subsidy to curb increases in weekly wholesale prices of oil products, while trading houses deduct the subsidy from selling prices of imported oil products. ","headline":"Japan cuts Aug 15-21 fuel subsidy by 20% as crude prices drop","updatedDate":"2024-08-15T05:34:10.000"},{"Unnamed: 0":62,"body":" India\u2019s middle distillates demand fell 8.74% to reach a 10-month low of 7.96 million mt in July, led by a decline in gasoil consumption as the monsoon season curtails industrial activity, latest provisional data from the Petroleum Planning and Analysis Cell showed. Gasoil and aviation turbine fuel consumption was last lower in September 2023 at 7.18 million mt, historical PPAC figures showed. On a year-on-year basis, demand was 4.46% higher than 6.89 million mt seen in July 2023. Over January-July, middle distillates demand totaled 59.7 million mt, or 3.5% higher than the same year-ago period. The month-on-month decline in middle distillates consumption in July came on the back of a 9.87% drop in gasoil demand at 7.2 million mt, a 10-month low. Demand was last recorded lower in September 2023 at 6.49 million mt. Supply of gasoil typically outpaces demand over June-September as the monsoon crimps agricultural and industrial activities in India and parts of Southeast Asia, prompting refiners to export instead of allocating to the domestic market. Meanwhile, demand for co-distillate aviation turbine fuel edged 2.83% higher on the month to 727,000 mt (b\/d) in July, bringing total consumption over the first seven months of the year to 5.1 million mt or 10.59% higher than the same period a year ago. India\u2019s domestic airlines carried 13.2 million passengers in June, representing a 5.76% increase on the month, according to the latest data from India's Directorate General of Civil Aviation. This brings total passengers carried over the six months to 79.3 million passengers, 4.28% higher from the same period a year ago. Data for July has yet to be released. Going forward, the South Asian middle distillate market is expected to remain at a surplus in the third quarter of 2024 compared with last year, S&P Global Commodity Insights analysts said in their latest outlook. \u201c[South Asian] gasoil demand is projected to grow by 58,000 b\/d, while production is expected to rise by 60,000 b\/d. Similarly, jet fuel\/kerosene demand is anticipated to increase to 19,000 b\/d, with production only growing by 18,000 b\/d,\u201d they said. The FOB Singapore 10 ppm sulfur gasoil derivative crack spread to front-month Dubai swap -- a measure of the product's relative strength to the crude it was refined from -- widened 18 cents\/b on the day to $16.28\/b at the Asian close Aug. 14. At this level, the gasoil swap crack was trading at a 90 cents\/b premium to that of co-distillate jet fuel\/kerosene, Commodity Insights data showed. ","headline":" July middle distillates demand falls 9% to 10-month low","updatedDate":"2024-08-15T02:44:42.000"},{"Unnamed: 0":63,"body":" Colombia's Ecopetrol will lower its crude production in the second half of the year as output from its Permian operations stabilizes after record levels, management said Aug. 14 during its second-quarter earnings call with analysts. Production in H1 2024 has been \"way above the range\" as a result of increased activity in the US Permian Basin, management said. As output stabilizes, the overall production of the company will fall from the 750,000 b\/d registered so far this year into the company's guidance of between 730,000 b\/d to 735,000 b\/d, management said. Ecopetrol has operations in the Permian through one of its subsidiaries. \"The production of Permian has been high in the first half of the year because of the large activity and the plans we had. But in the second half of the year, it will decline,\" Rafael Guzm\u00e1n, executive operating vice president said during the call, adding that currently Permian output is above 90,000 b\/d, but for the second half of the year it is expected to fall to around 80,000 b\/d. The company also has some \"uncertainties\" in Colombia for the second half of the year, as there is a risk of delays because of third parties. In terms of natural gas, the company said it is committed to Colombia's energy security and is focused on executing its 2024-2034 gas road map, which involves maximizing domestic onshore and offshore production, as well as exploring various alternatives related to regasification and energy imports. Among the alternatives under evaluation is the utilization of Colombia's natural gas regasification terminal, with capacity of up to 530 MMcf\/d. Other reclassification options with capacities of up to 1 Bcf\/d are being considered in projects located in various areas, from Buenaventura to Navarra, management said. ","headline":"Colombia's Ecopetrol to lower crude production in H2 as Permian operations stabilize","updatedDate":"2024-08-14T23:22:48.000"},{"Unnamed: 0":64,"body":" Mexico\u2019s state-owned Pemex has raised the K factor, or constant terms, for all its crude grades to East Asia, or what Pemex labels the Far East, for September, its PMI trading arm said Aug. 14. For other regions, the changes varied, according to a PMI notification. The K factor for Maya increased by 15 cents\/b to minus $9.35\/b to eastern Asia, while the Zapoteco price rose $1.15\/b to minus $7.40\/b, Pemex said in an email. Isthmus to East Asia rose 75 cents\/b to minus $8.20\/b, and Olmeca rose $1.20\/b to minus $5.10\/b. To the US Gulf Coast, the US Atlantic Coast and the Caribbean, Maya declined by 55 cents\/b to minus $10.10\/b, while the Zapoteco price increased 15 cents\/b to minus $4.00\/b. Isthmus to the region declined 20 cents\/b to minus $3.70\/b, and Olmeca rose 40 cents\/b to minus $1.45\/b. Pemex K factors ($\/b) Delivery region and crude grade August K factor September K factor Change USGC, USAC Maya -9.55 -10.10 -0.55 Zapoteco -4.15 -4.00 0.15 Isthmus -3.50 -3.70 -0.20 Olmeca -1.85 -1.45 0.40 USWC Maya -7.25 -7.25 0.00 Zapoteco -4.70 -3.65 1.05 Isthmus -8.20 -8.20 0.00 Olmeca -6.70 -5.35 1.35 Europe, Middle East Maya -8.40 -9.05 -0.65 Zapoteco -8.30 -7.60 0.70 Isthmus -8.25 -7.25 1.00 Olmeca -6.30 -5.55 0.75 India Maya -10.20 -10.55 -0.35 Zapoteco -8.75 -8.75 0.00 Isthmus -7.30 -7.50 -0.20 Olmeca -6.50 -6.40 0.10 Far East Maya -9.50 -9.35 0.15 Zapoteco -8.55 -7.40 1.15 Isthmus -8.95 -8.20 0.75 Olmeca -6.30 -5.10 1.20 Source: PMI ","headline":"Pemex increases Sep K factor for crude to East Asia; prices vary for other regions","updatedDate":"2024-08-14T21:55:02.000"},{"Unnamed: 0":65,"body":" Neuqu\u00e9n, the biggest oil and natural gas province in Argentina, aims to rapidly expand oil and natural gas production from the Vaca Muerta shale play over the next few years as facilities are built to increase exports, Governor Rolando Figueroa said Aug. 14. \"We expect to nearly triple Vaca Muerta's oil production by 2030,\" he told S&P Global Commodity Insights on the sidelines of a business conference organized by the Americas Society\/Council of the Americas in Buenos Aires. That would take output from Vaca Muerta, one of the world's biggest oil plays, to above 1.1 million b\/d from 380,000 b\/d in June, according to a calculation based on data from the province's energy ministry. Gas production is on track to double by 2030, Figueroa added. Based on official data, that would take gas output to 180 million cu m\/d from 90 million in June. The estimates come as more takeaway capacity is built in Vaca Muerta, boosting the potential for exports from the play in northern Patagonia. Argentina consumes some 525,000 b\/d of oil and 140 million cu m\/d of gas, meaning that with national production now at 680,000 b\/d and 140 million cu m\/d, any further growth in production must come from exporting. Building export capacity YPF, the state-run energy company, is starting to build pipelines and export terminals to handle up to 800,000 b\/d of crude shipments for the entire industry by 2028, while other projects have recently started or are in the works to increase the total export capacity to 1.4 million cu m\/d. At the same time, YPF is working on a project with Malaysia's Petronas for the industry to export 120 million cu m\/d of LNG by 2031. These projects will build on the country's exports of 168,000 b\/d of crude in the first half of this year and some 5 million cu m\/d of gas, according to industry and government data. From shortage to abundance Vaca Muerta's gas production would triple from current levels once the LNG facility reaches full-scale operation, Figueroa said That would take it to 270 million cu m\/d in 2031, according to the data. \"Argentina has changed the paradigm from an oil and gas shortage to the phenomenon of abundance,\" the governor said in a speech at the event. Vaca Muerta has enough resources to supply six times more than Argentina's expected demand over the next 30 years, he said. \"We have a window of time to monetize all of it,\" he said. Figueroa said that Vaca Muerta will allow Argentina to export $30 billion worth of oil and gas by 2030-31, which he said is equivalent to the country's agricultural exports but \"without the climate risk.\" ","headline":"Argentina's Neuqu\u00e9n aims to triple Vaca Muerta oil, gas output by 2031: governor","updatedDate":"2024-08-14T21:36:50.000"},{"Unnamed: 0":66,"body":" North Dakota bidders paid a total of $4.98 million for rights to drill and produce on 303 state-owned parcels spanning 24,436 net acres in the latest oil and gas lease sale that concluded Aug. 14, according to sale bidding platform Energynet.com. State sales, while not as spectacular in dollar amounts reaped, could help boost the production of some of the lesser-producing counties that have non-core but potentially productive acreage that needs a little more work and up-to-date technology to make it profitable, North Dakota officials have suggested recently. The highest bid in the two-day auction, sponsored by the North Dakota Department of Trust Lands, was more than $462,000 for a 80-acre net parcel in McKenzie County -- where a handful of other relatively large bids in the six-figure range were also placed, according to S&P Global Commodity Insights analysis showed using Energynet.com bid and acreage figures. That bid offered $5,776\/acre, also the highest per-acre amount. The auction featured acreage in 11 producing counties, although the highest bids and bids per acre were captured in McKenzie County, which is North Dakota's largest oil producing county in the core of the Bakken Shale. Bid amounts ranged from three figures to the mid- to mid-six figures, although a large number appeared to be five-figure bids. Typical size for parcels was about 160 gross acres or 80 net acres, although some tracts were as small as a few acres, an analysis by S&P Global Commodity Insights shows. Divide County, in far northwestern North Dakota, offered the largest number of parcels with 97, followed by 66 for Burke, Stark with 51 and Dunn with 31. Total 315 parcels offered in sale In all, 315 parcels were offered in the sale were spread over 42,724 gross acres. Twelve tracts did not receive any bids. Minimum bids\/acre on most of the parcels in the auction started at $2, although few parcels actually sold for that amount. Acreage in some counties received relatively low per-acre bids \u2013 in Stark County, for instance, bids mostly were in the one or two digits per acre, although a few tracts did receive bids in the $100s\/acre. But some of those counties may be important to future production in a state where Tier 2 and Tier 3 acreage -- less desirable lands -- are being converted to higher-quality Tier 1 through efficiencies that raise production per well at lower cost. For instance, improved completions such as multiple simultaneous hydraulic fracturing of wells speeds up the work necessary to get wells on production. That, and other continuous improvements that allow faster drilling of wells with more capable rigs, tools and chemicals, also have helped smooth and ease the process of getting more output from wells at a faster pace. And in the process, the acreage becomes more valuable. Moreover, some recent merger and acquisition activity in the Williston Basin, which encompasses North Dakota, may also take advantage of acreage in non-core counties to leverage the benefit of the merger partners' expertise in raising production, North Dakota officials have said in recent industry talks. M&A may boost output on non-core lands For example, the pending acquisition of Marathon Oil by ConocoPhillips, both of which operate in the Bakken Shale, could \"bring a lot of new ideas and technologies to areas that have Tier 2 and 3 geology,\" Lynn Helms, former oil and gas director for North Dakota's Department of Mineral Resources for 26 years, said during a June webinar. Helms has since retired. The largest oil producing counties are McKenzie at about 374,000 b\/d, Dunn at around 284,000 b\/d, Williams at around 228,500 b\/d and Mountrail at around 202,700 b\/d -- all May 2024 figures, according to the DMR. Those four counties, sited in west-northwest North Dakota, accounted for over 90% of North Dakota's total oil output in May of 1.195 million b\/d, DMR figures showed, while natural gas production the same month was 3.4 Bcf\/d. North Dakota officials have said they plan to ramp up efforts to issue permit for more oil and gas wells to keep up with the demand so the state can grow its oil output 1%-2%\/year. A two-day state Trust Lands oil and gas sale in February 2024 captured high bids of $6.96 million, receiving bids for 364 tracts covering 32,797 acres. North Dakota officially has had 19 producing counties over the years, although at least three of them -- Adams, Hettinger and Mercer, in the west to southwest part of the state -- have not produced any sizable volumes for at least 20 years and in some cases much longer. ","headline":"North Dakota state oil, gas lease sale nets $4.98 million on 303 parcels","updatedDate":"2024-08-14T20:59:50.000"},{"Unnamed: 0":67,"body":" Chubut and Mendoza, two of the biggest oil provinces in Argentina, expect to see a pickup in investment in exploration and production as new federal incentives spur an overall increase in activities in the sector, governors of both provinces said Aug. 14. The Incentive Framework for Large Investments, or RIGI for its Spanish acronym, was approved in June to provide 30 years of legal and regulatory stability for projects of at least $200 million, plus tax breaks and other benefits. While the incentives are not for smaller projects like oil drilling, they should \u201cgive a boost\u201d to investments overall, Mendoza Governor Alfredo Cornejo said at a business conference organized by the Americas Society\/Council of the Americas in Buenos Aires. In Mendoza, the fourth-largest oil producer in the country, there are opportunities for both conventional heavy oil and light shale oil, the latter in Vaca Muerta, one of the world\u2019s largest for oil and gas, he said. \u201cMendoza has the northern stretch of Vaca Muerta and it\u2019s undeveloped,\u201d Cornejo said. \u201cWe believe there is enormous potential there.\u201d Vaca Muerta, one of the world\u2019s biggest shale plays, is leading a surge in oil production in Argentina. The play\u2019s acreage in Neuqu\u00e9n, due south from Mendoza, produced 94% of its 401,000 b\/d of crude in June, up 25% on the year. That offset declines in conventional fields elsewhere in the nation to increase national output 6.5% to 660,414 b\/d over the same period, according to data from the Argentinian Energy Secretariat. Conventional oil shows potential In the southern province of Chubut, there is still potential for production growth in conventional reserves, Governor Ignacio Torres said. \u201cVaca Muerta may be the showcase for the development of hydrocarbons, but there are mature conventional basins that still have enormous potential like in Chubut,\u201d he said at the event. While the federal incentives will help bring more investment to Argentina, Torres said that more must be done to improve conditions to boost exports so that there is more capital available for investing. To access foreign currencies, he said conditions must be improved to export, such as building more efficient and competitive roads, ports and other infrastructure. \u201cWe need to resolve these bottlenecks,\u201d Torres said. Chubut produces 20% of Argentina\u2019s oil, while Mendoza produces 8% and Neuqu\u00e9n accounts for 57% of the total. ","headline":"Argentina provinces see pickup in oil investment with federal incentives","updatedDate":"2024-08-14T20:42:14.000"},{"Unnamed: 0":68,"body":" Crude oil futures settled lower Aug. 14 on the heels of a surprise US inventory build. NYMEX September WTI fell $1.37 to settle at $76.98\/b, and ICE October Brent dipped 93 cents to end the session at $79.76\/b. US commercial crude stocks climbed 1.36 million barrels in the week ended Aug. 9 to 430.68 million barrels, US Energy Information Administration data showed Aug. 14. The counter-seasonal build left inventories still 4.3% behind the five-year average of EIA data, in from a deficit of 5.5% the week prior. The build ran against market expectations. Analysts surveyed by S&P Global Commodity Insights Aug. 12 had pointed to a 3.73 million-barrel decline over the period. Blunting the price impact of the build was a 1.67 million-barrel draw at the NYMEX delivery hub of Cushing, Oklahoma. Cushing stocks now stand at 28.76 million barrels and are at the lowest outright level since early February. NYMEX September RBOB fell 5.36 cents to $2.3211\/gal, and September ULSD finished down 2.10 cents at $2.3682\/gal. The closely watched US Consumer Price Index showed July prices climbed 0.2% from June. The print was in line with market expectations and put annual US inflation at 2.9%, the slowest since March 2021. The easing inflation outlook renewed expectations that the Fed is on track to start its monetary easing cycle soon, which would boost economic activity and crude demand, analysts said. \"The market mood has shifted back toward rate cuts again in the last 24 hours, with US PPI data coming in on the soft side ahead of today's [consumer price index] numbers,\" analysts at ING said. But other analysts noted that slowing inflation could present near-term headwinds for crude prices. \"US producer prices rose less than expected in July,\" analysts at Global Risk Management said. \"This led speculative investors to take profits in oil, which some investors buy to hedge against inflation, in order to capitalize on the gains in the stock market that benefit more from lower inflation and interest rates.\" ","headline":" Crude slides following surprise US inventory build","updatedDate":"2024-08-14T20:04:37.000"},{"Unnamed: 0":69,"body":" US crude oil inventories moved higher in the week to Aug. 9, US Energy Information Administration data showed Aug. 14, as an uptick in refinery demand still left runs below their early-summer highs. US commercial crude stocks climbed 1.36 million barrels in the week ended Aug. 9 to 430.68 million barrels, the EIA said. The counter-seasonal build left inventories still 4.3% behind the five-year average of EIA data, in from a deficit of 5.5% the week prior. The build ran against market expectations; analysts surveyed by S&P Global Commodity Insights Aug. 12 had pointed to a 3.73 million barrel decline over the period. Notably, inventories at the NYMEX delivery hub of Cushing, Oklahoma, declined 1.67 million barrels. Cushing stocks now stand at 28.76 million barrels and are at the lowest outright level since early February. Refinery net crude inputs climbed 70,000 b\/d to 16.47 million b\/d while overall refinery utilization jumped 1 percentage point to 91.5% of capacity. The uptick put net crude inputs at a five-week high and around 1.2% above normal for this time of year, but left them around 4% below their most recent peak in early July. Most US refiners stated in recent second-quarter results call their total third-quarter refinery run rates will be lower than actual second-quarter refinery throughput as they seek to balance output with slowing demand, thus providing some support for weakening refining margins, according to an Aug. 13 Commodity Insights analysis. \"We think [third-quarter] utilization will reflect some modest economic optimization, and is an encouraging sign that ultimately could help balance the market if demand shows improvement in the second half,\" John Royall, analyst with JP Morgan, said in a recent note. US crude exports averaged 3.76 million b\/d, climbing 120,000 b\/d from an eight-week-low seen the week prior. Overall export remain relatively weak, however, with weekly exports holding below the four-week moving average for two weeks running. The arbitrage incentive for moving Mars crude into China versus Dubai crude has averaged minus 45 cents\/b to-date in August, Commodity Insights data showed Aug. 14, down from 9 cents\/b in July. Nationwide gasoline stocks retreated 2.89 million barrels to 222.2 million barrels, falling 2.4% behind average, while distillate inventories declined 1.67 million barrels to 126.12 million barrels. The draws come amid a general uptick in demand. Implied demand for gasoline and distillates each climbed 80,000 b\/d, to 9.05 million b\/d and 3.55 million b\/d respectively. ","headline":"US crude stocks unexpectedly climb as refinery demand holds below early summer highs","updatedDate":"2024-08-14T20:00:58.000"},{"Unnamed: 0":70,"body":" YPF, the biggest oil and natural gas producer in Argentina, said Aug. 14 it reached a deal to sell six maturing conventional blocks in Mendoza province to a local consortium of Quintana Energy and TSB, as well as a tight gas block in R\u00edo Negro province to Quintana. The cluster of six blocks in southern Mendoza is producing some 2,000 b\/d of oil and 840,000 cu m\/d of gas, while the tight gas block, called Estaci\u00f3n Fern\u00e1ndez Oro, is producing 1,400 b\/d of oil and 890,000 cu m\/d of gas, according to YPF. Quintana is a small oil producer with blocks in southern Argentina and Chile, while TSB is an oil services company. For YPF, the deals take the number of conventional blocks that the state-run company has sold to 22 since launching a plan earlier this year to divest its non-core assets to focus on Vaca Muerta, one of the world\u2019s largest shale plays. The first deals were reached Aug. 5 for 15 blocks in the provinces of Chubut, Mendoza, Neuqu\u00e9n and R\u00edo Negro. With these latest agreements, there are still 33 out of a total of 55 blocks still up for sale. YPF has said it wants to complete the divestment by the end of this year. The divestments will allow the company to focus on developing Vaca Muerta in northern Patagonia, where the costs are lower to produce oil and gas in terms of each dollar invested. The play is driving YPF's oil and gas production growth and boosting its export potential, with projects in the works that would enable the local industry to export up to 800,000 b\/d of crude by 2028 and up to 120 million cu m\/d of gas by 2031. Argentina\u2019s total exports were 168,000 b\/d of crude and some 5 million cu m\/d of gas in the first half of 2024, according to industry and government data. ","headline":"Argentina's YPF selling another seven conventional fields to focus on Vaca Muerta","updatedDate":"2024-08-14T19:45:18.000"},{"Unnamed: 0":71,"body":" US Gulf Coast sour crude Mars reached its lowest differential to the WTI basis in nearly one year on Aug. 14 as demand for the grade has dwindled. September barrels of Mars were heard trading as low as cash WTI minus $2.40\/b, after also trading at minus $2.15\/b. That's lower than Platts' previous-day assessment of cash WTI minus $1.50\/b. Platts is part of S&P Global Commodity Insights. Mars has not been assessed lower since Sept. 25, 2023, when it was at a $2.60\/b discount to cash WTI, and dropped this week by $1.50\/b from Aug. 9. Lower expected refinery run rates, lackluster export demand and slim refining margins could be pressuring sours on the coast, sources said. \"I imagine exports aren't working,\" one market participant said. \"I think rate cuts are the big untold story.\" International buying demand for US sours due to a thin Brent\/WTI spread, coupled with refineries easing back crude runs may be resulting in domestic oversupply. USGC crude inventories, excluding the Strategic Petroleum reserve, rose 55.7 million barrels to 244 million barrels for the week ended Aug. 9, according to the Energy Information Administration. Many US refiners also have stated that total third-quarter refinery run rates will be lower than actual second-quarter refinery throughput as they seek to balance output with slowing demand in efforts to provide some support for weakening refining margins, according to an Aug. 13 Commodity Insights analysis. Coking margins for Mars on the USGC sank to $9.82\/b on Aug. 13, according to the latest data from Commodity Insights. That was down from the five-day average of $10.84\/b and the month-to-date average of $11.67\/b. ","headline":"Mars sour crude tumbles to lowest differential in nearly a year","updatedDate":"2024-08-14T18:58:37.000"},{"Unnamed: 0":72,"body":" Canada's Strathcona Resources is shipping incremental heavy oil volumes from its Western Canadian asset base, following the start up of a new crude-by-rail offloading terminal on the US Gulf Coast, CEO Rob Morgan said Aug. 14. \u201cThe terminal was purpose built to handle our Lloydminster thermal crude and in the second quarter saw a drawdown of oil from storage, equal to about 4,000 b\/d,\u201d Morgan said on a webcast to discuss the company\u2019s second-quarter earnings. He did not indicate the current volume of shipments, but Strathcona said on its first-quarter earnings call in mid-May that its target is to have the capacity to ship up to 50,000 b\/d in rail cars to the USGC. In Q1, Strathcona had averaged crude shipments of 30,000 b\/d, it said then, adding the company had teamed up with two long-term buyers on the USGC. Strathcona has the ability to ship barrels from the Hamlin loading terminal in Saskatchewan without there being a need to blend the heavy crude grade with diluents and reducing the cost of transportation, according to information on Strathcona\u2019s website. The crude volumes are railed directly to the USGC and offer a $10\/b uplift when compared with a typical Athabasca oil sands pipeline, the information said. \"Total oil production for the second quarter was consistent with the first quarter of around 131,000 b\/d, while oil sales volume increased to 135,000 b\/d due to the drawdown of inventories with the commissioning on the new terminal,\u201d Morgan said. Total heavy and light oil, NGL and natural gas production last quarter was 181,766 b\/d of oil equivalent, up 26% compared with 143,778 boe\/d in the same quarter of 2023, Strathcona said in its earnings release. Of the total production last quarter, bitumen accounted for 59,581 b\/d, followed by heavy oil at 51,111 b\/d, condensate and light oil at 20,120 b\/d and natural gas at 257 MMcf\/d, it said. Current focus areas, CCS project Total capital spending last quarter was C$297 million ($216 million) and current activity remains concentrated in Edam, Lloydminster, where four well pairs are being executed, Morgan said, noting Strathcona will drill its first multi-lateral at Druid targeting the Mannville stack. At the same time, the company is progressing a brownfield expansion at one of its Meota West facilities, which will add a sixth steam generator and is scheduled to come on stream by late 2025, he said. Natural gas production was 16 MMcf\/d lower compared to the Q1, due to a combination of planned and unplanned outages at third-party gas facilities in Grand Prairie and Kakwa. Also, the company elected to shut in volumes at the Groundbirch plant due to the low prices. At Groundbirch, Strathcona finished drilling and completing its three-well pad and completed a short-term productivity test before shutting them in. Given the ongoing weakness of natural gas prices, Strathcona has deferred bringing the shut-in wells to production until prices improve. \u201cWe hope to see recoveries late this year and we will look to start dry gas production from Groundbirch,\u201d Morgan said. Meanwhile, Strathcona has started detailed front-end engineering work for its carbon capture project to be built in Saskatchewan under a partnership with Canada Growth Fund, he said. \u201cA final investment decision is targeted in mid-2025 and by mid-2027 the aim will be to have a 200,000 mt\/year CCS [carbon capture and storage] facility to start with, and then follow up with a bigger footprint,\u201d CFO Connor Waterous said on the same webcast. All of Strathcona\u2019s oil sands facilities in the Lloydminster and Cold Lake regions lie directly atop suitable carbon dioxide storage reservoirs, allowing for local injection, the company said, adding in the current year the Saskatchewan government granted Strathcona subsurface CO2 sequestration rights. Strathcona currently produces around 90,000 b\/d of heavy oil and bitumen from its steam-assisted gravity drainage assets, with associated emissions of nearly 3 million mt\/year of CO2, it said. ","headline":"Canada's Strathcona ramps up delivery of crude in rail cars to the USGC","updatedDate":"2024-08-14T18:16:07.000"},{"Unnamed: 0":73,"body":" Peru's government Aug. 14 called a bid round for two north coastal oil production blocks, as the Andean country seeks to halt declining crude production. Companies are to submit bids on Feb. 10, 2025 for Blocks 1 and 6, and the 30-year contracts will be awarded Feb. 17, Jorge Pesantes, head of state contracting agency Perupetro, said at a presentation ceremony in Lima. Block 6, a 13,772-hectare property in the Talara Basin, is currently producing 2,000 b\/d of crude and 3,800-Mcf\/d of natural gas at 500 wells, according to Perupetro. Bidders will have to commit to drilling at least 71 development wells and 33 well makeovers. Block 1, a 6,915-ha property in the same basin, is currently producing 500 b\/d of crude and 3,000-Mcf\/d of natural gas at 214 wells. The contract establishes a minimum commitment of 32 development wells and 64 well makeovers. Both blocks have been operated by state oil company Petroperu since October 2023. Since then, President Dina Boluarte has replaced the heads of the Energy & Mines Ministry, Perupetro and Petroperu with more investor-friendly officials as investment in Peru's oil and gas sector fell to $324 million in 2023 from a peak of $1.88 billion in 2012. \"There are many contracts in force majeure due to social conflicts and lack of predictability for investment decisions. There's a long list of factors that are a constant threat,\" Pesantes said at the ceremony. \"The oil and gas situation is critical. We have to turn this situation around, or else the sector won't recover.\" Perupetro, which awarded three E&P blocks earlier in the year, has put together a list of 47 E&P coastal and jungle blocks to be put up for bids, according to a presentation. Peru, which crude production hit a 10-year high in 2019, has yet to recover to pre-pandemic levels as companies, including Frontera Energy and Pluspetrol, pulled out of northern jungle blocks. Peru was producing 41,878 b\/d through June, according to Perupetro. ","headline":"Peru's govt calls a bid round for two northern coastal oil production blocks","updatedDate":"2024-08-14T17:58:05.000"},{"Unnamed: 0":74,"body":" The balance-month -- currently August -- Dated to Frontline contract gained 22 cents\/b Aug. 14 from the previous close and was assessed at the highest level since March. The DFL represents the difference between ICE Brent futures and Dated Brent. Platts, part of S&P Global Commodity Insights, assessed the balance-month DFL contract at $1.90\/b Aug. 14, the highest since March 4. The five-month high for the contract comes just one week after Platts assessed the contract at minus 25 cents\/b Aug. 6, which marked a two-month low. The rebound in the balance-month DFL contract has widened the backwardation between the balance month and month 1 DFL contracts to $1.29\/b Aug. 14, the steepest backwardation since February. Platts assessed the month 1 -- currently September -- DFL contract at 61 cents\/b Aug. 14. The strengthening in the balance-month DFL contract is typically a bullish signal for the prompt physical crude market. In the adjacent Brent CFD market, contracts continued to strengthen through the day, with the first four weeks seeing gains in value. Platts last assessed the Aug. 19 -23 contract -- the second-promptest week -- at $2.80\/b, the highest level since April 8 when the contract reached $2.85. Similarly, the balance-week contract, currently settling across Aug 12-16, was assessed at $3.44, its highest level since March 4 when the contract was assessed at $3.67. Surging prompt values have served to widen the backwardation in the complex, as later weeks have weakened across recent sessions. Traders have previously pointed to a tight market for prompt physical crude as driving the gains in the paper market. ","headline":"Prompt DFL and Brent CFDs see continued strength","updatedDate":"2024-08-14T17:35:22.000"},{"Unnamed: 0":75,"body":" Tehran oil refinery\u2019s gasoline production project, which includes a CCR, or continuous catalytic reformer, has reached 86% progress, the plant\u2019s managing director, Mohsen Iranzad, said Aug. 14 in a statement posted on the National Iranian Oil Refining and Distribution Co. website. The gasoline project will become operational next year, Mohsen Iranzad, the plant\u2019s managing director, said, with the CCR going onstream in June 2025. Tehran refinery has also received permission to sell its heavy naphtha, Iranzad said. Currently it exports LPG to Afghanistan and Pakistan but is also \"expanding towards Turkey and South Africa,\" Iranzad said, adding that the refinery is also pursuing \"exports of fuel oil to such countries as India.\u201d The CCR project will improve the quality of gasoline and increase the amount of gasoline meeting Euro V specifications, S&P Global Commodity Insights has reported previously. The first phase of the complex includes the construction of a 16,000 b\/d heavy naphtha hydrotreating unit, or NHT. ","headline":" Iran's Tehran refinery gasoline upgrade reaches 86% progress","updatedDate":"2024-08-14T17:25:22.000"},{"Unnamed: 0":76,"body":" Germany's Holborn refinery has awarded Topsoe a contract for its HydroFlex technology for production of sustainable aviation fuel and renewable diesel from waste and residue materials, Topsoe said Aug. 14. Holborn's renewable fuels complex is expected to be operational in early 2027 and aims to produce 220,000 metric tons per year of renewable diesel and SAF, Topsoe said. Holborn awarded earlier this year KT-Kinetics Technology and NextChem, both part of the Maire Group, an EPC contract for developing the HVO complex inside the Hamburg refinery. Platts, part of S&P Global Commodity Insights, assessed SAF CIF ARA at $2,158.75 on Aug. 13. ","headline":" Germany's Holborn awards contract for SAF production technology to Topsoe","updatedDate":"2024-08-14T17:17:53.000"},{"Unnamed: 0":77,"body":" Kenya plans to streamline its heavy fuel oil imports through a single operator in a move aimed at reducing high energy costs, according to officials, as residual fuels continue to play a significant role in the country's power generation. Speaking late Aug. 13, Kenya Power CEO Joseph Siror told local media the government plans to introduce an Open Tendering System (OTS) for its power producers importing residual fuel, in the hope that the new mechanism will deflate electricity prices and the cost of living. Filtering the country's fuel oil sourcing through the OTS would mark a pivot from the current practice of power generators sourcing their own supplies, typically from Saudi Arabia and the United Arab Emirates, Siror said. According to S&P Global Commodities at Sea data, Kenya imported an average of around 4,000 b\/d of residual fuel in 2023, though levels have proved volatile in recent years. Imports spiked to an all-time high of 39,000 b\/d in November 2023 and have averaged 26,000 b\/d over Aug. 1-14, according to CAS data. According to Commodity Insights analysts, Kenya consumed 7,000 b\/d residual fuel oil in 2023, with power generation accounting for more than half of its demand. The single-sourcing system would secure a uniform price for power producers, Siror said, using a monthly procurement process from the spot market similar to the current system used by Kenya's Oil Marketing Companies. The OTS would offer greater efficiency and economies of scale to disparate fuel oil importers, he suggested, adding that sales agreements would be conducted in Kenyan shillings, which could help to stabilize the currency. Kenya's Ministry of Energy and Petroleum is currently in advanced talks with stakeholders on implementation of the OTS, he said, noting that the government was engaging with thermal power generators, the Energy and Petroleum Regulatory Authority (EPRA) and Kenya Power on the plans. The move follows pressure on the Kenyan government to address cost-of-living concerns inflamed by high fuel and electricity costs, which sparked protests in recent months. In July, President William Ruto dismissed almost all his ministers and added some opposition members to form a broad-based government, responding to pressure to take action to support the country's economy. The country has aimed to pivot from residual fuel for its power generation to cleaner alternatives, with the Senate last year proposing a switch to LNG for power production. A switch from residual fuel would help Kenya to capitalize on its domestic LNG production plans promising further price drops, proponents have argued, though the move remains contingent on necessary infrastructure developments. With the country still reliant on residual fuel oil for its power generation in the interim, Commodity Insights analysts forecast demand will climb to 7,100 b\/d in 2025, reaching 8,100 b\/d by 2045. Power generation currently makes up the main use case for fuel oil imports, followed by industrial applications, while bunkering demand has declined since 2018. ","headline":"Kenya plans single sourcing for HFO imports to curb power costs","updatedDate":"2024-08-14T16:39:42.000"},{"Unnamed: 0":78,"body":" Iran\u2019s government has given a green light to an expeditious plan to raise crude output by 250,000 b\/d, the National Iranian Oil Co. said on its website Aug. 14. Following an NIOC request, the plan to urgently increase oil output by 250,000 b\/d from 34 fields was approved. The plan's \"executive strategy\" will be determined in an agreement among the Planning and Budget Organization, Central Bank of Iran and NIOC, the state Economy Council decided July 12, the NIOC said. In the first half of 2024, Iran\u2019s crude and condensate production reached 3.97 million b\/d, rising 630,000 b\/d on the year, according to Commodity Insights data. Iran produced 3.2 million b\/d of crude in July, according to the latest Platts OPEC+ survey, up 440,000 b\/d from a year earlier and the highest since October 2018, despite Western sanctions. There were no more details about the timetable as to when the increased output would be realized, however, oil minister Javad Owji had previously spoke of a plan to raise the total output to 4 million b\/d by end of the current Iranian year (March 20, 2025). On June 26, he put the OPEC member\u2019s average output at 3.57 million b\/d. Iran has been adding to its output barrel-by-barrel, repairing aged facilities and bringing back to life those oil wells it had to shut down to manage production under the US imposed restrictions on its oil sales. The latest increase of oil production capacity came from the massive South Azadegan oil field with 2,500 b\/d by bringing online two oil wells. South Azadegan was planned to have reached 320,000 b\/d in 2023 by reconstructing 17 unused wells. However, managing director of Petroleum and Development Co. or PEDEC, Abouzar Sharifi, said July 30 that the onshore oil field\u2019s production stood at 140,000 b\/d, pushing forward the big target to September 2025, oil ministry news service Shana reported. Sharifi said that the Economy Council was going to approve an integrated development plan for North and South Azadegan by two oil companies, six banks and the oil income saving fund or the National Development Fund. A contract worth $11.5 billion was signed in March for the integrated project. Azadegan oil field with 32 billion barrels of oil in place straddle borders with Iraq. ","headline":"Iran adds new oil output capacity at South Azadegan","updatedDate":"2024-08-14T16:37:44.000"},{"Unnamed: 0":79,"body":" Marathon Petroleum reported it plans to flare at its 365,000 b\/d Carson, California, refinery beginning Aug. 14 through Aug. 28, according to a filing with local regulators Aug. 13, which had an impact on Los Angeles area refined product prices. In the filing made with the South Coast Air Quality Management District, Marathon gave the reason for the flaring as start up\/shutdown but did not provide more details on which units were impacted. Marathon gave third-quarter operational guidance for its West Coast refineries -- which include its 145,000 b\/d Anacortes, Washington, refinery -- of 93% capacity, with crude throughput averaging 515,000 b\/d, 3,000 b\/d lower than the actual Q2 throughput. On Aug. 8 and Aug. 9, Marathon filed with the SCQAMD for two unplanned events at the plant. A company spokesperson was not immediately available for comment on which part of the refinery would be impacted by the outage. However, Los Angeles refined product prices -- particularly CARBOB gasoline and jet fuel -- reacted on snags at the plant, according to market sources. On Aug. 13, Los Angeles CARBOB prices spiked, despite a bearish NYMEX September RBOB futures contract, with Platts assessments showing a regular increasing of 7 cents to futures plus 9 cents, while premium was assessed at futures plus 21 cents despite ample supply of gasoline. Weekly US West Coast production of gasoline hit a one-year high for the week ended Aug. 9, rising for a fifth consecutive week to 1.495 million barrels, most recent Energy Information Administration data released Aug. 14 showed. That is up by 10,000 b\/d from the week prior, 85,000 b\/d from mid-July, and the highest since the week to Aug. 4, 2023, when production stood at 1.496 million b\/d. USWC CARBOB inventories rose 294,000 barrels to 31.174 million barrels on the week. USWC jet fuel also reacted to the outage news, with Los Angeles jet fuel prices climbing 7 cents\/gal to NYMEX September RBOB futures on Aug. 13 compared with Aug. 12, as regional production fell amid strong demand for the aviation fuel. Most recent EIA data showed USWC jet production fell by 44,000 b\/d to 444,000 b\/d in the week ended Aug. 9. That is lower by 104,000 b\/d from three weeks prior, when the EIA measured the highest output on record dated back to August 1982. Pricewise, CARB diesel appeared to unaffected by Marathon's outage, holding a 7-cent\/gal discount to NYMEX September ULSD contract on Aug. 13, unchanged from the previous day. Weekly EIA inventory data showed diesel output slipped from a nine-month high, by 21,000 b\/d to 442,000 b\/d, in the latest week, while inventories fell from a three-month high, dropping 1.029 million barrels to 9.634 million barrels for the week ended Aug. 9. ","headline":" Marathon plans 15 days of work at Los Angeles area refinery; jet, CARBOB prices rise","updatedDate":"2024-08-14T16:06:14.000"},{"Unnamed: 0":80,"body":" Crude output at Azerbaijan's flagship ACG oil complex in the Caspian Sea edged up to 346,000 b\/d in July, its highest since November 2023, data from state-owned Socar showed on Aug. 14, as a new production facility helped stem the decline. ACG crude production rose from 345,000 b\/d in June, reflecting firmer volumes since the April startup of a new production facility within the ACG complex, known as Azeri Central East. The new facility has been producing from just one well, with output averaging 8,000 b\/d. However, this is set to rise to 24,000 b\/d by year-end with the addition of two more wells, BP said earlier. Crude production operated by Socar outside the BP-led ACG complex amounted to 138,000 b\/d in July, unchanged on the month and in line with monthly levels since the start of the year, the data showed. ACG plus Socar's operations account for almost all the country's crude production. The Azeri Light crude grade exported by pipeline to the Mediterranean port of Ceyhan derives predominantly from the ACG complex and commands strong prices due to its light, sweet quality, being sought for production of jet fuel and middle distillates such as diesel. Azeri Light was assessed by Platts at a premium of $1.95\/b compared with Dated Brent on Aug. 13. The Azeri Light blend also includes some condensate from Azerbaijan's Shah Deniz gas complex and oil delivered across the Caspian Sea to Azerbaijan from Kazakhstan and Turkmenistan. Deliveries through the pipeline to Ceyhan averaged 604,000 b\/d in the first half of 2024, down 4% on the year, according to BP data issued earlier. Azerbaijan is a member of the OPEC+ producer group, which has agreed limits on member states' output. However, the steady decline in Azeri crude production means it generally undershoots its agreed output ceilings. ","headline":" ACG crude output volumes reach highest level since November 2023","updatedDate":"2024-08-14T15:55:48.000"},{"Unnamed: 0":81,"body":" Some farmers in Romania have started harvesting the sunflower crop three weeks earlier than planned as crops dry out in the fields due to drought. A lack of rain and scorching temperatures have forced farmers to begin harvesting earlier compared with previous years, a farmer said. Romania has been among the top sunflower seed exporters in the world. Heat waves in July with temperature exceeding 40 C have destroyed significant volumes of corn and sunflower crops in Romania. In Dolj County, about 65% of the sunflower crop has been affected with many fields now entirely barren, according to market analysts and domestic farmers. Some farmers\u2019 crops were completely burnt. Out of the 1.3 million hectares of sunflowers planted, about 700,000 hectares have been affected by drought to varying degrees, said World Farmers\u2019 Organization President Arnold Puech d'Alissac. In some areas, farmers are expecting yield losses of up to 90%. \u201cIf in a good year, let\u2019s say, we made somewhere between 2.5 metric tons and 3 metric tons a hectare, this year we hope to reach 1 t\/ha,\" a Oltenia-based farmer said. \"Although from what we see here, we will certainly not reach that [target].\" In response to the widespread crop damage, the Romanian government has announced several supportive measures for farmers, including a compensation ranging from Euro 200\/ha to Euro 250\/ha for damaged crops. The total estimated funds for this drought compensation program are expected to be between Euro 500 million and Euro 600 million, according to some local media reports. Agriculture minister Florin Barbu has also requested the European Commission to grant urgent compensation to Romanian farmers. The National Meteorological Administration has warned that the drought in Romania is expected to persist, with no significant rainfall on the horizon. Romania\u2019s sunflower production in marketing year 2024-25 (July-June) could reach 2.41 million metric tons on 1.29 million ha land, according to the US Department of Agriculture. ","headline":"Romanian farmers begin early harvest of sunflower crop due to drought","updatedDate":"2024-08-14T14:34:39.000"},{"Unnamed: 0":82,"body":" The Amsterdam-Rotterdam-Antwerp bunker fuel hub saw the highest rate globally of off-specification very low sulfur (0.5%S) fuel oil in the second quarter, according to VeriFuel, a unit of French testing and inspection company Bureau Veritas. Some 3.9% of VLSFO batches missed specification targets in Q2, mainly the sulfur content, sediments and Al+Si specifications, Veri Fuel said. Houston had the next highest rate, at 2.7%. ARA also led in Q4 2023 and Q1 2024 in terms of off-spec VLSFO. In terms of viscosity of VLSFO in ARA, 161 CST was recorded for Q2, reflecting a decrease of 32 CST quarter on quarter. Elsewhere, viscosity increases were noted for the ports of Algeciras, Balboa, Las Palmas, Malta and Zhoushan . HSFO Meanwhile in the high sulfur (3.5%S) fuel oil market, the port with the highest off-spec HSFO rate in Q2 was Malta, where the figure stood at 11.1%, while Fujairah came in second at 7.7%, followed by ARA at 3.4%. The primary reasons for off-spec HSFO were viscosity and density requirements. In Q4 2023, no off spec HSFO was recorded, while in Q1 2024, the ARA region came in second place for the highest incidence of off spec HSFO, at 8.3%. HSFO ARA viscosity stood at 356 CST Q22024, down 1 CST quarter on quarter. As with VLSFO, viscosity also increased in HSFO, with notable increases at Algeciras, Gibraltar, Gothenburg, Hong Kong, Houston, Istanbul, Piraeus and Zhoushan. HSFO and VLSFO are the most prevalent bunker fuels in the ARA region, with Port of Rotterdam data showing VLSFO accounted for 34% of its Q2 sales while HSFO accounted for 37%. While the VLSFO fundamentals have been fairly weak over the summer, according to traders, demand has picked up slightly over the past few weeks. Within ARA, traders have noted a strong pull from Singapore, helping to move inventory out of the region. One Mediterranean-based trader said said \"bunkering demand has been going up ... but not dramatically\" within the region. In the HSFO market, despite a pull for the sulfur grade for power generation purposes from the Middle East for power generation for cooling purposes, bunkering demand in the Mediterranean was muted, sources said. Due to the increased transit risk associated with passing via the Suez canal to the Red Sea from potential Houthi attacks, vessels are opting for safe transit via the Cape of Good Hope. ","headline":"ARA has highest rate of off-spec VLSFO in Q2: VeriFuel","updatedDate":"2024-08-14T14:06:00.000"},{"Unnamed: 0":83,"body":" Periodic maintenance of CDU 4 at Israel's Haifa refinery has been completed, the company said Aug. 14. The maintenance of the 113,000 b\/d crude refining plant 4 has been originally planned to last 45 days in the fourth quarter of 2023 but was postponed to the second quarter of 2024 due to the war between Israel and Hamas. The maintenance was still ongoing at the end of June, the company had said previously. Platts Dated Brent assessment was at $83.295\/b Aug. 13. ","headline":" Maintenance at Israel's Bazan CDU completed","updatedDate":"2024-08-14T13:59:47.000"},{"Unnamed: 0":84,"body":" Hapag-Lloyd has expanded its fleet to meet stronger-than-expected ship requirements amid buoyant shipping demand and persistent Red Sea shipping disruptions, the German container line said Aug. 14 while reporting higher bunker consumption. In its interim report, the Frankfurt-listed company said its fleet size reached 287 boxships with 2.2 million TEU as of June 30, up from 258 ships with 1.9 million TEU a year ago. The latest additions include three 24,000-TEU and three 13,000-TEU ships. \u201cWe have added several new ships and containers to our fleet,\u201d CEO Rolf Habben Jansen said. \u201cThis has helped us to meet the additional capacity requirements resulting from the security situation in the Red Sea and the rerouting of ships around the Cape of Good Hope, thereby keeping supply chains intact.\u201d Yemen-based Houthi militants, claiming to support the Palestinians, have launched more than 100 attacks on merchant ships since the Israel-Hamas war broke out on Oct. 7. Many ship operators and cargo owners, including Hapag-Lloyd itself, have diverted their ships away from the Red Sea to sail around Africa on longer routes for crew safety, leading to higher bunker consumption and freight rates. Hapag-Lloyd reported its bunker usage reached 2.3 million metric tons in January-June, up 16.4% year on year. The percentage of its use of 0.1%S and 0.5%S bunker fuels and LNG fell to 77% from 83%, with the company receiving more scrubber-fitted ships that run on 3.5%S fuel, according to the report. The Platts Container Index, a weighted average of spot rate assessments on key routes, hit a 21-month high of $4,159.27\/FEU in late June, up from $781.20\/FEU on Nov. 22, 2023. It was last assessed at $3,517.13\/FEU Aug. 13. Hapag-Lloyd achieved an average freight rate of $1,422\/TEU in the second quarter, the highest since Q3 2023 but lower than $1,533\/TEU in the same period last year. Stronger outlook Other than Red Sea issues, the company said it has also benefitted from higher-than-expected shipping demand, with its container volume rising to 3.1 million TEU in Q2 from 3 million TEU in the year-ago period. Hapag-Lloyd\u2019s EBITDA fell to $991 million in Q2 from $1.4 billion in the same period of last year, Revenue stood at $4.8 billion, almost flat on the year. \u201cEven though we were unable to match the exceptionally good results of the prior year, we delivered a very good first half of 2024 thanks to strong demand and better spot rate,\u201d Jansen said. The company has raised its full-year EBITDA forecast to $3.5 billion-$4.6 billion for 2024, compared with $2.2 billion-$3.3 billion previously. ","headline":"Hapag-Lloyd expands fleet, uses more bunker fuels amid Red Sea issues","updatedDate":"2024-08-14T13:24:32.000"},{"Unnamed: 0":85,"body":" There have been minor incidents at refineries in Europe, some related to the heat wave. ** Increased flaring was reported at France's Feyzin late Aug. 12, according to local media. The flaring has been attributed by the company to maintenance at units of the refinery, Le Progres reported, citing a company statement. ** There has been an oil leak at a refinery in Nieuwdorp, the local safety authority said Aug. 10. Nieuwdorp is the site of Netherland's Zeeland refinery. The disturbance was temporary, the local authority said. ** France's Gonfreville refinery in Normandy said July 29 that increased flaring occurred after heat-related unit disruption. The refinery, which did not specify the affected unit, said later that following the adjustment of the unit the flaring and increased noise had finished. ** A unit adjustment caused flaring at France's Lavera refinery, it said late Aug. 9. The flaring has been visible during the night. ** Shell has resolved a malfunction at a unit at the Shell Energy and Chemicals Park Rotterdam (formerly Pernis) refinery which resulted in noise complaints from the local community. The company did not specify which unit has been affected. The malfunction, which was resolved Aug. 10, started late Aug. 9. Earlier the local environmental authority reported increased noise following problems with the catalytic cracker at the site which have caused other units to trip. Meanwhile, companies continued to report quarterly results, with throughput largely impacted by planned maintenance. ** Serbian refiner NIS said its Pancevo refinery processed 1.403 million metric tons crude and feedstocks during the first six months of the year, down 29% from H1 2023, it said in its second-quarter operational and financial results. It processed 762,500 metric tons in Q2, down 25% year on year. In March, the refinery carried out \"the most complicated and large-scale\" maintenance in its history. The maintenance began at the end of February and was completed in April. ** ExxonMobil's French downstream subsidiary Esso SAF reported Aug. 1 lower throughput at its French refineries in the first half of 2024 due to planned maintenance at Fos-sur-Mer and the outage of a CDU at Port Jerome-Gravenchon following a fire incident in March. The two refineries processed 5.4 MMt of crude oil in January-June, down from 7.1 MMt in the year-ago period. Fos-sur-Mer refinery restarted around mid-March after a maintenance which commenced Jan. 20. Port Jerome-Gravenchon has been operating at around 50% of capacity since a fire forced one of its two crude distillation units offline March 11. The offline units have been restarting \"successively\" since May 19. The company also said that despite the lower margins, the 24% reduction in throughput and the \"unprecedented situation\" following its decision to sell Fos-sur-Mer and reorganize the Gravenchon platform, it achieved good results. ** OMV Petrom reported a 95% utilization rate at its Petrobrazi refinery in the first half of 2024, up from 64% in the year-ago period, when it was undergoing a turnaround, it said July 31. Utilization was 98% in the second quarter, up from 31% in Q2 2023. Utilization for the full year is expected to be above 95% compared with 80% in 2023. The refinery processed 1.19 MMt in the second quarter, up from 380,000 metric tons in Q2 2023. It processed 2.31 MMt in January-June, up from 1.53 MMt in H1 2023. The Q2 indicator margin was $9.66\/b, down from $11.17\/b a year earlier. The H1 margin was $11.12\/b, down from $13.98\/b. The company expects the refining margin to be around $10\/b in 2024 versus $14\/b in 2023. ** Austria-based OMV expects the utilization rate at its European refineries to be around 90% in 2024, from 85% in 2023. The forecast has been revised down from 95% previously, it said in its second-quarter report on July 31. OMV reported an 89% utilization rate at its European refineries in the second quarter of 2024, up from 73% in the year-earlier quarter, and 87% in January-June, up from 83%. The higher Q2 rate followed lower utilization in 2023 when Petrobrazi carried out a turnaround. OMV's Q2 margin for Europe stood at $7\/b, down from $7.59\/b. The first-half margin was $8.9\/b, down from $11.31\/b. For 2024, the company expected a margin of around $8\/b, compared with $11.7\/b for 2023. ** Italy's Saras expected crude processing at its Sarroch plant of 96.5 million-98.5 million barrels (13.2-13.5 MMt) in 2024 to which approximately 1 MMt (around 7 million barrels) of feedstock will be added, it said July 31 in its quarterly earnings statement. It would be an increase from 2023 runs of 12.885 MMt, or 94.1 million barrels. H1 crude oil runs amounted to 6.478 MMt, up from 6.086 MMt in H1 2023. Other feedstock amounted to 534,000 metric tons in H1, up from 358,000 metric tons in H1 2023. Q2 throughput was 22.2 million barrels, up from 19.5 million barrels in the year-ago quarter. The higher runs were attributed to a lighter maintenance plan. Light extra sweet made up the biggest share of the crude slate at slightly more than 40% in the quarter and first half, followed by light sweet. The Saras margin stood at $9.40\/b in Q2, compared with $7.90\/b in Q2 2023, and at $10.80\/b in H1, compared with $12.60\/b in H1 2023. Separately Saras said Aug. 6 that the Vitol-controlled Varas Holding has acquired 51% of the company's share capital. ** Turkish Tupras's refinery output in the second quarter of 2024 rose 15.2% on the quarter and on the year to 7.8 MMt, data released Aug. 5 showed. The company's refinery capacity utilization was 93.5% in Q2, of which 88% was crude utilization and 5% intermediate products. Tupras said its crack refining margin for H1 2024 was $12.9\/b, above its target of $12\/b for 2024 but down from the $14.3\/b it reported for Q1. ** Hungary's MOL's refinery throughput fell 9.6% year on year in the second quarter of 2024 to 3.84 MMt, owing to both planned and unplanned turnarounds at its refineries, MOL said in its quarterly earnings presentation on Aug. 9. The January-June throughput added up to 7.2 MMt, 6.8% lower than a year earlier. Within the total in Q2, MOL processed 2.85 MMt of import crude, down 16% year on year, and 235,000 metric tons of domestically produced crude, doubling year on year as well as from its typical levels in recent quarters. MOL's Q2 Brent-based groupwide refinery margin at $6.8\/b was 34% lower than in Q1. However, it rose by 26% year on year. MOL added it saw its groupwide refinery margin narrow further in July to $4.7\/b. ** Spanish refinery throughput increased by 7% year on year to 16.3 million metric tons (1.32 million b\/d) in the second quarter of 2024, reserve corporation CORES said Aug. 13. The figure meant an operating rate of approximately 88% in the period, down from an average rate of 89% in Q1. Spain has nine operational refineries with 1.5 million b\/d capacity. Meanwhile, the volume of transport fuel supplied to the Spanish market increased 11% year on year in June to 4 million cu m (3.2 MMt), with increases for all fuel types, Exolum said Aug. 2. The monthly volume was the highest on Exolum records published since 2018, driven by record high tourism levels and a more general economic recovery. The volume for the year to date meant 2024 was the first year to record volumes above pre-COVID pandemic levels, with total January-July volume up 3% compared to the same period in 2019. Maintenance Refinery Capacity Country Owner Unit Duration Star 212,000 Turkey Socar Full Sept Haifa 197,000 Israel Bazan Part Q2'2024 Tarragona 186,000 Spain Repsol Full 2028 Castellon 110,000 Spain BP Full 2029 Sines 220,000 Portugal Galp Full 2025 Busalla 32,000 Italy Iplom Full 2025 ISAB 321,000 Italy GOI Energy Part Back Sarroch 300,000 Italy Saras Part 2024 Sannazzaro 190,000 Italy Eni Full July Upgrades Refinery Total capacity Country Owner Upgrade Completion Gdansk 210,000 Poland Lotos Conventional 2025 Plock 326,000 Poland PKN Orlen Conventional 2022 Litvinov 108,000 Czech Unipetrol Conventional 2022 Petromidia 114,000 Romania Rompetrol Conventional 2022 Burgas 190,000 Bulgaria Lukoil Conventional NA Kirikkale 108,000 Turkey Tupras Conventional NA Star 212,000 Turkey Socar Conventional NA Orlen Lietuva 204,000 Lithuania PKN Orlen Conventional 2024 Pancevo 98,000 Serbia NIS Conventional 2024 Rijeka 90,000 Croatia INA Conventional 2023 Brod 108,000 Bosnia Optima Conventional 2020 Donges 219,000 France TotalEnergies Conventional 2023 Tarragona 186,000 Spain Repsol Petchem 2023 Sines 220,000 Portugal Galp Conventional NA Haifa 197,000 Israel Bazan Group Expansion NA Corinth 180,000 Greece Motor Oil Conventional 2022 Petrobrazi 90,000 Romania Joint Conventional 2023 Fawley 270,000 UK ExxonMobil Conventional NA Launches Porto Romano 150,000 Albania Joint launch 2025 Nazli 28,000 Turkey Ersan launch NA Aliaga NA Turkey Steas launch NA New and ongoing maintenance New and revised entries ** Scotland's Grangemouth refinery was restarting one of its units, Petroineos said Aug. 9. \"With work scheduled to start from Sunday this may give rise to spells of controlled elevated flaring and steam venting,\" Petroineos said via X. Petroineos said the recommissioning should take up to 48 hours to complete. Previously Ineos, part of the joint venture Petroineos, had provided notice of works happening at the refinery Aug. 6 and 7, warning of flaring from the Kinneil site, in a separate Aug. 5 statement. Ineos had said late July that a plant at Kinneil had been successfully restarted and further works were underway. The maintenance activity follows a series of outages affecting operations across both the north and south of the site over the last year, most recently impacting the refinery's hydrocracker. ** Preparations for planned maintenance at Turkey's Star refinery are continuing, a company spokesperson said Aug. 8. Further details were not provided. The maintenance is expected to take place in September, according to trading sources. The company has previously said that Star would undergo a full maintenance shutdown in September. The planned shutdown was expected to last 45-60 days and would be the first halting of production at the plant since the refinery was fully commissioned in 2019. ** Tupras reported maintenance work at three of its four refineries during 2024. At its Izmit plant, it reported the periodic maintenance at its Fuel Oil (residue) Conversion Unit -- scheduled for 13 weeks during Q1 -- had been completed as had the periodic maintenance of the FCC unit scheduled for six weeks in Q2. However, the company said the planned periodic maintenance of the crude oil and vacuum unit and desulfurizer -- both scheduled to take five weeks in Q4 --had both been postponed. At its Izmir plant, Tupras reported the completion of a periodic maintenance of the crude oil, vacuum and HYC units, scheduled to take seven weeks in Q1. A revamp of the FCC unit at Izmir slated to take 21 weeks during Q3-Q4 is still planned. Seasonal work scheduled to take 10 weeks during Q2 and Q4 on the crude oil and vacuum units at Tupras Batman refinery, which refines Turkey's domestically produced crude, is still ongoing, the company said. ** In the first half of the year, Italy's Sarroch carried out maintenance on the alkylation unit, one of the crude distillation units dubbed Topping RT2, and a vacuum distillation unit dubbed Vacuum V1. It will carry out maintenance on the sulfur recovery unit in Q3, followed by Q4 work on the CDU Topping T2, the VDU Vacuum V2 and the IGCC plant. ** The UK's Lindsey refinery completed maintenance July 31 and is currently in a start-up phase, \"with all units returning to operation\", the company said Aug. 6. It said in late May that planned maintenance was underway, without saying which units were involved. According to market sources, gasoline units were among those undergoing work. Existing entries ** Eni's Sannazzaro de Burgondi refinery in northern Italy is currently undergoing maintenance, according to market sources July 24. The turnaround, which started in June and is expected to be completed in August, involves the whole refinery. ** Slovakia's Bratislava refinery second part of the turnarounds is scheduled for September and October this year. ** Israel's Bazan said June 27 that it is planning periodic maintenance in the fourth quarter of the hydrocracker and hydrogen production facilities, the 57,000 b\/d CDU 3 and related facilities. Periodic maintenance of CDU 4, which had been rescheduled for the second quarter, is still ongoing, the company said. It was postponed due to the war between Israel and Hamas. The maintenance had been originally planned to last 45 days in the fourth quarter of 2023. The refinery has three crude refining facilities: the 27,000 b\/d crude refining plant 1; the 57,000 b\/d crude refining plant 3 and the 113,000 b\/d crude refining plant 4. ** The Stanlow refinery in the UK was planning routine minor work this autumn, the company said July 2. There was no major maintenance currently scheduled. ** At Poland's Plock, the residue hydrodesulfurization unit remains offline. The unit, known as HOG, was halted in September 2022 after a fire and has been offline since. In November 2023, Orlen launched a tender to modernize the unit. ** Motor Oil Hellas Corinth refinery is planning regular maintenance work this year but no major works. ** Valero's Pembroke refinery in the UK is expected to undergo turnarounds in September 2024, according to sources close to the refinery. ** The last major turnaround at Spain's Tarragona was in September 2022 and the next is slated for 2028. ** Orlen Unipetrol performs a turnaround at the Litvinov refinery every four years, with the last ones having been in 2020 and 2024. ** Croatia's Rijeka turnaround was completed in April 2024. The previous regular turnaround was in 2019, the company said. The next will take place in five years. ** BP will transform its Gelsenkirchen refinery in Germany to prepare it for energy transition, it said March 2024. The transformation will include reducing capacity from around 12 million metric tons per year to around 8 MMt\/y. Some of the units will be partly decommissioned and converted, subject to appropriate approvals, in order to process biogenic materials in addition to conventional ones. From 2025, five units in the Horst and Scholven plants will be decommissioned. In addition, coprocessing will be used for the hydrocracker at the Scholven site to produce more sustainable aviation fuel among other things. The refinery comprises the Horst and Scholven sites, with the latter accounting for around two-thirds of total capacity. ** The Iplom refinery, in northwest Italy, was planning its next general maintenance in 2025, with the timing yet to be confirmed. There was no planned maintenance in 2024. Separately, the refinery has been authorized for a potential increase in production equal to 16%, \"made possible by the improved efficiency of the refinery's production system,\" the source added. The refinery could increase its annual production to approximately 2.2 MMt as a result of the government authorization and following upgrades, according to a local media report. ** Galp's Sines is planning to hold its next major turnaround in 2025. This could coincide with the start-up of its new advanced biofuels and green hydrogen units, which are about to start construction for the 2025 start-ups targeted. ** Italy's Eni said Jan. 29 it was moving ahead with the conversion of its Livorno refinery into a biorefinery. It has stopped importing crude oil and initiated the shutdown of the lubricants production lines and the topping plant. ** Shell has taken a final investment decision to convert the hydrocracker at the Wesseling site inside the Rhineland refining complex as crude oil processing is set to end at the site by 2025. The hydrocracker will be repurposed into a production unit for Group III base oils, the company said Jan. 26. The new base oil plant is expected to start operations in the second half of this decade. The Rhineland refinery, which has over 17 MMt\/y crude processing capacity, comprises the Wesseling (south) and Godorf (north) sites. Wesseling processes 7.5 MMt\/y. Crude processing will continue at Godorf, Shell said. ** BP's Castellon refinery concluded a major maintenance in December 2023. The next maintenance of this scale is likely to be toward 2029. ** The UK's Grangemouth refinery would start preparatory work to transform into a fuel import terminal, but as preparations will take around 18 months, there will be no change in operations until the spring of 2025 \"at the earliest,\" the company said. Petroineos said that the decision reflects the \"decline in demand for the type of fuels we produce.\" It also said that it is evaluating \"a range of low-carbon opportunities for Grangemouth, including the feasibility of a bio-refinery facility on the site.\" Upgrades New and revised entries ** The upgrade project at Croatia's Rijeka refinery is 89% complete, INA said in its second-quarter report late July 31. Work on the upgrade project, which involves construction of a new residue complex including a delayed coker, started in 2020 after a final investment decision in 2019. Commissioning of the new complex is planned for 2024. ** In 2020, Serbia's Pancevo launched a delayed coker. It is currently carrying out the third stage of its modernization, which includes a reconstruction of the FCC unit and a construction of an ETBE unit. It started in 2021. Existing entries ** Rompetrol is making progress on the cogeneration plant project at the Petromidia refinery. The project, which started in May 2021, will ensure the refinery's energy needs \"exclusively from the cogeneration plant.\" The new facility will generate approximately 80 MW of electricity. ** Greece's Helleniq Energy said in May that the expansion of the polypropylene production plant in Thessaloniki is in progress. The company expects the unit it to add 235,000-300,000 t\/y of capacity. The project is expected to be completed in 2025. Helleniq Energy is looking at a capacity increase at the polypropylene production unit at Thessaloniki from 235,000 t\/y to 300,000 t\/y, it previously said. ** The new fluid catalytic cracker and propylene splitter complex remain under construction at Greece's Motor Oil Hellas Corinth refinery. The new propylene splitter at Greece's Motor Oil Hellas Corinth refinery is expected by 2025. Its capacity has been raised to 160,000 t\/y from the previously planned 120,000 t\/y. Separately, a new high-efficiency combined heat and power unit and wind park are under construction, it said. ** ExxonMobil's Fawley refinery on the UK south coast is on track to complete a major upgrade project in 2025 which will enable it to increase ULSD output, the company said. The project consists of a new diesel hydrotreater HD 10, which will result in the refinery increasing its current ULSD output by 38,000 b\/d, or 40%, as well as a new hydrogen unit with 55 million SCF (standard cubic feet) daily capacity. Apart from the two new units, the project includes expanding the jet hydrotreater HD 7 where a bigger reactor was installed at the end of 2023 and also adding a new reactor to the residue hydrotreater later this year. ** Turkey's Tupras is to invest $256 million in developing propylene splitter capacity at its Izmir refinery and its Izmit refinery. The company said the new capacity is aimed at producing high value-added chemical products and reducing Scope 3 emissions from the two refineries and is being undertaken \"within the scope of\" Tupras' Strategic Transition Plan announced in November 2021. Separately, Turkish construction group Tekfen Insaat and HMB Hallesche Mitteldeutsche Bau have signed an EPC contract with Tupras to construct a new sulfur recovery unit at the Kirikkale refinery. Tupras' upgrade plans for its four refineries include new sulfur units at Izmit, Izmir and Kirikkale. Tupras is also carrying out a revamp of the FCC unit at Izmit. ** In 2024, Puertollano's petrochemical area is due to bring online a new production plant to output 25,000 t\/y of high and low-density polyethylene (HDPE and LDPE) with a recycled plastic content of 10% and 80%. Current capacity for the plastic is 16,000 t\/y. Puertollano will also bring online in 2024 a new unit to produce 15,000 t\/y of ultra-high molecular weight polyethylene (UHMWPE). ** Repsol is planning a new 27,000 t\/y cross-linkable polyethylene (XLPE) plant at Tarragona that will be commissioned in 2025. ** Orlen Unipetrol is in the process of constructing a heat recovery unit at the Czech Kralupy refinery which is aimed to increase its energy efficiency by using the flue gas waste heat which previously was released into the atmosphere. \"Implementation of the recovery unit will lead to significant energy savings of 5 MW of the thermal energy per hour,\" it said Dec. 5. The project, which is based on \"cutting-edge heat exchanger technology\" will also lead to operational costs reduction. The system will recover the heat from flue gases generated during the burning processes in furnaces at Block 25, where the basic distillation of crude oil and other related processes are carried out, the company said. ** Poland's Orlen launched a tender Nov. 27 for a contractor to modernize the gudron (residue) hydrodesulfurization (HOG) unit at its Plock refinery. The upgrade, which will enable cascade catalyst dosage, is scheduled to start in Q3 2024 and will last until Q4, 2026. Contractors can submit their offers until Dec. 7. Orlen launched the HOG unit at Plock, which has a capacity of 1.8 MMt\/y, in 1999. The HOG was halted in September 2022 after a fire and has been since offline. Poland's PKN is also building a visbreaking unit at Plock, which will have the capacity to produce 200,000 t\/y of diesel. Ongoing modernization of the hydrocracking and diesel hydrodesulfurization units will also increase diesel production capacity. PKN Orlen has bought a license and base design from US engineering company KBR for a potential bottom-of-the-barrel project. If PKN takes a final investment decision, it will construct a production complex using solvent de-asphalting and fluid catalytic cracking technologies. PKN Orlen has signed a contract with Linde to build a new oxygen and nitrogen production unit at Plock. The unit will produce 38,500 cu m\/hour of oxygen and 75,000 cu m\/hour of nitrogen, supplying gas feedstock for the new Olefin III complex and other installations at Plock. The project is due to be completed by the start of 2025. ** Lithuania's Orlen Lietuva refinery in Mazeikiai said in August 2023 that after starting construction of the residue conversion unit, also known as its bottom-of-the-barrel investment, the reactor, a key component of the hydrocracking unit was transported to the refinery. The project is slated for completion by 2025. Following the startup of the hydrocracker, Orlen Lietuva will be able to produce a similar volume of fuels from 8 MMt\/y of crude throughput as it currently does at a throughput of 10 MMt\/y. ** OMV Petrom will build a new unit for aromatics products at its Petrobrazi refinery, with a processing capacity of around 1,500 t\/d of reformed gasoline. The existing aromatics unit, which started production in 1961, will be replaced over 2023-2025, and the new unit will be put in operation in 2026. ** Slovakia's Slovnaft has awarded an engineering, procurement services and construction management (EPSCM) contract for an off-gas upgrade at its Bratislava steam cracker to McDermott. Following the expansion, the capacity of the PP3 unit will increase by 33,000 t\/y to 300,000 t\/y. Construction was expected to start in the summer of 2023 and be completed in October 2024. ** Poland's PKN Orlen is working on a hydrocracking unit with a capacity of 400,000 t\/y and an oil product loading terminal in Gdansk. Both investments are scheduled to be commissioned by mid-2025. The hydrocracking base oils project will help the company diversify into second- and third-generation base oils. ** Orlen Unipetrol is expanding the steam cracker at Litvinov. The company plans to increase its total petrochemical production capacity to 1.4 MMt\/y by 2030 from 900,000 t\/y. Separately, McDermott International has been awarded a contract for engineering, procurement and construction management services for an upgrade of the hydrocracker at the Litvinov refinery. ** France's Donges refinery is building a new hydrodesulfurization unit. ** Bosnia's Brod refinery has started construction of a bitumen unit. The refinery has been offline since 2019 and has been expected to restart once it is connected to a gas pipeline, allowing it to switch to gas-fired power operations. The line was connected in December 2021, but the plant has remained offline. A solar power facility at the plant has also been built to help power operations. ** Azerbaijan's state oil company Socar is looking to expand the capacity of its 212,000 b\/d Star refinery in Turkey. Socar said it could expand Star's capacity to 13 MMt\/y (261,000 b\/d) by means of \"flexibilities\" in the refinery's design. ** Portugal's Galp will build a desulfurization unit with a processing capacity of 20,000 b\/d at the Sines refinery. ** Bulgaria's Burgas refinery has awarded a contract to US Lummus Technology for a 280,000 t\/y polypropylene plant. ** Israel's Haifa District Court has rejected an appeal by Haifa municipality along with six other neighboring communities and environmental groups against the proposed expansion of the Bazan refinery. Launches Existing entries ** Turkey's Ersan Petrol is still hopeful that its plans for a 1.4 MMt\/y refinery at Kahramanmaras in southeast Turkey will be able to go ahead despite repeated delays and a difficult investment climate. Project coordinator Cenk Pala said Ersan was in talks with prospective partners and sources of finance for the project and hopes to start work on the FEED study this year. The refinery is planned for a 300,000 sq m site in Kahramanmaras which holds a defunct mini refinery that will be dismantled. A pre-feasibility study by Axens has defined the configuration and capacity of the plant which will produce mainly Euro 5 diesel, Euro 5 gasoline, jet and bitumen. ** A new greenfield Porto Romano refinery in Albania will be oriented to export markets but will also be able to cover Albania's domestic demand, Helmut Mayrhofer, consultant at Larkalis said. Austria-based consultancy Larkalis is leading an international consortium working on the project which will involve building the refinery in the port town of Durres. The refinery has a two-year construction authorization and could be commissioned by end-2025, depending on international developments. ** Azeri state oil company Socar is considering developing a second refinery in Turkey, in addition to its existing 214,000 b\/d Star refinery at Aliaga on Turkey's central Aegean coast. ","headline":" Minor incidents in Europe","updatedDate":"2024-08-14T13:07:47.000"},{"Unnamed: 0":86,"body":" Romanian gas consumption in the first half of 2024 increased 1% year on year to 56 TWh (5.3 Bcm), state controlled Romgaz said Aug. 14. Gas demand across Europe has remained weak since the energy crisis in 2022, with the European Commission continuing to call for gas savings by member states through March 2025. Romania is effectively self-sufficient in gas, with domestic production capacity able to meet demand, which totaled some 103 TWh (9.7 Bcm) in 2023. However, it still imports gas -- mostly from Russia -- and also exports gas to neighboring markets depending on price dynamics. In the first half of 2024, some 9.3 TWh of gas consumed in Romania was imported -- accounting for about 17% of total consumption, according to Romgaz data. The remaining 46.7 TWh was gas from domestic production, with Romgaz representing 45.3% of the total consumption, down 2.5% year on year. Romgaz production totaled 2.49 Bcm in the first half of the year. Neptun Deep Romania is the EU's second biggest gas producer after the Netherlands but is expected to become the top producer once the Neptun Deep field starts up in 2027. OMV Petrom -- together with 50% partner Romgaz -- took the final investment decision for the development of Neptun Deep in June 2023. OMV Petrom and Romgaz are to jointly invest up to Eur4 billion ($4.4 billion) for the development phase of Neptun Deep, which is set to bring onstream around 100 Bcm of gas. Romania already exports some gas to neighboring countries but has the potential to become a bigger regional player once Neptun Deep begins producing. With European gas prices still relatively high, the EU continues to look for new supply sources and Romania's Black Sea gas is an obvious option for fast-tracked development. Platts, part of S&P Global Commodity Insights, assessed the benchmark Dutch TTF month-ahead price on Aug. 13 at Eur39.09\/MWh The country's domestic gas production had been on a steady decline but received a boost in June 2022 when private equity-backed Black Sea Oil & Gas started gas production from its Midia project. Midia -- estimated to hold some 10 Bcm of gas -- has seen production running at the equivalent of 1 Bcm\/year. ","headline":"Romanian gas consumption up 1% on year in H1 2024 to 56 TWh: Romgaz","updatedDate":"2024-08-14T11:48:15.000"},{"Unnamed: 0":87,"body":" Crude oil futures were rangebound in morning European trade Aug. 14 but market participants were optimistic that the US Federal Reserve is poised to lower benchmark lending rates, which is expected to boost crude demand while increasing tension in the Middle East to keep the supply risk concerns. At 1053 GMT, the ICE October Brent futures contract was trading at $80.51\/b, down 18 cents\/b from the previous close, while the September NYMEX light sweet crude contract was 30 cents\/b lower at $78.11\/b. Market attention was focused on US economic data, which is anticipated to show a steady disinflationary trend following a softer-than-expected producer price index reading. \u201cUS producer prices rose less than expected in July. This led speculative investors to take profits in oil, which some investors buy to hedge against inflation, in order to capitalize on the gains in the stock market that benefit more from lower inflation and interest rates,\u201d analysts at Global Risk Management said. The easing inflation outlook renewed expectations that the Fed is on track to start its monetary easing cycle soon, which would boost economic activity and crude demand. A lower-than-anticipated CPI print is likely to solidify expectations for a 50-basis-point rate cut by the Fed in September. The market is also keeping a close eye on the ongoing tensions in the Middle East, which continue to threaten supply routes. Israel said it launched a counterterrorism operation in the West Bank earlier Aug. 14, killing at least one person, according to regional media. \u201cGeopolitics remains a key focus. The White House sees a possible Iranian retaliatory strike as early as this week. If it is an attack similar to the one in April, where Iran announced it in advance and the damage was limited, the oil price may decline afterward. However, the risk of further escalation and direct war between Iran and Israel remains on the rise,\u201d analysts at Global Risk Management added. ","headline":" Crude rangebound, market eyes rate cut hopes, supply disruption risks","updatedDate":"2024-08-14T11:18:22.000"},{"Unnamed: 0":88,"body":" The Middle East sour crude complex saw two convergences during the Singapore Platts Market on Close assessment process Aug. 14, while the cash differentials for key sour crude markets diverged. Platts, part of S&P Global Commodity Insights, assessed October cash Dubai at a premium of 63 cents\/b to same-month Dubai futures at market close, down 19 cents\/b on the day, while October cash Oman was assessed at a premium of 70 cents\/b, down 12 cents\/b on the day. October cash Murban was assessed at $1.22\/b to same-month Dubai futures, inching 1 cent\/b higher on the day. During the Platts Market on Close assessment process, 68 October Dubai partials of 25,000 barrels each traded. The sellers were Exxon, Mercuria, Mitsui, PetroChina, P66, Reliance, Repsol, Trafigura and Unipec, while the buyers were BP, Gunvor, P66 and Vitol. Mitsui and Exxon declared a cargo of October Al-Shaheen and Upper Zakum crude respectively to Vitol following the convergence of 20 partials in Platts Cash Dubai. A convergence occurs when 20 partials are traded between two counterparties, resulting in a full 500,000-barrel physical cargo being declared from the seller to the buyer. Meanwhile, Russia\u2019s ability to maintain export flows of its critical revenue commodities have helped sustain Kremlin through its invasion of Ukraine in the face of Western sanctions, but analysts say the health of its vital oil and gas industry may be slowly deteriorating. The sanctions have restricted Russia\u2019s access to key export markets that were previously crucial. Russia\u2019s share in the EU's oil imports shrank to just 3% in the first quarter of 2024, from 30% in the first quarter of 2022, according to EU data. Restrictions on Russia\u2019s access to global financial markets and Western technology are also increasing producers' costs and raising risks of unplanned shutdowns and accidents. ","headline":" Middle East sour crude complex sees two convergences, cash differentials diverge","updatedDate":"2024-08-14T11:01:05.000"},{"Unnamed: 0":89,"body":" Russia's commercial ports handled 264 million metric tons of liquid bulk, including crude, oil products and LNG over January-July, down 3.4% year on year, the Association of Russian Commercial Seaports said late Aug. 14. Crude oil throughput was down 0.9% on the year at 160 MMt (5.5 million b\/d), while oil products throughput was down 9.8% on the year at 77.5 MMt, the association said. LNG throughput rose 2.6% on the year to 20.6 MMt. Exports at the start of 2024 were hit by inclement weather, especially at Black Sea ports, and also by drone attacks on energy infrastructure. Russia introduced a gasoline export ban from March 1 and the authorities also asked oil companies to redirect some diesel flows from exports to the domestic market. The ban was lifted temporarily in late May but reimposed from August and has been extended until the end of 2024. Product exports have fallen since the EU's ban on imports of Russian products that came into force Feb. 5, 2023. Russian commercial ports throughput, January-July: Port Total throughput of dry and liquid bulk (mil mt) Change % Notes Far East 137 -2.7 of which liquids 47.3 0.9 includes ESPO terminal of Kozmino Vanino 16.6 -24.1 exports products Nakhodka 16.7 4.9 exports products Black Sea, Azov 162.8 -7.4 of which liquids 87.2 -5.4 Novorossiisk 99.4 3.3 exports crude, products Tuapse 12.4 -16.9 exports feedstocks Taman 15.8 -37.5 exports crude, products, LPG Kavkaz 12.7 -1.9 exports LPG, products by river Caspian Sea 5 15.8 of which liquids 1.5 -11.3 Makhachkala 1.9 -4.4 Kazakh crude is delivered via Baku-Novorossiisk pipeline Baltic Sea 162 1.3 of which liquids 88.3 -4.6 Primorsk 37.1 -3.9 was main crude, diesel terminal, focuses on diesel Ust-Luga 79.7 -1.8 crude and products terminals launched in 2012 St. Petersburg 31.6 19.6 mostly fuel oil exports, Belarus exports Vysotsk 6.8 -12 product exports Arctic 55 -4.7 of which liquids 39.7 -0.5 Murmansk 31.7 -10.1 crude oil exports Archangelsk 1.5 41.7 oil products exports Varandey 3 -4.4 crude exports * The data does not provide a breakdown between dry and liquid bulk throughputs for individual ports Source: Association of Russian Commercial Seaports ","headline":" Jan-July crude, product and LNG port throughput fall 3.4% on year","updatedDate":"2024-08-14T10:27:54.000"},{"Unnamed: 0":90,"body":" China's propane dehydrogenation plants operated at an average rate of 74% in July, up from 71% in June, marking the highest rate in 26 months, S&P Global Commodity Insights' calculations based on data from domestic information provider JLC showed Aug. 14. The survey in July covered 29 PDH plants in the country that have a combined propylene production capacity of about 19.57 million metric tons a year. When operating at full capacity, these plants require up to 23.48 MMt\/y of propane feedstock. In July, 10 PDH plants in China raised their operating rates, while six plants lowered rates mainly due to maintenance, the data showed. China's PDH plants also saw estimated average theoretical losses of about Yuan 177 per metric ton ($24.76\/t) in July, widening from Yuan 75\/t in June, marking the country's 14th straight month of theoretical processing losses since June 2023. Theoretical processing losses narrowing in June had encouraged more PDH plants to increase their operating rates in July. The higher rates, which resulted in an increase in propylene supply, put pressure on selling prices, leading to further expansion in theoretical processing losses for PDH plants during the month, a JLC analyst said. While PDH plants still face some theoretical processing losses, those with downstream propylene processing units are expected to be able to reach breakeven levels or even be profitable, the analyst said. China's PDH plants: Plants Location Propylene capacity (t\/year) July run rate (%) June run rate (%) Tianjin Bohai Tianjin 600,000 93% 93% Hebei Haiwei Hebei 500,000 84% 38% Puyang Yuandong Henan 150,000 0% 0% Ningbo Kingfa Zhejiang 1,200,000 47% 47% Shaoxing Sanyuan Zhejiang 450,000 0% 0% Zhejiang Satellite Zhejiang 900,000 93% 98% Zhangjiagang Yangzijiang Jiangsu 600,000 98% 98% Ningbo New Materials Zhejiang 1,260,000 93% 93% Zhejiang Petrochemical Zhejiang 600,000 93% 93% Zhejiang Huahong Zhejiang 450,000 98% 90% Jiangsu Sierbang Jiangsu 700,000 92% 92% Fujian Meide Fujian 1,660,000 88% 88% Yantai Wanhua Shandong 750,000 93% 71% Jinneng Science & Technology Shandong 1,800,000 93% 64% Dongguan Juzhengyuan Guangdong 600,000 98% 95% Zibo Qixiang Tengda Shandong 700,000 60% 72% Xintai Petrochemical Shandong 300,000 93% 93% Ningxia Runfeng Gansu 300,000 46% 84% Zibo Haiyi Shandong 250,000 9% 22% Shandong Tianhong Shandong 450,000 0% 4% Liaoning Kingfa Liaoning 600,000 98% 95% Oriental Energy Maoming Guangdong 600,000 98% 95% Guangxi Huayi Guangxi 750,000 93% 70% Yanchang Zhongran Taixing Jiangsu 600,000 0% 0% Shandong Binhua New Material Shandong 600,000 79% 76% Lihuayi Weiyuan Technology Shandong 600,000 98% 98% Jiangsu Ruiheng Jiangsu 600,000 51% 40% Formosa Ningbo Zhejiang 600,000 32% 96% Zhonghai Fine Chemical Shandong 400,000 0% 0% Total\/average run rate 19,570,000 74% 71% PDH plant turnaround schedules: Plants Maintenance Yantai Wanhua Expected to shut for maintenance late August Tianjin Bohai Shut for maintenance early August Ningxia Runfeng Shut for maintenance July 18 and expected to restart mid-Aug Jiangsu Ruiheng Shut for maintenance July 18 and expected to restart H2 Aug Formosa Ningbo Shut for maintenance July 11 and expected to restart H2 Aug Zibo Qixiang Tengda Shut for maintenance July 8-12 Zibo Haiyi Restarted July 29 after being shut for maintenance June 11 Shandong Tianhong (Wanda) Shut June 3; expected to restart in August Yanchang Zhongran Taixing Did not restarted on June 28 after verification Zhonghai Fine Chemical Shut for maintenance May 29; restart date unknown Ningbo Kingfa Phase 1 shut for maintenance March 21; restart date unknown Shaoxing Sanyuan Shut for maintenance Sept. 20, 2023; restart date unknown Puyang Yuandong Shut again May 12, 2023; restart date unknown Source: JLC ","headline":" PDH plant average run rates rise to 74% in July, highest in 26 months","updatedDate":"2024-08-14T09:50:28.000"},{"Unnamed: 0":91,"body":" India\u2019s vegetable oil imports rose 1.84 million metric tons in July, up 22.2% from the month before and close to the highest recorded single month of imports of 1.85 MMt in August 2023, the Solvent Extractors\u2019 Association of India or SEA said Aug. 14. The increase was mostly due to a 37% jump in palm oil imports on month to 1.08 MMt in July, compared to 786,134 metric tons in June, according to the SEA. This is also the highest single month of palm oil purchases by India, the world\u2019s largest vegetable oil buyer, since November 2022 when imports stood at 1.14 MMt, SEA said. The third quarter of the marketing year 2023-24 (November-October) witnessed a 20% jump in vegetable oil imports, in anticipation of the upcoming festival season in India, SEA said, adding that the massive influx has led to congestion at India\u2019s Kandla port, causing berthing delays of 8 to 10 days. Soybean oil imports surged to 391,791 metric tons in July from 275,700 metric tons in June, SEA data showed. However, in first nine months of MY 2023-24, the purchase of bean oil was down by almost 20 % to 2.25 MMt against 2.824 MMt in same period a year prior. July sunflower oil imports slumped to 366,541 metric tons from 465,647 metric tons in June. Sunflower oil buying was, however, higher over the year by almost 30% at 2.83 MMt for the November to July period of MY 2023-24 compared to 2.18 MMt a year prior. Stocks and prices Excessive imports in July have increased India\u2019s vegetable oil stocks at ports to 988,000 metric tons by Aug. 1, up from 713,000 metric tons a month before, SEA said. Total vegetable oil stocks including pipeline stocks was pegged at 2.9 MMt at Aug. 1, up from 2.57 MMt a month before. In July, refined palm olein was the cheapest of all vegetable oil imports, averaging at $949\/t on CIF basis to Indian ports, followed by crude palm oil at $979\/t SEA said. Crude soybean oil price averaged at $1,054\/t while crude sunflower oil was $1,043\/t in July on CIF basis to Indian ports, the trade body said. Platts, a part of S&P Global Commodity Insights, assessed crude palm oil CFR West Coast Kandla at $829\/t on Aug. 13, down 2.2% from the start of the month. ","headline":"India\u2019s palm oil buying spree pushes July veg oil imports to near-record","updatedDate":"2024-08-14T08:58:38.000"},{"Unnamed: 0":92,"body":" Bunker fuel sales around the world\u2019s largest bunker hub of Singapore rebounded 9.2% on the month and increased 3.3% year on year to 4.669 million metric tons in July, following an 11.4% month-on-month decline in June, according to the latest preliminary data from the Maritime and Port Authority of Singapore. Total arrival of container liners at Singapore hub amounted to 1,214 across July, the highest since 1,248 recorded in March, climbing 11.7% on the month but declining 12.4% year on year, MPA data showed. The container liner segment also led the highest monthly increase across all other freight segments, with bulk carriers coming in second at a six-month high of 1,627 in July, rising 9.4% from June and up 9.1% year on year. Bunker-only calls around the Singapore hub also gained 6.1% on the month and rose 1.3% on the year to a six-month high of 3,557 in July, and was last recorded higher at 3,571 in January. In the high sulfur fuel oil space, including bio-blended product, bunker sales soared to a seven-month high of 1.787 MMt across July, 14.5% higher month on month and 28.3% above the previous year, MPA data showed. Across all grades, the proportion of HSFO bunker sales expanded to a record high of 38.3% in July, a 1.8-percentage-point increase on the month and 5.4 percentage points higher on the year. While buoyed downstream demand resulted in tighter-than-usual prompt barge schedules since the second half of July, the Platts-assessed Singapore-delivered 380 CST HSFO bunker premium over the FOB Singapore 380 CST HSFO cargo value averaged higher at $15.51\/t in H2 July, up from $11.30\/t in H1 July, and has been steadier at $19.60\/t so far in August, S&P Global Commodity Insights data showed. In addition, bio-blended HSFO sales totaled 6,100 metric tons in July, above the 2,500 metric tons in June and 5,300 metric tons in May -- the only months so far this year that sales of this grade were recorded. Sales of International Maritime Organization-compliant low sulfur fuel oil, including the bio-blended grade, fell 1.4% year on year to 2.528 MMt in July, despite rising 6.4% month on month, according to the latest MPA data. In July, LSFO sales accounted for only 54.2% of all bunker grades sold, shrinking 1.4 percentage points on the month and a sharper 5.7 percentage points decline from the previous year, MPA data showed. In the first seven months of 2024, bio-blended LSFO sales recorded a steep 40% jump from the same period in 2023 to total 322,600 metric tons, while the 42,500 metric tons sold in July was a 7.7% increase year on year, despite dropping 6.4% from June, according to MPA data. Sales of low sulfur marine gasoil, which has a maximum sulfur content of 0.1% and includes bio-blended product, totaled 308,000 metric tons for all of July, up 10.8% on the month and 7.4% higher on the year. Across January-July, LNG bunker sales surged nearly fivefold on year to 255,100 metric tons, demonstrating a considerable increase in uptake in this segment of alternative fuels. Singapore's July 2024 bunker sales: Bunker Sales (in '000 metric tons) Jul-24 Jul-23 YOY Jun-24 MOM MDO 0.00 0.00 0.00 Bio-blended MDO 0.00 0.00 0.00 MGO 1.80 22.30 -91.9% 8.00 -77.5% Bio-blended MGO 0.00 0.00 0.00 LSMGO 308.80 287.60 7.4% 278.80 10.8% Bio-blended LSMGO 0.00 0.00 0.00 MFO 1780.70 1484.00 20.0% 1557.60 14.3% Bio-blended MFO 6.10 0.50 1120.0% 2.50 144.0% LSFO 2485.70 2665.20 -6.7% 2331.10 6.6% Bio-blended LSFO 42.50 39.40 7.9% 45.30 -6.2% ULSFO 0.00 0.00 0.00 Bio-blended ULSFO 0.00 0.00 0.00 LNG 43.20 18.30 136.1% 51.70 -16.4% Methanol 0.00 0.30 0.00 Total 4668.73 4517.54 3.3% 4274.92 9.2% Source: Maritime and Port Authority of Singapore ","headline":"Singapore\u2019s July bunker sales rebound 9% on month to 4.67 mil metric tons","updatedDate":"2024-08-14T08:45:23.000"},{"Unnamed: 0":93,"body":" CNOOC Ningbo Daxie Petrochemical -- a subsidiary of state-run China National Offshore Oil Corp. -- will shut its 1.6 million metric tons\/year paraxylene plant in Daxie, eastern Ningbo, from Oct. 10 for around two months, a company source said Aug. 14. The shutdown is part of a planned turnaround, the source said. Platts, part of S&P Global Commodity Insights, last assessed Asian paraxylene down $1.33\/t on the day at $977.67\/t CFR Taiwan\/China Aug. 13. ","headline":"CNOOC Ningbo Daxie to shut 1.6 mil metric tons\/year PX plant for turnaround","updatedDate":"2024-08-14T08:17:01.000"},{"Unnamed: 0":94,"body":" Around the UAE\u2019s bunker hub of Fujairah, expectations of buoyed stockpiles of 380 CST high sulfur fuel oil in the near term spurred intense competition among downstream suppliers despite healthy demand, traders said Aug. 14, pushing delivered premiums to the lowest in five months. Amid aggressive offers among suppliers over the past several weeks to cap inventories, the Platts-assessed Fujairah-delivered 380 CST HSFO bunker premium to FO 380 CST 3.5% FOB Arab Gulf cargoes tumbled to a five-month low of $14.37 per metric ton Aug. 13, down $1.15\/t on the day, according to S&P Global Commodity Insights data. Platts last assessed the HSFO bunker premium at Fujairah at $14.36\/t March 13. In fact, Fujairah\u2019s HSFO bunker premiums gradually declined to average $19.96\/t over Aug. 1-13, compared with $23.92\/t in July, with both months below the $31.79\/t average in June, Commodity Insights data showed. \"Relative to the increasing [HSFO] cargo movements toward Fujairah, bunker demand is lagging,\" a Fujairah-based bunker supplier said Aug. 14, as downstream demand is still falling short of robust levels. As a result of eager selling activities in the HSFO segment, some suppliers were reportedly fully committed for their very prompt barging schedules and could only offer refueling slots from the third week of August onward. \u201cHSFO [barging schedules] might be a bit tighter. Seeing some sellers offering around the third week of August and onward,\u201d a Fujairah-based trader said Aug. 13. Industry sources estimate that HSFO cargo inflows to Fujairah in July were over 10% higher month on month, with more barrels reportedly of Russian origin expected to arrive in August, potentially boosting overall arbitrage flow volumes. Lately, term-contract HSFO ex-wharf barrels for August supply at the Fujairah hub were signed at premiums between plus $6\/t and plus $8\/t to Mean of Platts Arab Gulf 180 CST HSFO assessments, down from premiums of around $8 to $15\/t for July-loading cargoes, according to local traders. As peak summer demand for HSFO from regional utility sectors gradually ebbs, traders expect some degree of stock build toward the fourth quarter, amid uncertainties about whether downstream demand would rise accordingly. Inflows just shy of 1.2 million barrels, or around 184,000 metric tons, of HSFO reportedly of Iranian origin have landed around Fujairah since August to date, keeping the hub adequately supplied, industry sources said. \"Big HSFO volumes toward Singapore were heard fixed and partly moved already,\" the Fujairah-based bunker supplier added, suggesting elevated arbitrage flows toward Asia. Likewise, spreads between Singapore-delivered HSFO prices versus the same delivered grade at the Middle Eastern bunker hub widened to a five-month high of $30\/t Aug. 13, up $2\/t on the day, according to Commodity Insights data. Platts last assessed spreads between both key hubs higher at $31\/t March 13. Downstream HSFO valuations around the world\u2019s largest hub of Singapore have been more supported in recent weeks as reasonable demand volumes resulted in tighter-than-usual barge availability, with some suppliers committing their prompt slots for term contract nominations. ","headline":"Fujairah\u2019s downstream HSFO premiums hit 5-month low on stiff competition","updatedDate":"2024-08-14T07:15:31.000"},{"Unnamed: 0":95,"body":" Crude oil futures were higher in midafternoon Asian trading Aug. 14, driven by fresh optimism that the US Federal Reserve is poised to lower benchmark lending rates, which is expected to boost crude demand. At 2:57 pm Singapore time (0657 GMT), the ICE October Brent futures contract was up 47 cents\/b (0.58%) from the previous close at $81.16\/b, while the NYMEX September light sweet crude contract rose 47 cents\/b (0.60%) to $78.82\/b. Market attention was focused on US economic data, which is anticipated to show a steady disinflationary trend following a softer-than-expected producer price index reading. \"The market mood has shifted back toward rate cuts again in the last 24 hours, with US PPI data coming in on the soft side ahead of today's [consumer price index] numbers,\" analysts at ING said. The easing inflation outlook renewed expectations that the Fed is on track to start its monetary easing cycle soon, which would boost economic activity and crude demand. Expectations of lower interest rates also weakened the US dollar, making dollar-denominated assets like oil futures less expensive for investors holding foreign currencies. The ICE US Dollar Index was near a five-month low of 102.490 as of 0553 GMT on Aug. 14. \"Did the recession memo get lost in the mail, or are traders just betting big on the Fed's magic touch to engineer the mother of all soft landings for the decades?\" asked Stephen Innes, managing partner at SPI Asset Management, following the recovery in market sentiment. \"Unless consumer prices pull off an acrobatic leap, the Fed is all set to slice rates next month,\" Innes said. A lower-than-anticipated CPI print is likely to solidify expectations for a 50-basis-point rate cut by the Fed in September. Crude prices also remained supported by ongoing tensions in the Middle East, which continue to threaten supply routes. Israel said it launched a counterterrorism operation in the West Bank earlier Aug. 14, killing at least one person, according to regional media. \"If a broader conflict in the Middle East develops, this would likely threaten not only Iranian supply but also oil moving through key choke points in the Middle East,\" analysts at ANZ Research said, noting that over 20 million b\/d of oil could be disrupted. Technical indicators have supported crude prices, with Brent approaching key resistance levels, said Chris Beauchamp, chief market analyst at IG. \"The price has surged through trendline resistance from its July high and is now pushing on to the 200-day [simple moving average]. It faltered in late July around $81.50\/b, so a close above here helps to bolster the bullish view,\" Beauchamp said. However, if prices decline, Brent could retest the $80\/b psychological level, he added. Dubai crude Dubai crude swaps and intermonth spreads were lower in midafternoon Asian trading Aug. 14 from the previous close. The October Dubai swap was pegged at $78.65\/b at 2:00 pm Singapore time (0600 GMT), down 52 cents\/b (0.66%) from the previous Asian market close. The September-October Dubai swap intermonth spread was pegged at 73 cents\/b, down 5 cents\/b over the same period, and the October-November intermonth spread was pegged at 55 cents\/b, down 1 cent\/b. The October Brent-Dubai exchange of futures for swaps was pegged at $2.54\/b, down 12 cents\/b. ","headline":" Crude rises on rate cut hopes, supply disruption risks","updatedDate":"2024-08-14T07:00:00.000"},{"Unnamed: 0":96,"body":" Malaysia's output of combined oil products surged 29.72% on the year to 3.62 million mt in June, latest preliminary data from the Department of Statistics showed, with all products, except gasoline, recording increases. The Southeast Asian nation\u2019s combined oil products include gasoline, gasoil, fuel oil, kerosene, LPG and naphtha. Compared to May, combined output of oil products rose 24.27% in June, with fuel oil and naphtha posting the widest percentage increase on the month. Production of combined oil products over January-June, however, fell 0.88% on the year to 15.95 million mt, with declines in gasoline and LPG offsetting growth in output of other oil products. Malaysia's fuel oil production rose 46.73% on the month to 284,603 mt in June. The fuel oil output in June was also 46.5% higher, compared with 194,274 mt in the corresponding month in 2023, the data showed. This brings total fuel oil production to 1.1 million mt over the first six months, up 20.87% on the year. Meanwhile, naphtha production soared 37.46% on the month, and 30.06% on the year, to 494,869 mt. The rise came despite a slump in gasoline production as naphtha is typically used as a blending component for gasoline production. Over January-June, Malaysia produced 1,775,277 mt of naphtha, up 5.99% from the year before. Gasoline output fell 6.87% on the month, and 6.89% on the year, to 367,782 mt in June, the data showed. Total gasoline output over the first half of the year was at 1.73 million mt or 30.33% lower on the year. Malaysia's gasoline output is likely to increase in July as Hengyuan Refining completed repairs to a leak found at the carbon monoxide boiler of the LRCCU at its 120,000-b\/d Port Dickson refinery on June 30, S&P Global Commodity Insights previously reported. Middle distillates output rises Malaysia\u2019s gasoil production surged 38.73% on the year, and 29.22% on the month, to 1.66 million mt in June, bringing total output in the first six months to 8 million mt or 2.43% higher from the same corresponding period a year ago. Peninsular Malaysia\u2019s r etail diesel price increased 56% to RM3.35 per liter (22 cents\/liter) on June 10 as the government shifted away from blanket diesel subsidies to a targeted subsidy, and retail prices were aligned to market price, according to a statement by Malaysia\u2019s Ministry of Finance released June 9. \u201cThere hasn\u2019t been much impact on demand from the subsidy cut yet so I would expect [diesel] production to be stable,\u201d an industry source said. Production of co-distillate kerosene climbed 34.92% on the year, and 27.61% on the month, to 524,660 mt. Total kerosene output over the first half of the year was 9.74% higher on the year at 1.98 million mt, the data showed. Malaysia produced 288,952 mt of LPG in June, 7.62% higher from May and 22.29% higher from a year ago, the data showed, bringing the total output over January-June to 1.35 million mt, slipping 3.14% from the same year-ago period. Malaysian consumers mainly use LPG for household cooking, while the remaining is largely exported as pressurized cargoes to neighboring Vietnam and the Philippines as well as Bangladesh. Platts assessed CFR North Asia propane at an average of $629.45\/mt, up from an average of $620.02\/mt in May, Commodity Insights data showed, while CFR North Asia butane was assessed at an average of $612.50\/mt in June, up from $610.79\/mt in May. Separately, Malaysia produced 2.3 million mt of LNG in June, down 2.8% on the year but up 5.7% from May. The LNG production in the first half went up 2.4% on the year to 15.83 million mt, the data showed. The country exported 14.035 million mt of LNG between January and June, up 4.6% on the year. Imports largely stable Malaysia imported 19.4 million mt of refined products in the first six months, inching 0.7% higher on the year, according to the data. The country also exported 19.13 million mt of oil products in the first half, down 14.6% from the same period last year. The southeast Asian nation exported 1.57 million mt of oil products to Vietnam in the first six months, jumping 77.2% on the year, becoming the second largest supplier of refined products to Vietnam in the period, preliminary data from Vietnam Customs showed. Malaysia imported 11.15 million mt of crude oil over January-June, up 2.1% year on year. Meanwhile, it exported 4.83 million mt of crude oil over the same period, 8.2% higher year on year. Malaysia's oil products, LNG output: Unit: mt June 24 June 23 Change (Y\/Y) May 24 Change (M\/M) Kerosene 524,660 388,860 34.92% 411,133 27.61% LPG 288,952 236,276 22.29% 268,505 7.62% Fuel oil 284,603 193,969 46.73% 194,274 46.50% Gasoil 1,655,676 1,193,439 38.73% 1,281,299 29.22% Gasoline 367,782 394,997 -6.89% 394,924 -6.87% Naphtha 494,869 380,488 30.06% 360,008 37.46% LNG 2,303,478 2,368,951 -2.76% 2,178,371 5.74% Unit: mt Jan-June 24 Jan-June 23 Change (Y\/Y) Kerosene 1,983,778 1,807,752 9.74% LPG 1,353,648 1,397,531 -3.14% Fuel oil 1,106,553 915,504 20.87% Gasoil 8,000,265 7,810,605 2.43% Gasoline 1,732,685 2,486,890 -30.33% Naphtha 1,775,277 1,674,933 5.99% LNG 15,832,126 15,458,514 2.42% Source: Department of Statistics ","headline":" June output of most oil products surge; gasoline production falls","updatedDate":"2024-08-14T01:29:46.000"},{"Unnamed: 0":97,"body":" The differentials for Heavy Canadian Crude at Cushing, Oklahoma, and Nederland, Texas, moved to the most narrow levels in almost four months on Aug. 13 due to an increase in barrels exported on the water, sources said. Platts, part of S&P Global Commodity Insights, assessed WCS at Nederland at a $4.95\/b discount to the WTI CMA on Aug. 13, the most narrow since April 17, when it was assessed at a $4.65\/b discount. The differential has rallied steeply from a recent low of a $7.75\/b discount to the WTI CMA from July 29. Since hitting that low, WCS Nederland has narrowed in 10 consecutive assessments. Prices for WCS Cushing also narrowed on the day to the tightest differential in over three months, with Platts assessing the grade at a $6.05\/b discount to the WTI CMA on Aug. 16. The WCS Cushing differential was last more narrow on April 23, when it was assessed at a $6\/b discount to the WTI CMA price. The differentials tightened as more Canadian export barrels were diverted from the US Gulf Coast due to the Trans Mountain Pipeline Expansion coming online on May 1. An analysis from Commodity Insights showed crude cargo loadings from the pipeline have been shipped to China and India, as well as California and Washington state on the US West Coast. The expansion added 590,000 barrels per day of heavy crude pipeline capacity from Edmonton, Alberta, to Burnaby, British Columbia. The original Trans Mountain pipeline has a capacity of around 300,000 b\/d, and now carries light crude and refined products. US imports of Canadian crude hit a 15-week low of 3.48 million b\/d in the week ended Aug. 2, according to US Energy Information Administration data released Aug. 7. ","headline":"Western Canadian Select crude differentials at Nederland, Cushing near four-month highs","updatedDate":"2024-08-13T21:26:27.000"},{"Unnamed: 0":98,"body":" Vista Energy, the third-biggest oil producer in Argentina, is bringing in a third drill rig by the end of September to step up its drilling pace with a target of reaching 150,000 b\/d of oil equivalent by 2030 as new takeaway capacity is added, CFO Pablo Vera Pinto said Aug. 13. \u201cThis rig will increase our capacity to drill wells by 30% more,\u201d he said at a televised energy seminar organized by La Naci\u00f3n newspaper. The Mexico City-based company will add more frack sets to complete the increased number of wells it will be drilling, with a target of taking production to 100,000 boe\/d by 2026, Vera Pinto said. That production will be up from the company\u2019s 65,000 boe\/d in the second quarter of this year, according to company records. \u201cWe are very much on track to reach the guidance for 2026,\u201d he said. \u201cWe also have the assets and the operating capacity to reach the vision of 2030.\u201d The increase in drilling means that Vista will be investing more than $1 billion per year in Vaca Muerta to increase production starting in the third or fourth quarter of this year, up from an initial $250 million that has gone up gradually to $800 million, Vera Pinto said. Vista is focusing on a shale oil hub in Vaca Muerta, which is made up of the Aguada Federal, Bajada del Palo Este and Bajada del Palo Oeste blocks. The company has sold its conventional areas in other parts of Argentina to focus on the play in northern Patagonia, first at this oil hub in the south and eventually in a northern section. The ramp-up in production comes as projects get off the ground to build up to 1.4 million b\/d of crude transport and export capacity by 2030, according to industry data. \u201cThe opportunity is enormous\u201d for the industry, Vera Pinto said. \u201cPractically all the the companies with shale oil acreage have plans to grow because it is profitable and the infrastructure is being developed.\u201d ","headline":"Vista aims to reach 150,000 b\/d oil output by 2030 in Argentina\u2019s Vaca Muerta: exec","updatedDate":"2024-08-13T21:18:25.000"},{"Unnamed: 0":99,"body":" Bidders for North Dakota acreage have paid some relatively large six-figure sums for Divide County parcels in a two-day oil and gas lease sale Aug. 13, after the first 50 parcels and most thereafter went for five-figure sums or less, according to bidding platform Energynet.com. So far, the highest bid at press time in the auction, sponsored by the North Dakota Department of Trust Lands, has been just over $192,000, or $1,201\/acre, for a 160-acre Divide County parcel\u2014a typical size lot for most of the 315 parcels offered in the current sale, an S&P Global Commodity Insights analysis shows. Most of the six-figure bids were in Burke and Divide counties. The 315 parcels offered in the sale were spread over 42,724 gross acres. At least a half-dozen six-figure offers were made through mid-afternoon Aug. 13, the Commodity Insights analysis shows. Bid amounts ranged from three to six figures, although most were five-figure bids. Bidding on most of the parcels so far in the auction mostly started at $2\/acre. By mid-afternoon Aug. 13, the Department of Trust Lands had released high bid amounts for less than half the sale's 315 parcels. The auction has processed bids alphabetically by county and, at that time, was still releasing information on Dunn County parcels. Acreage offered in 11 counties The acreage offered for lease is spread across 11 North Dakota counties, largely in the western part of the state. The county with the largest number of parcels in the current sale is Divide, with 97. In May, Divide County produced about 19,400 b\/d of oil, according to the most-recent figures from the North Dakota Department of Mineral Resources. Burke County contained the second-largest number of parcels, at 66. Burke's oil output in May was about 9,000 b\/d, DMR figures show. Parcels whose winning bids were released Aug. 13 were Billings, Burke, Cavalier\u2014which received no offers on the 11 parcels that state included in the auction\u2014Divide and had started on Dunn County acreage. Counties still to come later Aug. 13 and Aug. 14 are the rest of Dunn, Golden Valley, McKenzie, McLean, Mountrail, Stark and Williams. Bidding should be finished at about 11:30 am CT Aug. 14. Four counties produce over 90% of state's oil output The largest oil-producing counties, based on data from May, are McKenzie, at about 374,000 b\/d; Dunn, at around 284,000 b\/d; Williams, at around 228,500 b\/d; and Mountrail, at around 202,700 b\/d. Those counties, all in west-northwest North Dakota, accounted for more than 90% of North Dakota's 1.195 million b\/d of May oil output DMR figures showed. A two-day state Trust Lands oil and gas sale in February captured high bids of $6.96 million. It received bids for 364 tracts covering 32,797 acres. North Dakota officially has had 19 producing counties over the years, although at least three of them\u2014Adams, Hettinger and Mercer, in the west-southwest part of the state\u2014have not produced any sizable volumes for at least 20 years and, in some cases, much longer. ","headline":"North Dakota oil, gas lease sale offers 315 parcels, gets half-dozen six-figure bids","updatedDate":"2024-08-13T21:11:31.000"},{"Unnamed: 0":100,"body":" Tecpetrol, the third-largest natural gas producer in Argentina, plans to put into operation an oil field in the Vaca Muerta play by the end of the year to produce an initial 8,000 b\/d, part of a strategy to reach 100,000 b\/d over the next five years, CEO Ricardo Markous said Aug. 13. Output at this field, Puesto Parada, will then be increased to 20,000 b\/d, he said at a televised energy seminar organized by La Naci\u00f3n newspaper. The second project is at Los Toldos II Este, where Tecpetrol plans to start at 35,000 b\/d and increase to 70,000 b\/d, Markous said. These two shale blocks will build on the company\u2019s nearly 20,000 b\/d of current oil production to take its total to 100,000 b\/d over the next five years. The push into oil comes as the growth in gas production in Vaca Muerta has stalled at an industry-wide 140 million cu m\/d to 150 million cu m\/d because of limited takeaway capacity and demand. While a new pipeline is being built with an initial 11 million cu m\/d and a target of 40 million cu m\/d, the big growth in production won\u2019t come until the country can widen exports, first regionally and then the global market. Argentina\u2019s state-run YPF is starting a $30 million project to build a 120 million cu m\/d LNG export terminal with Malaysia\u2019s Petronas, but it isn\u2019t expected to come online until 2030 at 40 million cu m\/d with floating facilities and then an additional 80 million cu m\/d with an onshore terminal by 2031. In the meantime, Tecpetrol will focus on oil production given that there is spare capacity for exporting via pipelines to the Atlantic and Pacific, Markous said. There are also projects underway or in the planning phase to build up to 1.4 million b\/d of export capacity, according to industry data. Possible acquisitions Tecpetrol is also considering bidding for more acreage in Vaca Muerta that ExxonMobil has put up for sale. The US-based company is selling the assets as part of a global review of its portfolio. The blocks are in the shale play's oil window toward the north of Neuqu\u00e9n province. Its most productive block there, Bajo del Choique-La Invernada block, was producing 7,500 b\/d of crude in May, according to data from the Argentina Oil and Gas Institute, an industry group. \u201cWe are interested because the assets are really good,\u201d Markous said. ExxonMobil also operates Los Toldos II Oeste, Los Toldos I Sur and Pampa de las Yeguas I in the same vicinity of Vaca Muerta \u2014 and near where Tecpetrol has its biggest shale oil field. ","headline":"Argentina\u2019s Tecpetrol to ramp up Vaca Muerta oil output; mulls ExxonMobil asset purchase","updatedDate":"2024-08-13T20:08:07.000"},{"Unnamed: 0":101,"body":" Canada-based Crown Point Energy said Aug. 13 it reached a deal with a unit of London-based Phoenix Global Resources to buy that company\u2019s stakes in three oil and natural gas blocks in Tierra del Fuego, its latest acquisition to expand its reach in southern Argentina. The company\u2019s local unit, Crown Point Energ\u00eda, agreed to buy Phoenix\u2019s 17% stakes in Angostura, Las Violetas and R\u00edo Cullen in the country\u2019s southernmost province, pending approval by the other shareholders in these blocks, according to a securities filing. The buyer said it paid the Phoenix unit, Petrolera el Tr\u00e9bol, $293,000 upfront for the blocks and will pay the remainder when the deal closes. The pending payment will be of up to $700,000 in cash plus the seller's share of the gas and crude stocks as of July 1, 2024, Crown Point said. Angostura and Las Violetas were producing a combined 78,000 cu m\/d of gas and 1,700 b\/d of oil in May, according to the latest data from the Argentina Oil and Gas Institute, an industry group. R\u00edo Cullen has yet to come into production. The blocks are operated by Roch, a smaller oil producer based in Buenos Aires. While a small deal, it is the latest move by Crown Point to expand in Argentina. In February, the company announced the acquisition of 100% stakes in two oil fields in Santa Cruz province from BP-backed Pan American Energy. That deal closed in May to gain it 3,500 b\/d of production for $12 million plus up to 600 b\/d of the oil production to the seller for the subsequent 15 years depending on the price of the product. Crown Point has said it was seeking to build up a portfolio of conventional and shale-producing assets in Argentina to finance its exploration for growth. The deals come as more of the larger players in Argentina like Pan American Energy refocus their business on Vaca Muerta, a huge shale play in northern Patagonia that is driving up the country\u2019s oil and gas production and exports. State-run YPF, the country\u2019s biggest oil and gas producer, is selling most of its mature conventional fields to invest in Vaca Muerta, where extraction is considered more efficient and cheaper on a per-dollar investment basis. Most of Argentina\u2019s conventional reserves are maturing after more than 100 years of extraction. ","headline":"Crown Point buys more oil assets in southern Argentina in deal with Phoenix","updatedDate":"2024-08-13T20:04:22.000"},{"Unnamed: 0":102,"body":" Crude oil futures settled lower Aug. 13 after the International Energy Agency revised lower its near-term demand outlooks. NYMEX September WTI settled down $1.71 at $78.35\/b and ICE October Brent declined $1.61 to $80.69\/b. The world is seeing a major deceleration in oil demand growth led by China, with inventories set to rise next year even if OPEC+ were to postpone its plans to ease output cuts, the IEA said in its monthly oil market report released Aug. 13. The IEA highlighted preliminary data for July showing China's crude oil imports fell to their lowest since September 2022. The report comes on the heels of OPEC striking a more bearish tone in its monthly oil market report Aug. 12. The producers group said the \"call\" on the OPEC+ alliance's crude -- the volume of oil it must produce to balance the market -- would be 43.0 million b\/d in 2024 and 43.6 million b\/d in 2025. That is down 100,000 b\/d and 300,000 b\/d respectively from July's forecast. \u201cOPEC+ acknowledgement of weakening demand may also be a cue that the group is considering to defer its plan to gradually unwind voluntary production cuts, which risks eventually creating a surplus even barring a recessionary outlook,\u201d TD Securities Senior Commodity Strategist Daniel Ghali said in a note. Most US refiners stated in recent second-quarter results call their total third-quarter refinery run rates will be lower than actual second-quarte r refinery throughput as they seek to balance output with slowing demand, thus providing some support for weakening refining margins, according to an Aug. 13 S&P Global Commodity Insights analysis. \"We think [third-quarter] utilization will reflect some modest economic optimization, and is an encouraging sign that ultimately could help balance the market if demand shows improvement in the second half,\" John Royall, analyst with JP Morgan, said in a recent note. NYMEX September RBOB declined 6.82 cents to $2.3747\/gal and September ULSD dipped 1.73 cents to $2.3892\/gal. Markets remain on edge ahead of a key US Consumer Price Index report expected Aug. 14 that could drastically shift expectations of the Federal Reserve's rate cut cycle, analysts warned. \"The speed with which financial markets moved to price-in 100 basis points of US rate cuts is inconsistent with the economic data released so far in August,\" ANZ Research analysts said Aug. 13. The recent uptick in unemployment and temporary layoffs has dampened the economic outlook for the US, which along with demand concerns in China, have put crude prices under pressure, they continued. The US Producer Price Index released Aug. 13 climbed 0.1 percentage point in July, indicating a slower-than-expected uptick in wholesale prices. ","headline":" Crude slides as market eyes slowing China, US demand outlooks","updatedDate":"2024-08-13T19:49:06.000"},{"Unnamed: 0":103,"body":" Low Carbon Fuel Standard credits traded as high as $62\/mt on Aug. 13, up 26.5% from the day prior amid the release of the Proposed Low Carbon Fuel Standard Amendments by the California Air Resources Board on Aug. 12. Platts, part of S&P Global Commodity Insights, assessed third-quarter LCFS credits at $59\/mt on Aug. 13, up $10 from Aug. 12. The assessment has not been this high since April 29, but market participants did not seem confident the rally would last. CARB proposed a 9% decrease in carbon intensity targets in 2025, up from the initial amendment\u2019s 5% decrease. One market participant said the decrease was larger than expected, but that it was necessary to encourage more investments in low-carbon-intensity fuels in the state. The amendments included a 20% cap credit generation for renewable diesel and biodiesel produced from virgin soybean oil and canola oil, which would take effect starting January 2028. A second market sources said regulating feedstock was a step in the right direction. The updated proposed amendments kept the existing exemption of jet fuel as an obligated fuel.\u202fCARB\u2019s public notice provided the justification that the addition of jet fuel to the program would not guarantee that airlines would procure and use alternative jet fuel as a compliance response, but that suppliers may instead meet their obligation with acquired credits. Sustainable aviation fuel will continue to generate credits, but will be subject to the sustainability requirements for biomass-based feedstocks and the cap on soybean oil and canola oil. ","headline":"California LCFS credits rise 27% after CARB updates proposed project amendments","updatedDate":"2024-08-13T19:19:50.000"},{"Unnamed: 0":104,"body":" The price differential for WTI Midland delivered into Europe on a CIF Rotterdam basis has reached a seven-month high on Aug. 13 amid a tightening picture for light sweet crude. Platts, a part of S&P Global Commodity Insights, last assessed WTI Midland CIF Rotterdam at a $3.06 premium to Dated Brent, up 38.5 cents\/\/b on the day, and its highest level since Feb. 23, when the assessment reached $3.06\/b. The differential has been supported by wider sentiment pointing to supply tightness in the light sweet crude complex. The Aug. 13 Platts Market on Close assessment process saw strong bidding activity across the twelve days to a month ahead forward laycan, with two bids from Vitol and one from Gunvor demonstrating value higher. Aug. 12 had also seen an outstanding WTI Midland bid demonstrating a strengthening value. This comes amid a \"paucity of Midland availability\" that also seemed to be supporting differentials in related light sweet markets, such as for Oseberg and Troll crudes, said a source. \"We think Midland is tight off a tight US and some insurance barrel buying against Libya,\" said a second source, referring to the ongoing force majeure declared by the Libyan National Oil Corp. Aug. 7 around the Sharara oil field. Interruptions to output at Libya's largest field began Aug. 4, with Commodity Insights reporting a full shutdown on Aug. 5. With Sharara crude having an API of 42.2 degrees and a sulfur content of 0.09%, WTI Midland crude is generally seen as an ample substitute with an API of between 40-44 degrees and a sulfur content of 0.2%. ","headline":"WTI Midland differential reaches seven-month high","updatedDate":"2024-08-13T18:49:11.000"},{"Unnamed: 0":105,"body":" Honeywell and Repsol have announced a strategic collaboration to advance the production of biofuels and circular materials. This partnership aims to leverage Honeywell's cutting-edge technologies to create new pathways for chemical production and renewable fuels at Repsol\u2019s refineries, utilizing various waste materials such as fats, oils, greases, biomass, and solids, Honeywell said in a statement Aug. 12. The primary objective of the collaboration is to scale and commercialize Honeywell's technologies to produce diverse biofuels, including sustainable aviation fuel (SAF) and renewable diesel. The technology will be integrated into Repsol's existing refinery infrastructure, aiming to align with the global energy transition megatrend and reduce carbon emissions. Repsol has committed to achieving net zero emissions by 2050. The company is actively working on various fronts, including increasing the production of renewable fuels, enhancing energy efficiency, and investing in carbon capture and storage technologies. \"We seek collaborations to provide innovative solutions that help our customers and stakeholders reduce carbon and greenhouse gas emissions through biofuel production. Our collaboration with Repsol illustrates how Honeywell can apply new technologies to reduce carbon emissions while producing biofuels and advanced materials leveraging current refinery infrastructure,\" Bryan Glover, CTO of Honeywell Energy and Sustainability Solutions, said. Honeywell's UpCycle process technology, which will be deployed at Repsol\u2019s facilities converts plastic waste into Honeywell Recycled Polymer Feedstock, which can be used to produce new plastics. This technology can recycle a wide range of plastics with potential to recycle nearly 90% of waste plastics, significantly increasing the amount of them that can be turned into polymer feedstock. Honeywell is committed to reducing its greenhouse gas emissions and supporting the global energy transition. The company has set a target to achieve carbon neutrality in its operations and facilities by 2035. Berta Cabello, Repsol\u2019s Director of Renewable Fuels, emphasized the importance of the initiative: \"Renewable fuels and plastics recycling are crucial to Repsol\u2019s commitment to achieve net zero emissions by 2050. Our collaboration with Honeywell to advance and adopt cutting-edge technologies will help us reduce our carbon footprint and become a benchmark in renewable fuels and hydrogen production by 2030.\" In 2023, Repsol selected Honeywell\u2019s Ecofining technology to produce renewable fuels from sources such as used cooking oil and waste animal fat at its plant in Puertollano, Spain. This technology, developed in collaboration with ENI, will enable the plant to produce approximately 240,000 mt\/year of renewable diesel and other products. This alliance follows the trend of leading corporations worldwide setting ambitious emission reduction targets to align with global sustainability goals. ","headline":"Honeywell and Repsol join forces to enhance biofuel, recycling efforts","updatedDate":"2024-08-13T18:42:42.000"},{"Unnamed: 0":106,"body":" Nigeria's oil production including condensates averaged 1.53 million b\/d in July, a 2% rise month on month, according to data released Aug. 13 by the country's oil industry regulators. Oil production continues to show signs of recovery according to Nigerian Upstream Petroleum Regulatory Commission data, having edged up for the third consecutive month. Crude output alone stood at 1.31 million b\/d in July, up from 1.28 million b\/d in June, the data showed. The recent uptick follows years of sinking output, worsened by rampant crude oil theft, underinvestment and limited exploration activity. Nigeria recorded increased output of its Bonny, Brass, Qua Iboe and Forcados crude streams, according to the NUPRC, which state oil firm Nigerian National Petroleum Company attributed to improved security surveillance at the production facilities. Crude output was also bolstered by an increase in output of the new Utapate crude, located in Nigeria's new Oil Mining Lease (OML) 13 in the southern Akwa Ibom state, operated by Nigerian company Sterling Oil. The Utapate crude oil blend, a new grade geared toward the international crude market, commenced production in early May. Output reached around 24,300 b\/d in July up from around 19,000 b\/d in June. NNPC said Aug. 5 that the field has the potential to increase production to 50,000 b\/d by the end of 2024 and that Spanish oil company Repsol had lifted the first cargo of 950,000 barrels. Sources from Sterling confirmed the 50,000 b\/d target. Nigerian government officials say that the country oil production could reach 2 million b\/d by the year of the end, on the back of improved security measures put in place to curb crude oil theft. In July, Nigeria's President Bola Tinubu issued marching orders to the country's military high command to curb oil theft and vandalism in the Niger Delta region within the shortest possible time. Nigeria's Chief of Naval Staff, Emmanuel Ikechukwu Ogalla, said Aug. 7 that Nigeria's military had successfully closed off routes used for the illegal shipment of stolen crude, stepped up surveillance and enforcement in the oil-producing areas, with the deployment of 12 patrol ships on the sea to protect oil production facilities. Meanwhile, several international oil companies, including Eni, ExxonMobil and TotalEnergies, have agreed to sell onshore and shallow water oil assets to local companies such as Seplat and Oando, but the deals have faced regulatory hurdles. Nigerian crude is light and sweet and popular among European refiners. Platts, part of S&P Global Commodity Insights, last assessed it at a $2.40\/b premium to Dated Brent on Aug. 12. ","headline":" July oil output increases 30,000 b\/d on month amid security crackdown","updatedDate":"2024-08-13T18:35:43.000"},{"Unnamed: 0":107,"body":" The EU\u2019s soybean meal imports in the marketing year 2024-25 (July-June) totaled 2.24 million metric tons as of Aug. 11, up 13% on the year, European Commission data showed Aug. 13. Poland and Spain were the largest buyers within the bloc over the period at 448,494 t and 338,828 t, respectively. Meanwhile, Brazil and Argentina were the largest soybean meal suppliers to the EU, at 1.07 MMt and 894,865 t, respectively. The EU imported 510,996 t of soybean meal in MY 2023-24, according to the data. The region\u2019s soybean imports dropped 20% on the year to 1.21 MMt in MY 2024-25. Spain and Germany were the largest buyers at 386,988 t and 228,223 t, respectively. Brazil-origin products accounted for 71.3% of the EU\u2019s raw soybean inflows, while its share of soybean meal was 48% over the period. The EU is the world\u2019s largest soybean meal importer and the second-largest soybean purchaser. The bloc\u2019s soybean oil imports in MY 2024-25 fell 59% year on year to 43,150 t as of Aug. 11, EU data showed. Ireland and the Netherlands were the largest buyers within the bloc, while the UK and Norway were the largest soybean oil suppliers to the EU. The EU imported 693,725 t of soybean oil in MY 2023-24, according to the data. The bloc\u2019s sunflower oil imports decreased 15% on the year to 232,397 t in MY 2024-25. The EU\u2019s rapeseed oil imports decreased 81% year on year to 10,252 t over the period, while palm oil inflows were at 289,989 t, down 31% on the year, the data showed. Platts, part of S&P Global Commodity Insights, assessed soybeans FOB Paranagua June new crop at $393.36\/t Aug. 12, up $3.21\/mt day on day. ","headline":" MY 2024-25 soybean meal imports rise 13% on year as of Aug 11","updatedDate":"2024-08-13T17:56:43.000"},{"Unnamed: 0":108,"body":" Nigeria\u2019s landmark new Dangote refinery looks unlikely to realize its ambitions to produce gasoline in August, according to sources and ship tracking data, as continued naphtha exports indicate that the plant has yet to start up its catalytic reformer. As Nigeria\u2019s primary fuel type, gasoline has been a key focus of the Dangote project, which aims to secure energy independence for the West African nation and to break a history of import dependency from Europe. Analysts expect the refinery to produce its first gasoline by blending naphtha with reformate produced from its catalytic reformer, while higher yields of straight run gasoline should arrive later with the commissioning of the plant\u2019s residue fluid catalytic cracker, or RFCC. In the latest of numerous revised timelines, representatives for Dangote had last promised to deliver the project\u2019s first gasoline by mid-August, while a pause in naphtha exports had lifted expectations of imminent supply. The refinery's naphtha exports from Lekki dropped sharply in July, with no exports taking place in the two weeks on either side of July 15, according to S&P Global Commodities at Sea data. Previously, the plant had exported 10 cargoes per month in May and June, amounting to around 120,000 b\/d. A spokesperson for Dangote also confirmed July 18 that no new naphtha orders were being booked. However, on July 31, the refinery exported its largest naphtha cargo in four months, dispatching some 814,000 barrels to South Korea on a Vitol-chartered tanker, while one naphtha trader said new export activity was expected imminently. \"Reformer startup is the big question mark,\" the trader said. \"We heard it should be on very soon, but as you say, this nap load is saying otherwise.\" The reformer should come onstream by September 2024, according to forecasts by S&P Global Commodity Insights analysts, while the RFCC is likely to come online in 2025, facilitating higher gasoline production volumes next year. The Dangote Group declined to comment on its latest timeline expectations. Gradual shift to gasoline, ULSD In a note July 31, Daniel Evans, Richard Joswick and other lead Commodity Insights analysts pointed to a \u201cfaster-than-anticipated startup\u201d of Dangote operations after the recent streaming of its mild hydrocracker, anticipating looser oil product supply balances by as soon as the fourth quarter of 2024. Yields are expected to gradually shift from naphtha, fuel oil and gasoil to gasoline and ULSD. Meanwhile, resumed naphtha flows are expected to be directed toward Asia, where prices look most supportive, traders said. Naphtha exports from Dangote have not resumed at the pace seen in May and June, but additional outflows could help mitigate a recent bullish swing in South Korea and other demand hubs. Platts, part of S&P Global Commodity Insights, assessed naphtha C+F Korea cargoes at $688\/mt Aug. 13, up strongly from $653.50\/mt July 30 and $677.50\/mt Aug. 12. Fuel oil export spike As analysts look to 2025 for the startup of Dangote\u2019s RFCC, rising crude runs could also exert growing pressure on fuel oil markets. Without an active RFCC, the refinery is unable to upgrade low-sulfur straight run fuel and has instead sold supply to other refiners or marine fuel suppliers capable of blending the product into the very low sulfur fuel oil (0.5%) pool. Early exports from the refinery in April and May had already weighed on European feedstock prices, with traders talking of the refinery \u201cflooding the market\u201d with new supplies, while volumes are set to grow in line with utilization rates. According to a Dangote representative July 31, the refinery was processing around 400,000 b\/d -- around 60% of its nameplate capacity -- by the end of the month, while the group has aimed to reach 85% utilization by year-end, he said. Commodity Insights analysts have said the refinery could take until 2027 to reach higher \"steady state\" utilization levels, yet they project run rates to increase in the months ahead, boosting fuel oil supplies. Despite rising crude runs from the refinery, fuel oil exports from Dangote appeared to peak in April at 100,700 b\/d and have steadily receded month on month to a low of 48,000 b\/d in July, lifting hopes among fuel oil suppliers that markets might avoid additional import pressure. The downward trend, however, appears to have reversed course in August. Dangote's fuel oil exports averaged 65,000 b\/d Aug 1-13, up 33% from levels for the full month of July, according to CAS data. Three fuel oil cargoes are currently inbound for Singapore from Dangote, while traders flagged that continued export strength could increasingly exert pressure on the European complex. Platts assessed FOB NWE LSSR cargoes at a $1.14 discount to M1 Brent Aug. 12, up from a $3.17 discount July 1. ","headline":"Nigeria\u2019s Dangote refinery loadings signal delay to gasoline plans","updatedDate":"2024-08-13T17:42:28.000"},{"Unnamed: 0":109,"body":" Most US refiners stated in recent second-quarter results call their total third-quarter refinery run rates will be lower than actual second-quarter refinery throughput as they seek to balance output with slowing demand, thus providing some support for weakening refining margins, according to an Aug. 13 S&P Global Commodity Insights analysis. \u201cWe think [third-quarter] utilization will reflect some modest economic optimization, and is an encouraging sign that ultimately could help balance the market if demand shows improvement in the second half,\u201d John Royall, analyst with JP Morgan, said in a recent note. Royall said this is a big \u201cif\u201d given recent fall of in US gasoline and diesel demand at 6% and 8%, respectively, below the five-year pre-coronavirus average. JP Morgan said second-quarter refinery utilization in its coverage group -- which is comprised of about 50% of US refining capacity -- averaged 95% of capacity. \u201cNot surprisingly, [third-quarter] aggregate guidance is down sequentially due to fall maintenance and to the lower crack environment,\u201d he wrote. US West Coast refinery vulnerabilities Valero Energy expects third-quarter runs at its two California refineries to average 245,000 b\/d, down more than 11% from the 276,000 b\/d refinery runs in the second quarter. While Valero did not provide guidance on any planned work for the region in the third quarter, the company noted that because the state is a hard and expensive place in which to operate, \u201cit is probably one of the places that you would ultimately see some refinery closures.\u201d This is despite regional gasoline supply tightness, as renewable plant conversions have cut gasoline supply, spurring the state\u2019s gasoline imports to an average of 70,000 b\/d in the second quarter, Valero noted, with much of the supply coming from India and South Korea. As of Aug. 13, third-quarter 2024 US West Coast cracking margins for Alaska North Slope were averaging $10.94\/b, compared with the third-quarter 2023 margins of $37.20\/b, according to margin data from Commodity Insights. However, USWC refiners have yet to fully realize the benefit of cheaper Canadian crudes flows on the Trans Mountain Express, which could help bolster margins and cracks. TMX volumes rose to average 380,000 b\/d in July, compared with June\u2019s 330,000 b\/d of exports. Through end-July, about 40% of TMX cargoes were shipped to either California or Washington state. US Midwest margins bumped up by Joliet outage In the US Midwest, the sudden shutdown of ExxonMobil\u2019s 251,800 b\/d Joliet refinery in Channahon, Illinois, on July 15 after a tornado destroyed the electrical infrastructure bumped up some Midwestern refinery margins for the third quarter of 2024, with Midwest Syncrude cracking margins averaging $12.71\/b as of Aug. 13, compared with the third-quarter 2023 average of $10.54\/b, according to Commodity Insights margin data. With the restart of Joliet on Aug. 12, margins have begun to slip lower, with Syncrude cracking margins at $8.19\/b as of Aug. 12. Several refiners have cut Midwest refinery runs guidance for the third quarter. Valero expects a 5.25% refinery run drop to a median of 415,000 b\/d throughput in the third quarter at its Midwest refineries, but gave no details on work planned for the quarter. Marathon guided on its second-quarter results call an 8.7% throughput drop in the third quarter to 1.13 million b\/d in its Midwest refineries, which includes its Salt Lake City plant in the Rockies. Overall, refiners plan to cut back runs in the third quarter due to weakening margin resulting from softer demand. Phillips 66 ran its refining system -- which includes two European plants -- at a record-high 98% in the second quarter. For the third quarter, it expects total system refining utilization to be in the low 90%s. \u201cWe are actually guiding down right now because we see a softening in the market and particularly in some regions on the coast, both East and West,\u201d Rich Harbison, Phillips 66\u2019s head of refining, said in the company\u2019s second-quarter results call . \"But we are going to take this opportunity to some discretionary maintenance,\u201d he added. Refinery Margin Tracker: US Atlantic Coast Bonny Light Cracking Saharan Blend Cracking CPC Blend Cracking Forties Cracking Week ending Aug. 9 6.42 10.62 14.04 8.95 Week ending Aug. 2 6.54 10.88 14.15 9.05 Third quarter to date 6.60 10.37 13.81 8.79 Third quarter 2023 20.25 21.54 25.39 20.41 Second quarter 2024 8.61 11.93 16.65 10.90 First quarter 2024 9.14 10.42 17.46 8.82 US Gulf Coast WTI MEH Cracking Mars Coking WCS ex-Nederland Coking Maya Coking Week ending Aug. 9 12.89 12.20 15.59 13.89 Week ending Aug. 2 13.31 12.43 17.31 14.16 Third quarter to date 12.55 11.16 16.32 12.81 Third quarter-23 21.95 20.02 24.02 19.87 Second quarter-24 13.10 10.68 15.21 12.34 First quarter 2024 18.09 16.47 20.25 17.50 US Midwest Bakken Cracking WTI Cushing Cracking Syncrude Cracking WCS ex-Cushing Coking Week ending Aug. 9 17.60 15.96 11.69 19.14 Week ending Aug. 2 21.51 19.23 16.17 23.19 Third quarter to date 17.59 14.79 12.17 18.69 Third quarter-23 15.90 16.26 10.54 18.62 Second quarter-24 14.19 12.76 7.60 14.82 First quarter 2024 16.82 13.35 13.00 15.61 US West Coast ANS Cracking Oriente Coking Napo Coking WCS Hardisty Coking Week ending Aug. 9 11.32 14.87 13.41 26.38 Week ending Aug. 2 11.70 14.38 12.79 28.72 Third quarter to date 10.94 14.05 12.57 27.29 Third quarter-23 37.20 44.94 42.18 59.86 Second quarter-24 20.45 26.03 24.76 37.76 First quarter 2024 21.54 23.02 24.67 42.52 Singapore Dubai Cracking Murban Cracking WTI MEH Cracking Forties Cracking Week ending Aug. 9 3.07 5.42 4.11 0.47 Week ending Aug. 2 3.04 5.07 4.55 0.54 Third quarter to date 2.26 4.43 3.79 -0.39 Third quarter-23 7.42 9.58 10.42 6.53 Second quarter-24 0.41 2.65 3.08 -0.41 First quarter 2024 4.92 8.69 8.72 3.11 Northwest Europe Ekofisk Cracking Basrah Light Cracking WTI MEH Cracking Brent Blend Cracking Week ending Aug. 9 5.90 0.26 9.30 6.23 Week ending Aug. 2 6.22 0.87 9.15 6.39 Third quarter to date 5.60 0.42 7.81 5.55 Third quarter-23 17.04 11.37 18.93 16.67 Second quarter-24 7.94 3.24 8.61 7.24 First quarter 2024 10.99 4.01 12.50 9.93 Italy Urals Cracking CPC Blend Cracking Basrah Light Cracking Azeri Light Cracking Week ending Aug. 9 16.57 12.43 1.07 8.34 Week ending Aug. 2 16.89 12.33 1.94 8.61 Third quarter to date 16.57 11.39 1.90 7.84 Third quarter-23 28.64 20.69 10.99 16.51 Second quarter-24 18.68 12.97 4.08 9.90 First quarter 2024 22.48 16.11 4.17 11.28 Source: S&P Global Commodity Insights ","headline":" US refiners to lower Q3 run rates to balance weaker demand","updatedDate":"2024-08-13T17:28:39.000"},{"Unnamed: 0":110,"body":" Seaspan Corp. and Wai Hai Lines have ordered dozens of dual-fuel containerships capable of running on LNG or methanol, the companies said in recent regulatory filings, underscoring the sector\u2019s strong appetite for alternative marine fuels in decarbonization drive. In a filing to the US Securities and Exchange Commission dated Aug. 9, Atlas, Seaspan\u2019s parent, disclosed 27 vessels ranging from 9,000 to 17,000 twenty-foot equivalent units had been ordered in June. Of them, eight 9,000-TEU, five 16,000-TEU and 10 17,000-TEU ships can run on LNG and conventional, oil-based fuels. Four 9,000-TEU ships can be powered by methanol and conventional fuels. Seaspan is expected to time-charter the ships to container lines when they are delivered over 2027-28, but no further details have been disclosed. Earlier media reports suggested that A.P. Moller-Maersk could be one of the charterers. Maersk declined to comment on the matter. Separately, Taipei-listed Wai Hai said Aug. 12 it ordered 12 8,000-TEU ships that can run on methanol and conventional fuels from compatriot yard Taiwan CSBC for up to $2 billion, with options for another four. Another four 8,700TEU ships with the same dual-fuel capability were contracted from HD Hyundai Samho for up to $522 million. Driven by tightening environmental regulations and more eco-conscious clients, containership owners have been the keenest in booking ships fueled by alternative energy sources to reduce their greenhouse gas emissions. Shipbroker Braemar estimated 224 LNG-capable and 161 methanol-capable boxships were on the global order book as of Aug. 7, far exceeding any other shipping segments like tankers and dry bulk carriers. Methanol can be a low-carbon fuel when produced via sustainable means, while the owners of LNG-powered ships can switch to biomethane or e-methane for deep decarbonization even though LNG can only reduce 20%-30% of greenhouse gases compared with conventional fuels, according to their supporters. However, LNG is currently cheaper and more available in the world\u2019s main bunkering hubs than methanol, some industry participants said. In Rotterdam, Europe\u2019s largest bunker hub, the monthly average delivered bunker price for 0.5% sulfur marine fuel oil was $16.128\/Gigajule for ships in intra-EU trade, compared with LNG at $14.807\/Gj and gray methanol at $19.414\/Gj, according to calculations based on S&P Global Commodity Insights\u2019 Platts data. Green methanol could be at least two times more expensive based on industry estimates. ","headline":"Seaspan, Wai Hai order dozens of dual-fuel ships running on LNG or methanol","updatedDate":"2024-08-13T15:32:06.000"},{"Unnamed: 0":111,"body":" Crude oil exports by Azerbaijan's state-owned oil company Socar totaled 4.2 MMt in the second quarter of 2024, averaging 337,826 b\/d, down 9.7% from Q1, it said in a statement Aug. 13. The company said this figure included oil produced from the fields which it operates as well as the fields in which it is a partner -- such as Azerbaijan's main ACG oil field operated by BP. The company did not specify how much crude came from the fields in which it is a partner. Socar said that Q2 crude production from the fields it operates totaled 1.876 MMt, an average of 150,896 b\/d, down 3.4% from Q1. It did not provide figures for individual fields. Azerbaijan's total crude production in Q2 was 7.174 MMt, an average of 577,039 b\/d, down 8.1% from Q1. Socar's exports of petroleum products, petrochemical products and gas chemical products in Q2 totaled 659,000 tons, up 37.8% from Q1, the data showed. Socar operates the 150,000-b\/d (7.5-MMt\/year) Heydar Aliyev refinery, which has been undergoing a major modernization program since 2015, and in June 2024 began producing Euro 5 gasoline. The plant also has the capacity to produce 790,000 t\/yr of Euro 4 diesel, 400,000 t\/yr of bitumen as well as dry gas, light condensate, TC-1 jet, C3 and C4 LPG, stabilized FCC naphtha, LCO and slurry. ","headline":"Azerbaijan's Socar sees crude exports fall 9.7% in Q2","updatedDate":"2024-08-13T13:30:36.000"},{"Unnamed: 0":112,"body":" Russia's Omsk refinery was expected to restart a primary processing unit affected by fire towards the end of August, according to market sources |Aug. 13. The refinery reported fire at a pumping station Aug. 1 adding that operations continued normally. However, according to market sources and media reports, the fire affected an 8.6 million mt crude and vacuum distillation complex AVT-10. Separately, Volgograd refinery was on track to restart its hydrocracker after an unplanned outage. The unit has been offline since the last week of July and was expected back around mid-August, according to sources. As a result of the hydrocracker outage, Volgograd had also reduced crude processing, according to sources. Platts, part of S&P Global Commodity Insights, assessed Urals CIF Rotterdam at $72.99\/b on Aug. 12. ","headline":" CDU at Russia's Omsk offline, Volgograd completing hydrocracker repairs","updatedDate":"2024-08-13T13:20:16.000"},{"Unnamed: 0":113,"body":" India's Haldia refinery is planning to carry out maintenance in August and September, according to market sources. The maintenance, which will include the whole refinery, is expected to start around Aug. 17 and last approximately 52 days, sources said. \"We don't confirm any precise date for any turnaround due to last-moment changes as company's policy,\" said a company official when asked by S&P Global Commodity Insights. In Asia, \"refinery downtime decreased by 135,000 b\/d, with total outages at around 1.6 million b\/d for the week ending Aug. 9 as refineries restarted from maintenance,\" Commodity Insights analysts wrote in a recent report, adding that some plants in India are gearing for works in August and September. ","headline":" India's IOC Haldia to carry out maintenance in Aug-Sep","updatedDate":"2024-08-13T12:41:04.000"},{"Unnamed: 0":114,"body":" Indonesia's Balikpapan Refinery Development Master Plan (RDMP) -- under which the refinery's capacity has already increased from about 260,000 b\/d to 360,000 b\/d -- will be completed no later than September next year, the country's energy and mineral resources ministry said in a statement Aug. 12. Following the upgrade, the refinery will also produce up to 225,000 mt\/year of additional petrochemical products. \"In 2022, when I came here, there were still a lot of civil works. But now everything has been built. So it's just a matter of finishing. The progress now is more than 91%,\" said the energy and mineral resources minister Arifin Tasrif during a site visit Aug. 11. The new completion target comes after the project has faced several challenges in recent years, notably the pandemic, as well as geopolitical woes like the Russia-Ukraine conflict impacting supply chains, said Tasrif. The capacity increase to 360,000 b\/d from 260,000 b\/d was completed during a maintenance that started in February, which was a key step to integrating existing units with new ones, S&P Global Commodity Insights reported previously. The new capacity includes the revamped 300,000 b\/d CDU IV, the capacity of which was increased by 50%, and the 60,000 b\/d CDU V. The refinery is now operating at its increased capacity, the company said late Aug. 12, adding that CDU IV is operating normally. CDU IV had been undergoing maintenance following a fire incident May 25 and restarted July 27, according to market sources. After the completion of the upgrade in 2025, the refinery's complexity will also be higher, the company said. Marked as one of Indonesia's national strategic projects, the Balikpapan RDMP costs $7.4 billion in investments. Of this , $4.3 billion comes from equity, while the remaining $3.1 billion was obtained through loans involving Export Credit Agencies. The project is expected to enhance national energy resilience, and help the country to meet increased demand for fuel and petrochemical products. In all, Asia is expected to add nearly 1.2 million b\/d of net distillation capacity, mainly in China and India, over the next two years, analysts at S&P Global Commodity Insights said in a July report. ","headline":" Indonesia's Balikpapan refinery upgrade targets Sep 2025 completion","updatedDate":"2024-08-13T12:35:12.000"},{"Unnamed: 0":115,"body":" Electrolyzer manufacturer ITM Power signed a contract with Shell on Aug. 13 for its 100-MW Refhyne II green hydrogen plant at its Rheinland refinery in Germany, after the energy company took a positive final investment decision on July 25. Refhyne II will produce up to 44 metric tons of hydrogen per day via renewables-powered electrolysis, ITM said in a statement. The hydrogen will be used in fuel production at Shell\u2019s Wesseling refinery, with the proton exchange membrane electrolyzer to start up in 2027. \u201cThe Refhyne II project builds on the lessons learned from the 10-MW Refhyne I plant, which was put into operation in 2021, and on ITM's and Linde's experience in engineering, constructing, and operating other green hydrogen projects across Europe,\u201d ITM said. Linde Engineering is the engineering, procurement and construction partner for the hydrogen plant. ITM said the Refhyne II project had been enabled by supportive government frameworks and policies, including binding EU targets for renewable hydrogen use in industry and transport, and Germany\u2019s regulatory framework. The project also received funding from the EU\u2019s Horizon program, it said. Platts, part of S&P Global Commodity Insights, assessed the cost of producing hydrogen via alkaline electrolysis in Europe at Eur6.29\/kg ($6.87\/kg) Aug. 12 (Netherlands, including capex), based on month-ahead power prices. PEM electrolysis production was assessed at Eur6.55\/kg. The refinery comprises the Wesseling (south) and Godorf (north) sites although Shell will end crude processing at the Wesseling site in 2025. ","headline":" ITM receives 100-MW electrolyzer contract for Shell Rheinland","updatedDate":"2024-08-13T12:33:00.000"},{"Unnamed: 0":116,"body":" Russia's reinstated gasoline export ban, coupled with various other factors, is expected to lower domestic spot prices by 20% to 30% and consequently put a dent in the superior margins refineries have enjoyed in recent months, market watchers told S&P Global Commodity Insights. Russia had originally imposed the temporary ban -- aimed at bringing stability to the domestic market -- on March 1, 2024, for six months until the end of August, but lifted it temporarily in late May. Although export volumes are fairly marginal, typically ranging between 300,000-500,000 mt\/month, the government reinstated the ban starting Aug. 1 and also extended it to the end of October. Coupled with a gradual end of maintenance works at Russian refineries, the ban should create a surplus on the domestic gasoline market and return the spot price for 95 RON gasoline to a more justified range of Rb50,000-60,000\/mt ($578-$693\/mt), according to Sergey Kaufman, an analyst with Moscow-based think tank Finam, said in an email Aug. 6. Amid planned and unplanned outages at refineries, domestic spot prices have been climbing most of the year, but since early June -- after the lifting of the export ban -- they have surged by some 44% to close to an all-time peak at around Rb74,460\/mt. The price rally was driven by various factors weighing on supply simultaneously, according to Alexander Kotov, head of consulting with Neft Research, including the unplanned outage of one of the two catalytic crackers at Lukoil's Nizhny Novgorod refinery in January due to equipment failure, drone attacks on several refineries in the central part of Russia, the impact of a severe flood that led to the temporary shutdown of the Orsk refinery, and technical issues at the Omsk and Volgograd refineries. Supply chain bottlenecks have also played a role, Kotov said, noting that a shortage of railcars has held up oil product loadings at refineries. The gasoline ban extension will help increase availability, which will certainly have an impact on commodity exchange prices, Igor Yushkov, a senior analyst with the National Energy Security Fund and a specialist at the Russian government's Financial University, said in a phone interview on Aug. 9. The effect will be similar to those achieved in September 2023 and March 2024, when restrictions on exports brought spot prices down, Yushkov said. However, some analysts do not think that the ban extension is likely to have a significant impact on spot prices. Tamara Kandelaki, Chairman of the Committee on Economics at the Oil Refiners and Petrochemical Association, said in an Aug. 8 email that it will only have limited \"psychological effect\". In her opinion, the Russian oil refining industry has sufficient flexibility to switch to making alternative products, such as naphtha. Kandelaki also noted that the authorities no longer publish data on gasoline output, which would make discussions purely \u201chypothetical.\" End of super-margins Most analysts do agree that the export ban will drag refinery margins down. Finam's Kaufman said it would be more accurate to describe the impact of the anticipated fall as a \"normalization\" as current levels are abnormally high. In addition to extremely high gasoline prices, Russian refineries have also enjoyed an 82% hike in payments under the so-called damping mechanism in the first half of 2024, Kaufman said. Russian refineries receive compensation under the damping mechanism when export prices exceed domestic prices. Kotov added that the ban would primarily hurt the economics of oil refineries focused on exports due to their geographical location and product basket structure, such as the Kirishi and Orsk refineries. According to Yushkov, however, while profits will decline modestly due to lower exports, they will be offset by higher compensation under the damping mechanism. While analysts may vary on their view of impact on margins they are confident that the Russian government will continue to closely monitor fuel prices due to their impact on inflation. \"The rise in fuel prices means a rise in prices for consumer goods. That means inflation. That means the Central Bank will continue to raise the [key interest] rate,\" Kotov said. ","headline":"Russia's gasoline export ban extension to have a mixed impact on refineries","updatedDate":"2024-08-13T11:41:56.000"},{"Unnamed: 0":117,"body":" Crude oil futures were rangebound in morning European trading Aug. 13, as the market awaits the release of key inflation data and oil market indicators through the week. At 1045 GMT, the ICE October Brent crude futures contract was trading at $82.12\/b, down 18 cents\/b from the previous close, while the September NYMEX light sweet crude contract was 14 cents\/b lower at $79.92\/b. The International Energy Agency released its monthly Oil Market Report Aug. 13, in which its estimate of the \"call\" or demand for OPEC+ crude was trimmed by 100,000 b\/d for both 2024 and 2025, to 41.6 million b\/d and 41 million b\/d, respectively. Analysts were closely watching demand expectations from the IEA following a series of cuts to its 2024 outlook throughout the year so far. \u201cThe market will be keen to see if the IEA lowers its demand forecast for 2024 for the fifth consecutive time this year, especially after last week's market turmoil,\u201d Arne Lohmann Rasmussen, head of research at Global Risk Management, said in a note. The IEA's downbeat views on oil demand growth followed a more bearish tone in OPEC's own monthly oil market report, published Aug. 12, in which estimates of 2024 global oil consumption were revised down by 140,000 b\/d. The OPEC report also trimmed the \u201ccall\u201d on the OPEC+ alliance\u2019s crude to 43.0 million b\/d in 2024 and 43.6 million b\/d in 2025, down 100,000 b\/d and 300,000 b\/d respectively from its July forecast. This week will also see the release of US Producer Price Index -- scheduled for later Aug. 13 -- and the US Consumer Price Index -- set for Aug. 14. US retail sales data is also expected to be released Aug. 14. Global financial markets are likely to remain on tenterhooks ahead of the slate of US inflation prints, which could shake up forecasts of global monetary easing and crude demand, according to analysts. \u201cThe Consumer Price Index (CPI) report will be closely monitored for inflation trends, which could significantly influence Federal Reserve policy decisions,\u201d Rasmussen said. Elsewhere in the market, crude prices have been somewhat dampened by expectations of a marginal uptick in US inventories in the week to Aug. 9. Commercial crude stocks likely rose 530,000 b\/d to around 429.8 million barrels over the period, analysts surveyed by S&P Global Commodity Insights said. ","headline":" Crude rangebound ahead of key data releases through week","updatedDate":"2024-08-13T11:37:45.000"},{"Unnamed: 0":118,"body":" Despite the structurally bearish market, European LNG prices are expected to continue their upward trajectory in the week to Aug. 16 driven by geopolitical risks and supply uncertainty, traders said. Platts, part of S&P Global Commodity Insights, last assessed the DES Northwest Europe price for September at $12.691\/MMBtu Aug. 9, an increase of $1.091\/MMBtu or 9.4% on the week, while the September JKM price stood at $14.19\/MMBtu on Aug. 12, showing an uptick of $1.418\/MMBtu from the previous week. NWE, Med Supply-side uncertainties have fueled price increases, adding to the market's anxiety ahead of winter procurement. Concerns include potential maintenance at Norwegian facilities, escalating tensions in the Middle East and supply delays from Asia. In addition to the ongoing Iran-Israel hostilities, the week to Aug. 9 was also marked by added tensions between Russia-Ukraine as Ukrainian troops entered Russian borders near the Sudja interconnection point, putting the gas infrastructure at risk. Despite the price increases, demand in Northwest Europe remains weak, influenced by high inventories, steady Norwegian supply and the fact that LNG is relatively expensive versus domestic gas hub prices. The price increments, however, led to narrowing arbitrage between Europe and Asia. \"The arb is very narrow now to Asia,\" said David Lewis, LNG analyst at Commodity Insights. \"TTF has strengthened a lot recently and sellers are struggling to find buyers at elevated prices in Asia.\" The volatility in the market has dampened NWE liquidity in the prompt, thereby shifting the focus to the winter months. The Mediterranean region, however, is seeing some demand owing to the summer temperatures. The Platts-assessed West Mediterranean price was at a 5.5 cents\/MMBtu premium over NWE, while the East Mediterranean marker held a 25 cents\/MMBtu premium. Americas Despite the recent easing of restrictions at the Panama Canal, US LNG cargoes destined for Asia continue to choose the longest route through the Cape of Good Hope in July. 49 US LNG cargoes traveled to Asia via the Cape of God Hope in July, up from 37 in June, marking the highest number of monthly cargoes making the journey since Commodity Insights began recording the data in 2010. The US exported 44 cargoes this month so far as of Aug. 12, compared with the 41 in July over the same period, Commodity Insights data showed. The Platts Gulf Coast Marker for US FOB cargoes loading 30-60 days forward was assessed at $11.89\/MMBtu Aug. 9, up $1.07\/MMBtu on the week. Meanwhile, stronger economics in the Mediterranean was leading to several cargo diversions away from Latin America. Two LNG carriers originally expected to deliver cargoes to Argentina\u2019s Escobar terminal have been diverted to Spain. Platts last assessed DES Brazil for deliveries 15- to 45-day forward at $12.541\/MMBtu Aug. 9, or at a 15 cents discount to September NWE. LNG swaps Traders were eyeing the Asia-Europe competition for waterborne LNG cargoes in the near term and added that heightened bullish sentiment is keeping prices across the curve elevated from September 2024 to July 2025. Platts assessed the September DES Northwest Europe derivative at $12\/MMBtu Aug. 9, with October at $12.668\/MMBtu, November at $13.230\/MMBtu and December at $13.442\/MMBtu. Adding to the bullish expectations is the persistent net-long positions that hedge funds have taken in the European natural gas futures markets. Traders said the longer position could be attributed to continued delayed startups of new supply in 2025. However, the stronger price forecasts were being seen throughout the curve, sources said. Although the market remains inheritably bearish from the lull in European demand and healthy stocks, volatility is expected to persist in the next few months with the market eyeing expected maintenances and gas volumes through Ukraine . LNG bunkers Atlantic LNG prices made large gains in the week ended Aug. 9 on healthy demand and a bullish rally in the wider gas and LNG arena. Platts assessed LNG bunker fuel Rotterdam and Barcelona at $14.575\/MMBtu and $14.677\/MMBtu Aug. 9, respectively, both up $1.23\/MMBtu on the week. LNG bunker fuel is now at a 74.1 cents\/GJ premium to VLSFO. \"There are a lot of geopolitical things driving up LNG and at the same time crude has weakened,\" said an Atlantic-based LNG bunkers trader. The same source noted that, although he thinks the premium is temporary, dual-fueled vessels will now turn away from LNG until the price drops. Also big in the bunkers space was the A.P. Moller-Maersk acquisition of 60 new LNG capable vessels for a fleet renewal during the second half of the decade. Market participants said this will put pressure on supply capacity going forward in order to meet growing demand. Across the Atlantic, Platts assessed LNG bunker fuel on the US Southeast Coast at $12.961\/MMBtu, up 83.1 cents\/MMBtu on the week. ","headline":" Key market indicators for Aug 12-16","updatedDate":"2024-08-13T11:31:26.000"},{"Unnamed: 0":119,"body":" Refinery: Puertollano, Tarragona, A Coruna, Bilbao, Cartagena, Algeciras, Huelva, Castellon, Asesa (Tarragona) Overall capacity: 1.5 million b\/d (74.7 million metric tons\/year) Vacuum capacity: 34.3 MMt\/y FCC: 10.4 MMt\/y Hydrocracking: 7.8 MMt\/y Viscoreduction: 7.0 MMt\/y Mild hydrocracking: 6.8 MMt\/y Coking: 8.9 MMt\/y Notes: Spanish refinery throughput increased by 7% year on year to 16.3 million metric tons (1.32 million b\/d) in the second quarter of 2024, reserve corporation CORES said Aug. 13. The figure meant an operating rate of approximately 88% in the period, down from an average rate of 89% in Q1. Spain has nine operational refineries with 1.5 million b\/d capacity. The country\u2019s largest refiners, Repsol and Cepsa, reported Q2 throughput of 10.5 MMt and 5.3 MMt, respectively, while BP Espana (5.4 MMt\/y capacity) and Asesa (1.4 MMt\/y capacity) did not publish figures for their output. Repsol carried out maintenance works in the quarter at conversion units in Bilbao and Puertollano, while Cepsa carried out work on its FCC and other units at Algeciras, the companies said. Repsol\u2019s refining margin fell 2% year on year to $6.30\/b while Cepsa\u2019s firmed 6% year on year to $7.70\/b. BP and Asesa did not report a Spanish refining margin. Total refinery production in Spain in Q2 was 15.9 MMt, up 5% year on year, adjusted for refinery losses that increased more than fourfold year on year to 445,000 mt, CORES data showed. Production was slanted towards kerosene, whose output increased 14% year on year to 2.6 MMt in the quarter, amid a surge in tourist volume for the summer season. There was also a 40% annualized uptick in fuel oil production to 1.3 MMt as Repsol reported importing increased volumes of heavy crudes from Venezuela in the period. Among other products, naphtha production increased 12% year on year in Q2 to 452,000 t, while LPG production increased 2% to 252,000 t. The output mix from Spain\u2019s refineries in the period was approximately 40% diesel, 18% non-fuel products (comprising bitumen, asphalt, refinery gas, naphtha, petcoke), 16% kerosene, 16% gasoline, 8% fuel oil and 2% LPG. The country\u2019s blend of biofuels shrunk significantly in Q2, the data showed, with 2.7% blended into its gasoline mix in the period, down from 3.7% in Q2 2023. The blend of biofuels into diesel, similarly, was 6.1%, down from 9.0% in the year ago period. Export balance On balance, Spain\u2019s market was overall long on fuel products by 856,000 t in Q2, when considering domestic consumption, a decrease from a net long of 1.7 MMt in Q1. By product, gasoline was about 830,000 t long in Q2; kerosene, 660,000 t long; and other products, 1.7 MMt long. For LPG, Spain was 315,000 t short in Q2; for diesel it was 1.1 MMt short; and for fuel oil 920,000 t short. In terms of export balance, Spain retained its position as a net exporter of refined products, for an outgoing balance of 862,000 t in April-June, narrower than a 1.2 MMt export balance in January to March. France, Spain\u2019s neighbor, was the favored export destination, with 1.2 MMt delivered in Q2, including 852,000 t of diesel. It was followed by maritime neighbor Morocco, with 836,000 t delivered, including 548,000 t of diesel and 104,000 t of LPG. In terms of imports, Spain\u2019s largest refined product suppliers in Q2 were led by Italy with 792,000 t including 521,000 t of diesel and 235,000 t of fuel oil incoming, while the British Overseas Territory of Gibraltar exported 650,000 t to Spain in the period, up 75% year on year, including 378,000 t of fuel oil and 241,000 t of diesel. Spain\u2019s overall storage position was mixed compared to the start of the quarter. Crude stocks were 5.7 MMt at the end of June, up from 4.7 MMt at the end of March, but roughly flat year on year. But product stocks at end June, were down by 310,000 t over the quarter to 9.6 million t, with the level also roughly in line with June 2023. Source: CORES ","headline":" Spain Q2 throughput up 7% to 16.3 million mt","updatedDate":"2024-08-13T11:07:19.000"},{"Unnamed: 0":120,"body":" Voluntary carbon offset (VCO) prices should continue falling in the near term as supply of unretired credits remains strong, outpacing demand that has been impacted by public scrutiny and criticism, analysts at BofA Global Research said in a note dated Aug. 9 and made public on Aug. 12. \u201cThe already strong supply of unretired credits should grow as credits generated in previous years are continuously issued and new projects are commissioned. This supply is likely to continue to outpace demand, especially as compliance markets expand in the West, where the bulk of VCOs are retired,\u201d the analysts said. They noted that VCO prices have plummeted over the last three years, with global emission offset futures prices dropping 98% to $0.21\/tCO2e recently from a peak of $12\/tCO2e in November 2021. Nature-based avoidance offsets have fallen roughly 80% in the past two years, from $15\/tCO2e to just $3\/tCO2e; renewable energy VCOs have fallen to $1.5\/tCO2e; while tech-based carbon capture continues to hold the strongest with prices over $120\/tCO2e, BofA said. Offset issuances dramatically increased during the 2010s, growing from 40 million offsets in 2010, peaking in 2021 at around 300 million and then averaging 280 million offsets a year, the bank said. However, total issuance for the current year does not reflect the total VCO supply available for the current year, due to a roughly three year and three month gap between the vintage year and the date of issuance, BofA said. \u201cSo, a substantial number of 2021 and onward offsets could still be issued in the future, raising supply for those vintage years. Once issued, however, it takes about 1.5 years for the credits to be retired,\u201d the analysts said. Meanwhile, on the demand side, the scrutiny of projects has further weakened confidence in the market, monthly traded volumes have slowed in recent months and annual retirements have flattened after years of growth -- from 36% annual growth in 2010 to 2021, to single digits between 2021 to 2022. As a result, offset supply continues to outpace demand, and this imbalance has led to a cumulative surplus of nearly 900 million offsets since inception, that could meet over five years of demand, though many will likely never be purchased and retired due to concerns around vintage, additionality, and other factors, the bank said. \u201cOn the demand side the SEC's proposed climate disclosure rules could boost demand by obligating companies to disclose their emissions, though it is currently going through court challenges with their latest brief arguing for the requirement filed just this week,\u201d the analysts said. \u201cExcess supply of unretired VCOs is therefore likely to continue to expand, weakening prices going forward,\u201d BoFA said. The bank also said the majority of offset buyers are from the oil and gas industry. Over a third of retirements last year were by the energy industry according to publicly available transactions, and the oil and gas sector accounts for a majority at 32% of total VCO retirements last year where the data was publicly available, BoFA said. ","headline":"Voluntary carbon offset prices to continue falling until material change in market: BoFA","updatedDate":"2024-08-13T10:53:25.000"},{"Unnamed: 0":121,"body":" The International Energy Agency has lowered its estimate for global refinery runs in 2024 amid weaker margins, it said in its latest monthly report Aug. 13. It now expects throughput to be down 150,000 b\/d at 83.3 million b\/d this year as \"the collapse in profitability since the start of the year continues to weigh on refining activity.\" It has also trimmed its 2025 global refinery runs estimate by 180,000 b\/d to 83.9 million b\/d. \"Weaker margins and refinery profitability in both Asia and the Atlantic Basin are the main reasons for restrained activity,\" it said. Nonetheless, both 2024 and 2025 will see year-on-year growth in throughput. The recent start-up of new plants in the Middle East and Nigeria has \"bolstered\" the annual increase in the second half of 2024. Nigeria's Dangote has been ramping up runs and exports and is expected to start gasoline production, according to S&P Global Commodity Insights data. Meanwhile, the past few years have seen the launch of Duqm, Al-Zour and Jazan in the Middle East. Meanwhile, runs in the Atlantic Basin have been boosted in recent months by \"winding down of maintenance\", the International Energy Agency said. OECD runs are expected to \"reach a seasonal peak\" in August as maintenance in Japan and South Korea has been winding down while runs in OECD Europe have been \"seasonally stronger,\" the IEA said. Maintenance in Europe largely finished in June with refineries gearing for the next wave of maintenance in the autumn, according to Commodity Insights data. Non-OECD countries meanwhile \"remain the engine of growth for global refinery crude throughput\" although Chinese runs have contracted in the first half of the year. The IEA has subsequently revised down its Chinese forecast for both the second half of 2024 and for 2025. Leaders in the non-OECD growth are thus \"the Middle East, Other Asia and Africa.\" ","headline":"IEA lowers 2024 refinery runs estimate amid weaker margins","updatedDate":"2024-08-13T10:31:39.000"},{"Unnamed: 0":122,"body":" Refinery: Kashima, eastern Japan Owner: ENEOS Overall capacity: 210,100 b\/d Unit affected: Sole CDU Unit capacity: 175,000 b\/d Duration: Aug. 10; no restart date ENEOS, Japan's largest refiner, shut the sole 175,000 b\/d crude distillation unit at its 210,100 b\/d Kashima refinery on the east coast Aug. 10 for technical issues, a company spokesperson said Aug. 13. The refinery continues to ship oil products to both the rack and seaborne markets, although no date has been set for the restart of the CDU, the spokesperson added. The company had stopped operating the CDU for June 29-July 11 due to technical issues. The 35,100 b\/d condensate splitter at the refinery has been shut since June 2021 for operational adjustments. The Platts-assessed gasoline, kerosene and gasoil prices across the Chiba, Kanagawa, Chukyo and Hanshin regions averaged Yen 79,000\/kiloliter, Yen 79,000\/kl and Yen 77,600\/kl, respectively, on Aug. 13, S&P Global Commodity Insights data showed. Source: Company spokesperson ","headline":" Japan's ENEOS shuts Kashima CDU on glitches","updatedDate":"2024-08-13T10:09:10.000"},{"Unnamed: 0":123,"body":" ENEOS, Japan's largest refiner, restarted the 172,100 b\/d No. 2 crude distillation unit at its 249,100 b\/d Kawasaki refinery in Tokyo Bay Aug. 9 after planned maintenance, a company spokesperson said Aug. 13. The company has also shut the sole 136,000 b\/d CDU at its Oita refinery in the southwest since May 13 for scheduled maintenance, the spokesperson added. The Platts-assessed gasoline, kerosene and gasoil prices across the Chiba, Kanagawa, Chukyo and Hanshin regions averaged Yen 79,000\/kiloliter, Yen 79,000\/kl and Yen 77,600\/kl, respectively, on Aug. 13, according to S&P Global Commodity Insights data. ","headline":" Japan's ENEOS restarts Kawasaki No 2 CDU after planned maintenance","updatedDate":"2024-08-13T09:02:44.000"},{"Unnamed: 0":124,"body":" China\u2019s Haoye Petrochemical, which has been operating at a relatively low rate since the second quarter, further reduced its utilization rate in July to cut losses, according to the company. The refinery processed 227,000 mt of crudes in July, or 53,675 b\/d, which was around 42.6% below its refining capacity of 6.3 million mt\/year (126,000 b\/d), the company said on its official WeChat account. This will be about 3.5 percentage points lower from 46.13% in June, and much lower from an average rate of 51.4% in the first half of the year. In comparison, the refinery processed about 1.7 million mt of crudes in 2023 following maintenance in the first half of the year, translating to a utilization rate of around 27.6%, according to local energy information provider JLC. Haoye processed a total of 1.82 million mt of crudes in the first seven months of the year, with a profit tax of Yuan 930 million ($130 million) and a loss of Yuan 1.647 billion ($0.23 billion). In order to cut losses, the refinery has taken measures including adjusting its product slate by producing more aromatics, processing more heavy crudes and cutting the utilization rate since April 2024, according to the company. The refinery has been processing higher heavy crude volumes to cut refining costs. In June, it processed crudes with a gravity of about 26.34 API and 1.6% sulfur content, which was almost the upper processing limit for the refinery. Over the past few months, the refinery processed heavy Castilla crudes, making up about 20% of its crude slate, according to the company. Castilla is a Columbian blended heavy crude with 18.8 API and 1.97% sulfur content. Haoye typically processes crudes from the Middle East such as Oman, Upper Zakum and Murban, as well as some light crudes like Johan Sverdrup and Tupi, Commodity Insights data showed. The refinery made an average loss of around Yuan 313 million ($43.8 million) per month in Q1, and this was reduced to an average of around Yuan 137 million ($19 million) over April-July, down 43.4%, according to the company. At the same time, Haoye plans to further adjust its product portfolio by increasing the output of petrochemical products and lowering the output of oil products in coming months, which will help cut the tax burden. Haoye operated eight out of 28 units on Aug. 13, including a 4 million mt\/year asphalt production unit, a 1.4 million mt\/year of delayed coker, a 1.2 million mt\/year continuous reformer, a 1.6 million mt\/year hydrocracker and a 1.5 million mt\/year diesel unit, the refinery said on its website. Haoye is a provincial government-backed refinery in northeastern Liaoning province, which was restructured from an independent refinery. Shandong independent refinery run rates low China\u2019s independent refinery, on the other hand, was also maintaining at a low utilization rate in July due to weak refining margins, according to data from JLC. JLC data showed the average utilization rate at the independent refineries in China\u2019s eastern Shandong province in July was around 53%, compared with an average run rate of around 52.34% in June. Year on year, it was about 13 percentage points lower. At the same time, the refining margins for processing imported crudes, fell Yuan 98\/mt to Yuan 27\/mt in July, according to JLC data. Shandong\u2019s independent refineries are the swing players in China\u2019s refining sector as their activities directly reflect the country\u2019s oil demand. ","headline":" China's Panjin Haoye cuts run rate further in July","updatedDate":"2024-08-13T07:08:56.000"},{"Unnamed: 0":125,"body":" Crude oil futures were lower in midafternoon Asian trade Aug. 13 as volatility ensued ahead of the forthcoming US inflation data that could shake up forecasts of global monetary easing and crude demand. At 2:40 pm Singapore time (0640 GMT), the ICE October Brent futures contract was down 49 cents\/b (0.60%) from the previous close at $81.81\/b, while the NYMEX September light sweet crude contract fell 41 cents\/b (0.51%) at $79.65\/b. Global financial markets remained on edge ahead of a slate of US inflation prints which could drastically shift expectations of the Federal Reserve's rate cut cycle, analysts warned. The US Producer Price Index is due Aug. 13 while the US Consumer Price Index is expected Aug. 14. \"The speed with which financial markets moved to price-in 100 basis points of US rate cuts is inconsistent with the economic data released so far in August,\" ANZ Research analysts said Aug. 13. The recent uptick in unemployment and temporary layoffs has dampened the economic outlook for the US, which along with demand concerns in China, have put crude prices under pressure, they continued. Further dampening crude prices were expectations of a marginal uptick in US inventories in the week to Aug. 9. Commercial crude stocks likely rose 530,000 b\/d to around 429.8 million barrels over the period, analysts surveyed by S&P Global Commodity Insights said. Nevertheless, lingering geopolitical tensions across the Middle East and Ukraine continued to keep a floor on prices. \"Oil prices are making a modest comeback, hovering around $82\/b, not quite reaching their previous season highs of $86-$90\/b,\" said Stephen Innes, managing partner of SPI Asset Management. \"Volatility might come back this week, especially if inflation data skews too low -- amplifying recession worries -- or too high, stoking fears that the Fed won't be able to slash rates swiftly enough to shield the economy,\" he said. Given the geopolitical backdrop, retail traders appeared to hold a net-long position on US crude, Daily FX Analyst Richard Snow said. \"Our contrarian stance on crowd sentiment suggests further declines in US crude prices might occur. However, a decrease in net-long positions over the week, coupled with a significant increase in net-short positions, suggests a potential upward price reversal despite the prevailing net-long bias,\" Snow highlighted. Ahead in the global day, the International Energy Agency will release its oil market report which follows OPEC's report where it trimmed its global oil demand forecast by 140,000 b\/d. \"The release of IEA\u2019s monthly oil market report should provide some insight into demand amid concerns of weaker economic activity,\" ANZ Research analysts said. Dubai crude Dubai crude swaps and intermonth spreads were higher in midafternoon Asian trading Aug. 13 from the previous close. The October Dubai swap was pegged at $79.05\/b at 2 pm Singapore time (0600 GMT), up $1.16\/b (1.49%) from the previous Asian market close. The September-October Dubai swap intermonth spread was pegged at 73 cents\/b, up 6 cents\/b over the same period, and the October-November intermonth spread was pegged at 55 cents\/b, up 2 cents\/b. The October Brent-Dubai exchange of futures for swaps was pegged at $2.60\/b, up 35 cents\/b. ","headline":" Crude pares overnight gains ahead of US inflation data","updatedDate":"2024-08-13T06:41:38.000"},{"Unnamed: 0":126,"body":" Vietnam\u2019s crude oil exports grew over twofold on the month, and 4.25% on the year, to 53,591 b\/d in July, a rebound following three consecutive months of decline, latest customs data showed. Thailand, Japan, and Australia were the key destinations for Vietnamese crude in the month, with volumes to Thailand dipping 5.1% on the year to 24,968 b\/d, while exports to Japan grew twofold on the year to 19,290 b\/d. Volumes to Australia slid 47.2% on the month, but grew 6.4% on the year, to 9,333 b\/d, the data showed. The pick up in Vietnam\u2019s crude exports in July came as state-owned PV Oil issued a slew of spot tenders in the month. The company sold 300,000 barrels of Chim Sao crude for Sept. 1-5 loading to Australia\u2019s Ampol at a premium in the low-$7s\/b to the Platts Dated Brent crude assessments, FOB. The company also sold 300,000 barrels of SV-DN crude and 250,000 barrels of Thang Long crude to Hengyi and Taiyo Oil respectively, at premiums heard around the low $3s and low $5s\/b to Dated Brent, respectively, on FOB basis, S&P Global Commodity Insights reported previously, citing market sources. A portion of Vietnam's crude oil output goes to the Dung Quat refinery, with the remainder allocated for exports. In July, Vietnam was estimated to have produced 158,139 b\/d of crude oil in July, down 8.9% on the year, while its estimated production in the first seven months of the year was 164,395 b\/d, down 7.1% on the year, according to latest data from its General Statistics Office. From January to July, the country had exported 61,699 b\/d of crude oil, up 9.4% on the year, mainly to Thailand and Australia. More recently, PV Oil offered two 300,000-barrel cargoes of Chim Sao crude to load over Sept. 29-Oct . 3 and Oct. 22-26 via a spot tender that closes on Aug. 12, with validity until Aug. 15. The two cargoes offered are two separate lots and would be assessed separately. This came after the company issued a term tender which closed July 30, with validity until Aug. 9, offering a minimum of 6,700 b\/d of the grade in 200,000-barrel of Rang Dong crude for loading over Oct. 1, 2024-March 31, 2025. Results of the tender could not be ascertained at the time of writing. Market sources noted that cash differentials for October-loading Vietnamese crudes is expected to be similar-to-slightly-weaker, adding that the number of Vietnamese crude cargoes available in the spot market for October loading is expected to see little to no change from the previous trading cycle. The second-month gasoil and jet fuel swap crack spreads averaged $17.26\/b and $16.52\/b, respectively, as of the Aug. 12 Asian close, compared to the July monthly averages of $17.51\/b and $16.52\/b, respectively, Commodity Insights data showed Nigerian inflows returns Vietnam imported 290,279 b\/d of crude oil in July, up 14.9% on the year and 21% on the month, mostly from Kuwait. The volumes from Kuwait \u2013 meant for Vietnam\u2019s 200,000 b\/d Nghi Son refinery \u2013 grew 30.7% on the year and 29.2% on the month to 258,005 b\/d. State-owned PetroVietnam has a 25.1% stake in Nghi Son, along with Kuwait Petroleum International (35.1%), Japan's Idemitsu Kosan (35.1%) and Japan's Mitsui Chemicals (4.7%). The country also imported 32,274 b\/d from Nigeria for the first time in at least a year, after its 130,000 b\/d Dung Quat refinery first tested the Qua Iboe crude oil grade from Nigeria in early 2021, said the refinery\u2019s operator Binh Son Refining and Petrochemical. The refinery\u2019s most recent successful test of a new crude grade was conducted in May this year with the Bunga Orkid, which was produced in the PM3-CAA Block located in the overlapping area between Vietnam and Malaysia. The Nghi Son and Dung Quat refineries collectively meet about 70% of Vietnam's demand for oil products, while the remainder is sourced through imports. Vietnam had imported 276,607 b\/d of crude oil over January-July this year, up 15.3% on the year, mostly from Kuwait. Volumes from Kuwait stood at 244,189 b\/d, up 22.9% compared to the same period last year, the data showed. Vietnam's crude exports in July Jul 24 Jul 23 Change (Y\/Y) Jun 24 Change (M\/M) Thailand 24,968 26,313 -5.11% - - Japan 19,290 9,368 105.91% - - Australia 9,333 8,773 6.38% 17,681 -47.21% Total* 53,591 51,407 4.25% 24,111 122.27% Vietnam's crude exports over Jan-July Jan-Jul 24 Jan-Jul 23 Change (Y\/Y) Thailand 25,076 24,147 3.85% Australia 18,114 16,884 7.29% Japan 4,122 5,633 -26.82% Singapore 4,035 - - China 1,783 1,355 31.59% Total* 61,699 56,409 9.38% Vietnam's crude imports in July Jul 24 Jul 23 Change (Y\/Y) Jun 24 Change (M\/M) Kuwait 258,005 197,347 30.74% 199,730 29.18% Nigeria 32,274 - - - - Total* 290,279 252,661 14.89% 239,914 20.99% Vietnam's crude imports over Jan-July Jan-Jul 24 Jan-Jul 23 Change (Y\/Y) Kuwait 244,189 198,659 22.92% Nigeria 9,051 - - Brunei 2,823 - - Total* 276,607 239,861 15.32% Unit: b\/d, unless specified otherwise *Include other sources Source: Vietnam Customs ","headline":" July crude exports rebound amid slew of spot tenders, up over twofold on month","updatedDate":"2024-08-13T04:29:56.000"},{"Unnamed: 0":127,"body":" Vietnam imported 750,576 mt of oil products in July, down 17.17% year on year and 2.64% on the month, the most recent Vietnam Customs preliminary data showed. On a year-on-year basis, inflows of diesel and jet fuel contracted, while that of gasoline and fuel oil rose. Over January-July, Vietnam imported 6.19 million mt of oil products, edging 1.1% higher on the year, with the bulk of imports from South Korea at 1.93 million mt. This was followed by Malaysia and Singapore at 1.68 million mt and 1.48 million mt, respectively. Gasoil inflows posted the widest percentage decline among oil products in July at 329,204 mt (79,115 b\/d), down 36.19% on year. This brings total gasoil imports over January to July to 2.9 million mt, 12.98% lower than the same period last year. Trade sources attribute the decline in gasoil import volumes to ample domestic supply from the 130,000 b\/d Dung Quat refinery and 200,000 b\/d Nghi Son refinery. Both collectively meet about 70% of Vietnam's demand for oil products, while the remainder is sourced through imports. Meanwhile, Vietnam\u2019s imports of co-distillate jet fuel fell 19.27% on the year but was 1.73% higher on month at 157,665 mt in July. Over January-July, the southeast Asian nation imported 1.15 million mt of jet fuel, up 5.51% from the same year-ago period. Vietnam\u2019s jet fuel demand is expected to remain supported as the country targets to expand its airport system to 30 airports by 2030 from 22 airports and to 33 by 2050, local media reported. Construction on the Quang Tri airport project -- part of the country\u2019s plan to expand its airport system -- started July 6. Completion is expected by end-July 2026 with the airport estimated to accommodate around 5 million passengers and 25,500 mt\/year of cargo. On the gasoline front, imports climbed 25.69% on year and 28.31% on month to 213,487 mt, the Vietnam Customs data showed, bringing total inflows over the first seven months to 1.77 million mt, or 38.15% higher, on year. Moving forward, gasoline demand could be slightly weaker amid the monsoon season. \u201cDemand has slowed by roughly 10% due to the rainy season,\u201d a Vietnam-based trade source said, adding that demand should recover in Q4. Vietnam's fuel-oil imports in July dropped nearly 16% on the month to 50,294 mt, the Vietnam Customs data showed. The July inflows, however, more than doubled compared with the corresponding month a year ago, when Vietnam imported 25,096 mt of fuel oil, the data showed. The Southeast Asian country, which typically imports low sulfur fuel oil and gets some of its supplies from Singapore, has not imported any fuel oil from the city-state so far in August, according to latest Enterprise Singapore data. Singapore exported about 5,791 mt of fuel oil to Vietnam in the four weeks between July 4-31, the data showed. The wider Asian LSFO market remains partly under pressure due to adequate prompt supplies on the back of steady arbitrage inflows into the region, but traders said a recent upsurge in the downstream bunker market would likely cap any major downsides in the near term. Oil products exports decline Vietnam exported 164,146 mt of oil products in July, down 8.83% year on year, with Cambodia, South Korea and Singapore being the main destinations. The country shipped 1.41 million mt of oil products in the first seven months, up 8.96% year on year, mainly to Cambodia, South Korea, Singapore and China. In July, Vietnam was estimated to have produced 1.58 million mt of oil products, up 17.1% year on year. The country\u2019s estimated production of oil products in the first seven months was at 10.33 million mt, rising 10.3% year on year, data from the General Statistics Office showed July 28. LPG inflows fall on year Vietnam imported 292,345 mt of LPG in July, down 15.35% on year, with UAE, Saudi Arabia and China being the key suppliers, according to Vietnam Customs data. The country imported 1.85 million mt of LPG over January-July, up nearly 24% year on year, with Qatar, Malaysia, the UAE and Saudi Arabia being the main sellers. Vietnam has four major LPG producers: the 130,000 b\/d Dung Quat refinery, Dinh Co gas processing plant in the southern province of Ba Ria-Vung Tau, Ca Mau gas processing plant in the southern province of Ca Mau, and the 200,000 b\/d Nghi Son refinery. The country\u2019s LPG market is dominated by state-controlled PV Gas, which currently has around 70% of market share. Vietnam\u2019s estimated production of LPG declined by 6.9% to 71,000 mt in July. The country\u2019s estimated LPG output in the first seven months was at 435,700 mt, 16.9% lower year on year, according to the General Statistics Office. Vietnam's oil products imports by countries Jul 24 Jul 23 Change (Y\/Y) Jun 24 Change (M\/M) Singapore 224,662 190,177 18.13% 153,923 45.96% South Korea 199,640 385,372 -48.20% 317,538 -37.13% Malaysia 116,441 147,309 -20.95% 146,921 -20.75% Thailand 88,719 108,682 -18.37% 54,817 61.85% China 86,601 73,959 17.09% 61,196 41.51% Total 750,576 906,167 -17.17% 770,945 -2.64% Jan-Jul 24 Jan-Jul 23 Change (Y\/Y) South Korea 1,926,556 2,456,659 -21.58% Malaysia 1,684,103 1,032,231 63.15% Singapore 1,483,281 1,554,104 -4.56% China 659,904 521,579 26.52% Thailand 269,743 517,617 -47.89% Total 6,190,397 6,122,901 1.10% Vietnam's imports by products Product name Jul 24 Jul 23 Change (Y\/Y) Jun 24 Change (M\/M) Gasoline 213,487 169,849 25.69% 166,390 28.31% Diesel 329,204 515,929 -36.19% 390,242 -15.64% Fuel oil 50,294 25,096 100.41% 59,713 -15.77% Jet fuel 157,665 195,290 -19.27% 154,985 1.73% Product name Jan-Jul 24 Jan-Jul 23 Change (Y\/Y) Gasoline 1,765,997 1,278,312 38.15% Diesel 2,903,917 3,337,153 -12.98% Fuel oil 341,848 402,591 -15.09% Jet fuel 1,150,749 1,090,651 5.51% Vietnam's oil products exports by countries Jul 24 Jul 23 Change (Y\/Y) Jun 24 Change (M\/M) Cambodia 30,141 42,742 -29.48% 25,505 18.18% South Korea 21,166 16,454 28.64% 27,301 -22.47% Singapore 14,206 24,911 -42.97% 45,404 -68.71% China 9,804 14,167 -30.80% 21,174 -53.70% Malaysia 5,446 1,051 418.17% - - Laos 1,917 6,239 -69.27% 2,505 -23.47% Indonesia 1,528 - - - - Hong Kong 1,308 - - - - Total 164,146 180,053 -8.83% 123,361 33.06% Jan-Jul 24 Jan-Jul 23 Change (Y\/Y) Cambodia 253,044 360,015 -29.71% South Korea 154,155 113,520 35.80% Singapore 139,519 138,933 0.42% China 126,892 99,394 27.67% Laos 53,145 42,743 24.34% Malaysia 33,684 27,355 23.14% Thailand 6,741 2,163 211.65% Indonesia 2,166 - - Hong Kong 1,406 881 59.59% Total 1,413,835 1,297,589 8.96% Vietnam's LPG imports by countries Jul 24 Jul 23 Change (Y\/Y) Jun 24 Change (M\/M) UAE 85,111 57,067 49.14% 67,679 25.76% Saudi Arabia 45,647 125,310 -63.57% - - China 34,153 24,850 37.44% 22,307 53.10% Malaysia 12,810 10,251 24.96% 19,455 -34.16% South Korea 2,151 - - - - Qatar 1,950 - - 44,200 -95.59% Thailand 1,701 5,187 -67.21% - - Total 292,345 345,365 -15.35% 292,836 -0.17% Jan-Jul 24 Jan-Jul 23 Change (Y\/Y) Qatar 323,854 91,845 252.61% Malaysia 254,493 68,924 269.24% UAE 241,635 306,883 -21.26% Saudi Arabia 233,102 480,579 -51.50% China 168,409 175,102 -3.82% Kuwait 113,039 94,608 19.48% Australia 59,862 - - Indonesia 58,700 78,392 -25.12% Nigeria 41,018 - - Thailand 22,565 20,807 8.45% South Korea 2,680 1,024 161.72% Total 1,854,128 1,495,407 23.99% Unit: mt *Total include other sources Source: Vietnam Customs ","headline":" July refined products imports fall 17% on year to 750,576 mt","updatedDate":"2024-08-12T23:31:47.000"},{"Unnamed: 0":128,"body":" Bolivian President Luis Arce named as the new minister of hydrocarbons and energy Aug. 12 Alejandro Gallardo, who vowed to support an increase in oil and natural gas production to reduce imports following severe diesel shortages. \u201cIt is always good to have a change to renew energies, ideas, commitments and the work that will be essential to bring success to the Bolivian people,\u201d Arce said in a televised address at the government\u2019s headquarters in La Paz. A former general manager of the EBIH, a state company that makes polyethylene pipes and other products for the industrialization of oil and gas, Gallardo replaced Franklin Molina, who was fired in a cabinet reshuffle after nearly four years at the helm. Gallardo said he will focus on rebuilding oil and gas production, with a focus on technology and international relations. \u201cWe are facing the challenge of reducing our dependence on imported fuels,\u201d he said at the swearing-in ceremony. The change came after Bolivia suffered diesel shortages in late July and early August largely because of disruptions in the supply chain. High surf stalled the unloading of four ships with a total of 160 million liters of diesel at the Port of Arica in Chile, while low water levels on rivers stalled deliveries from neighboring countries. This pushed YPFB, Bolivia\u2019s state oil company, to scramble to import supplies by truck from the neighboring countries of Argentina, Brazil, Paraguay and Peru, but it was not enough to prevent long lines forming at service stations. While it was largely a logistical snag, the shortages unmasked the deeper challenge of how to turn around a decade-long decline in oil and gas production. Indeed, oil output tumbled 59% to 21,000 b\/d in April from a peak of 51,100 b\/d in 2014, while gas output shrank 44% to 33.8 million cu m\/d from a record 60.8 million cu m\/d over the same period, according to data from the state statistics institute INE. YPFB has been stepping up exploration since 2022 in response, with the first large find made last month in Mayaya Centro-X1, a well in an undeveloped basin to the north of La Paz that has 1.7 Tcf of potential reserves. ","headline":"Bolivia\u2019s new energy minister vows to rebuild oil, gas production to reduce imports","updatedDate":"2024-08-12T21:48:55.000"},{"Unnamed: 0":129,"body":" US crude inventories could see a marginal increase in volumes for the week ended Aug. 9, analysts surveyed by S&P Global Commodity Insights said Aug. 12, as refinery runs are expected to recover once several facilities exit maintenance and production is anticipated to remain at a record high of 13.4 million b\/d. Commercial crude stocks likely rose 530,000 b\/d to around 429.8 million barrels in the week to Aug. 9, analysts said. The incremental rise could mark the end of consecutive inventory draws seen for the last six weeks, driven by a slowdown in refinery runs and utilization. At this level, stocks are 4.7% below the five-year average. Still, the recent downturn in inventories does not compare to the significant losses seen earlier in the year when inventories were over 5% below the five-year average at a low of 420.7 million b\/d Jan. 19. Refinery utilization is expected to remain unchanged at 90.5%, analysts said. Runs are expected to increase to 16.52 million b\/d as refineries continue to ramp up, according to Commodity Insights analysts. This would put inputs 1.8% behind the five-year average of EIA data. Following a string of restarts seen at Marathon's Galveston Bay, Cenovus' Lima and Valero's Port Arthur refineries, ExxonMobil was the latest to bring operations back online at its Chicago-based Joliet refinery . The company confirmed Aug. 12 the safe restart of its refinery after the plant was abruptly shut down July 15 after a tornado destroyed local power infrastructure. Crude production is expected to remain at 13.4 million b\/d following last week's 100 million b\/d increase. The total domestic number of frac crew units over the period to Aug. 2 increased by six to 243 units, while the rig count also increased by three to 636 rigs. Exports are expected to extend their recent draws, with Commodity Insights analysts anticipating a 3 million b\/d decline for the week to Aug. 9. \"After strong lifting activity post-Hurricane Beryl and towards the end of July, export activity materially deteriorated as we entered the month of August,\" they said in a report from Aug. 7. \"Flows to Asia are particularly weak as US August loaders arrive in September\/October -- the heart of turnaround season.\" For the week to Aug. 11, exports to Asia were reported at 1.1 million b\/d compared to peak shipments seen the week to July 28 when exports were at 2.6 million b\/d according to S&P Global Commodities at Sea data collected Aug. 12. Total gasoline inventories likely declined 1.9 million barrels to around 223.1 million barrels, analysts said. Distillate inventories were expected to fall 750,000 barrels to 127 million barrels. ","headline":"US crude inventories to see small uptick on ramp-up of refinery operations","updatedDate":"2024-08-12T20:37:43.000"},{"Unnamed: 0":130,"body":" Canada\u2019s Gran Tierra Energy has drilled the third successful oil well of 2024 in the Ecuadorian Amazon, its fifth oil discovery in the country since 2022, the company said Aug. 12. Drilling was completed at the Charapa B-6 well down to 11,170 feet at the Charapa Block in Ecuador\u2019s Oriente Basin, which tested for 2,118 b\/d of 28.2 API crude, Calgary-based Gran Tierra said in a statement. The company, which earlier this year drilled the Arawana-J1 and Bocachico Norte-J1 wells in Ecuador, added it moved its drilling rig and started drilling the nearby Charapa B-7 well last week. The company aims to drill as many as nine exploration wells this year in Ecuador and Colombia in addition to processing 238 km2 of 3-D seismic data for the Charapa Block, part of 2024 capex of $210 million-$240 million. Gran Tierra is on track to meet 2024 production guidance of 32,000-35,000 b\/d, CEO Gary Guidry said Aug. 1. Ecuador, whose investor-friendly President Daniel Noboa is due to step down next year following general elections in May, has sought to attract more foreign investment in the oil and gas industry, awarding several blocks in the Intracampos II bid round this year. ","headline":"Canada\u2019s Gran Tierra Energy drills third oilwell in Ecuador's Oriente Basin","updatedDate":"2024-08-12T20:31:51.000"},{"Unnamed: 0":131,"body":" The United States Department of Energy is expanding a previously announced solicitation to purchase crude oil for the Strategic Petroleum Reserve, adding 4 million barrels to its latest order for delivery at the start of 2025. The DOE's Office of Petroleum Reserves announced its intention on Aug. 6 to purchase 1.5 million barrels of oil for delivery to the Bayou Choctaw SPR site for January 2025. In that release, DOE revealed another solicitation scheduled Aug. 12 to purchase 2 million barrels for delivery to the Bryan Mound site in January 2025 -- the first refill at the recently renovated and reopened location. A DOE spokesperson updated that guidance on Aug. 12, saying the agency would expand the Bryan Mound solicitation to 6 million barrels to be delivered in January, February and March 2025. \"The Biden-Harris Administration is opening up more capacity for potential return in 2025 as market conditions have shifted in favor of the taxpayer,\" the spokesperson said. The new solicitations will add to the more than 43 million barrels that DOE has purchased in 2023 and 2024 to replenish the federal government's emergency oil stockpile. President Joe Biden released more than 180 million barrels from the SPR in 2022 in the wake of Russia's invasion of Ukraine, for $95\/b. The Biden administration has touted the relatively discounted purchase ceiling as a \"good deal\" for the taxpayer. The Biden administration\u2019s three-part SPR replenishment strategy has centered on \u201cdirect purchases with revenues from emergency sales, exchange returns that include a premium of oil above the volume delivered, and securing legislative solutions that avoid unnecessary sales unrelated to supply disruptions,\u201d the DOE said. As of Aug. 2, the SPR held 375 million barrels, down from the 638 million it held in January 2021, when Biden took office. Alongside cancellations of 140 million barrels of congressionally mandated sales from 2024 to 2027, the agency has now accounted for all of the crude it sold in 2022. Market analysts have suggested the Biden administration may be reaching the end of its ability to purchase oil. In an August research note, ClearView Partners estimated that $1.38 billion remains in the DOE's SPR budget, and that if monthly purchases at regular prices of an average of 3.5 million barrels per month continue, the SPR account would be depleted in roughly four months. \u201cWe do not think the current Congress is likely to provide additional appropriations for SPR procurement,\u201d ClearView said. ","headline":"US Department of Energy adds 4 million barrels to latest SPR solicitation","updatedDate":"2024-08-12T19:16:49.000"},{"Unnamed: 0":132,"body":" Mounting strain in the relationship between Israel and Iran has failed to lift tanker freight rates, as key buyers look to preserve calm markets and remain focused on bearish demand sentiment. There were fears that the assassination of Ismail Haniyeh, a top Hamas leader, in Iran, and of Fuad Shukr, a senior Hezbollah commander, in Lebanon, would portend a fresh escalation in geopolitical tensions in the Middle East and cause commodity prices to snap higher. However, oil markets have proved surprisingly stable as ships continue to avoid the Red Sea and traders have proved increasingly less reactive to brinkmanship from both sides of the conflict. Crude has shrugged off significant increases, rising only a few cents from $81.45\/b July 31, when Hezbollah confirmed the death of Shukr, to $81.61\/b Aug. 9. Shipping has shown a similarly muted response as bearish sentiment has prevailed across both dirty and clean markets and war risk premiums have stayed rangebound. Platts assessed the rate to carry a 75,000 mt cargo of refined products from the Persian Gulf to UK-Continent at $53\/mt Aug. 8, broadly stable with $53.33\/mt on July 31. Platts is part of S&P Global Commodity Insights. Flows from the Middle East to Europe have been dampened by anemic demand for products in Europe and little expected change in trade routes for mainstream shippers already mostly travelling around the Cape of Good Hope to avoid the Red Sea, shipping market sources said. For crude carriers, Platts assessed the rate to carry a 140,000 mt cargo from the Persian Gulf to UKC at $54.75\/mt Aug. 8, up a touch from $50.50\/mt July 31. The dirty tanker market is in its typical summer lull and this has limited upside in the market, trade sources said. Trade flow resilience While markets remain watchful for sign of an Iranian retaliation, traders have become increasingly reluctant to price in higher risk premiums as supply chains have adapted. Around 60% of tankers bound from Europe from East of Suez in the second half of July have opted to sail the longer Cape of Good Hope route to avoid the Red Sea, reflecting limited volatility since tanker operators began reassessing voyages earlier this year, according to S&P Global Commodities at Sea data. For Europe, record volumes of US diesel imports have also helped to minimize exposure to Middle Eastern flows, while a broader bearish sentiment on oil-products demand had limited upside sensitivity to the latest signs of escalation. Rebeka Foley, an oil analyst at S&P Global, noted easing gasoline and diesel cracks as tensions have mounted as a vote of confidence around product availability in the coming months. \"Ongoing ICE gasoil backwardation is implying that low stock levels are adequate to cover prompt demand. We also have high runs\/low outages in the US and Europe, meaning that gasoline cracks should come off end-August,\" she said. Geopolitical interests Benjamin Hoff, head of commodity research at Societe Generale, agreed that confidence in newly established trade flows has diluted upside risk in the downstream market. \u201cThe market took Houthi rhetoric following the assassination of Hamas leader Haniyeh in its stride,\" he said Aug. 12, noting a counter-intuitive increase in short positions on ICE gasoil futures after the July 31 assassination. Arne Lohmann Rasmussen, chief analyst at Global Risk Management, said that widely anticipated retaliatory measures can now even trigger an oil market selloff once they materialize, by briefly dissipating expectations of an imminent attack. Meanwhile, after months of tit-for-tat attacks and fraught relations within the region without significant disruption to energy infrastructure, several analysts have underscored mutual interests in keeping oil flowing. \"Iran would have little to no strategic gain by purposefully attacking oil infrastructure in the region. That is not to say it won\u2019t happen, perhaps by accident or on purpose. But such attacks would spur responses against Iran. And China, an Iranian ally of sorts, would not like to see higher oil prices or supply threatened,\" said Jim Burkhard, Commodity Insights\u2019 vice president of oil markets, energy and mobility. \"Causing damage to regional oil supply would not win Iran any friends or support apart from its proxies and like-minded actors. But in times of war, economic logic and long-term repercussions are often set aside,\" he said. ","headline":"Tanker markets shrug off escalating Middle East tensions","updatedDate":"2024-08-12T18:48:59.000"},{"Unnamed: 0":133,"body":" September\u2019s loadings of Kazakh CPC Blend have been provisionally set at around 1.165 million b\/d, up from August\u2019s 1.05 million b\/d, according to loading information compiled by traders. The Caspian Pipeline Consortium stopped releasing full loading schedules early January 2023, instead choosing to communicate load dates to individual lifters directly. As information around loading dates has spread through the market, traders have been able to piece together export volumes. Traders previously told S&P Global Commodity Insights that August program was shorter due to planned maintenance at the Tengiz field. The September provisional loading program is around 125,000 b\/d lower year-on-year, according to data from Platts, part of S&P Global Commodity Insights. Platts last assessed CPC Blend at a $1.77\/b discount to Dated Brent Aug. 8, the steepest discount to the benchmark since July 9. However, sentiment appears to be tentatively more bullish for September-loading CPC Blend cargoes. Throughout the day Aug. 12, September stems of CPC Blend were heard traded around a $1\/b discount to Dated Brent. ","headline":"Kazakh CPC Blend September loadings are provisionally around 1.165 million b\/d: traders","updatedDate":"2024-08-12T17:20:56.000"},{"Unnamed: 0":134,"body":" Saudi Aramco lowered the official September selling prices for crudes loaded from the Egyptian port of Sidi Kerir, with all four grades set at a 15 cents\/b premium to the prices of the same grades loaded from Saudi Arabia and bound for the Mediterranean, a source close to the matter said Aug. 12. Aramco set the OSP for the flagship Arab Light crude loaded from the Mediterranean port in September at a premium of $1.30\/b to ICE Brent, $2.65\/b lower on the month. That is 15 cents\/b above the OSP, announced separately, for cargoes of the grade bound for the Mediterranean and loaded from the ports of Ras Tanura and Yanbu in Saudi Arabia. The Sidi Kerir August OSPs for Arab Extra Light and Arab Medium crudes are set at a premium of $3\/b and 70 cents\/b to ICE Brent, respectively, while Arab Heavy crude has been priced at a $2\/b discount to ICE Brent. These prices are all $2.65\/b below the August OSPs and 15 cents\/b above the equivalent Med OSPs for September. These price decreases come amid a weaker backdrop for both sweet and sour crude markets in Europe. The Mediterranean sweet crude complex has seen differentials retreat recently amid a softer demand ahead of a heavy European refinery maintenance season in September, traders said. A similar weakness has been seen in European sour crude grades such as Johan Sverdrup and KEBCO. Iraq's SOMO announced decreases for its official selling prices (OSPs) for September-loading sour crude oil bound for Europe, according to a pricing notice seen by S&P Global Commodity Insights Aug. 7. ","headline":"Saudi Aramco September Sidi Kerir OSPs set at 15 cents\/b premium to Mediterranean prices","updatedDate":"2024-08-12T17:07:49.000"},{"Unnamed: 0":135,"body":" Royal Caribbean\u2019s newest cruise ship, Utopia of the Seas, completed its maiden voyage bunkered with bio-LNG, according to an Aug. 9 LinkedIn post by Nordic energy company Gasum, which supplied the fuel for the journey. The Miami-headquartered cruise line's Oasis class cruise ship was the first in its class to be powered by LNG as it made the journey from Saint-Nazaire, France, in late June to its home base at Port Canaveral in Florida, arriving July 11, according to data from S&P Global Commodities at Sea . Bio-LNG, also known as liquefied bio-methane, is chemically identical to LNG but is derived from renewable sources such as organic waste or biomass. LNG-powered ships are able to operate on only bio-LNG or use a mixture of both. Traders have seen increasing demand in the European bio-LNG market. \u201cBio-LNG is really sparking the interest of our clients,\u201d one Atlantic-based LNG bunker supplier said. Bio-LNG with 89% greenhouse gas savings can trade around Eur70\/MWh, while GHG savings of around 200% can trade at upwards of Eur200\/MWh. This is around $22.188\/MMBtu for bio-LNG with 89% GHG, or around $63.393\/MMBtu for 200% savings. In comparison, Platts, part of S&P Global Commodity Insights, last assessed the DES Northwest Europe price for September at $12.691\/MMBtu on Aug. 9. Gasum also said it can \u201cproduce biomethane at our own 17 biogas plants and supply bio-LNG to our maritime customers on a mass balance basis.\u201d The company also expects to begin distributing synthetic e-methane from 2026. ","headline":"Royal Caribbean's Utopia of the Seas completes maiden voyage bunkered with bio-LNG","updatedDate":"2024-08-12T15:32:29.000"},{"Unnamed: 0":136,"body":" Derivatives ** Speculative net long positions on the ICE low sulfur gasoil futures contract fell 17,251 to minus 2,697 in the week to Aug. 6, according to ICE data. ** Managed money long positions fell 4,900 contracts to 62,179, while short positions rose 12,351 contracts to 64,876. ** Open interest rose 7,922 to 919,249 contracts, the ICE data showed. ** The front-month July LSGO futures contract rose $6.50\/mt in the week to Aug. 9, with Platts, part of S&P Global Commodity Insights, assessing it at $719.50\/mt, while the prompt intermonth spread fell 50 cents\/mt to minus $3\/mt. Diesel ** The European diesel market continued its downtrend in the week to Aug. 9, weakening the entire complex amid strong imports. ** The CIF Mediterranean ULSD cargo differential fell $2.75\/mt over the week to be assessed at $6\/mt, while its Northwest European counterpart was down $2.50\/mt at $7.75\/mt, according to the Platts assessments from Commodity Insights. ** Europe is currently scheduled to receive 1.885 MMt of diesel and gasoil import volumes from the US, according to S&P Global Commodities at Sea data Aug. 9. If all volumes land, this would be a record-high volume. ** Strong imports are expected from the Middle East as well, with spike in fixing activity being partly owed to a pivot to larger crude oil tankers to transport diesel to economize logistics costs around the Cape of Good Hope, which has increased import volatility week to week. Jet fuel ** European jet fuel differentials were rangebound in the seven days to Aug. 9 as strong seasonal aviation demand was matched with strong inflows from the East of Suez. ** The market is balanced, with the strong supply being absorbed by healthy demand, according to sources. Further tightening of the complex this year will depend on refinery run cuts in coming months, they added. ** Imports of jet fuel from East of Suez into Europe are set to remain heavy at 1.7 MMt in August, for the fourth straight month, according to CAS shipping data retrieved Aug. 11. ** Jet fuel and kerosene inventories in the Amsterdam-Rotterdam-Antwerp refining hub fell 45,000 t to 882,000 t in the seven days to Aug. 8, 23.87% higher than the same year-ago week, data from market research company Insights Global showed. Gasoil ** Mediterranean gasoil cargoes pushed up throughout the week, strengthening to a two-month high amid strong bidding activity during the Platts Market on Close assessment process. ** The NWE gasoil barge market continued to move sideways at the beginning of the week, holding steady at the end of the week, as diesel and gasoil stocks in ARA rose 2.9% to 2.071 MMt in the week to Aug. 8, according to data from Insights Global. ** The increase places stocks up less than a percentage point on the year, with levels still seen as low following several consecutive weeks of draws. ** Platts assessed the CIF Mediterranean 0.1%S gasoil cargo balance-of-month differential swap up $6\/mt on the week to minus $5\/mt, Commodity Insights data showed. ","headline":" Key market indicators for Aug 12-16","updatedDate":"2024-08-12T14:59:37.000"},{"Unnamed: 0":137,"body":" ADNOC Gas\u2019s recently signed preliminary LNG offtake agreements for its Ruwais LNG project, with Shell, Mitsui and Osaka Gas, are currently being negotiated at a price of around 12.6% slope to crude oil, sources told S&P Global Commodity Insights. These heads of agreements are yet to be converted to formal sales and purchase agreements or SPAs and the price slopes could change by the time the final deals are inked. The 12.6% slope level in particular is notable and it has emerged in a hotly contested market where buyers have been calling for lower prices, anticipating more LNG supply coming online, while suppliers have been rushing to close deals early to secure financing and get projects off the ground. Market participants said the 12.6% oil slope speared to be slightly higher than current levels where buyers have been bidding in the range of early to mid 12%. This is likely because the ADNOC deals were concluded at least six months ago and only announced in July and August, and hence reflected the pricing environment from earlier this year. Market sources also said that the pricing slope accounts for optionality in the LNG agreement in favor of buyers that added a price premium, for a range of terms and conditions that cover cargo quantity, quality specifications, delivery window and delivery locations. Such optionality can be hard to quantify in dollar terms but can be valuable if buyers or sellers have existing positions and assets that can be monetized, such as access to LNG ships in winter. When ADNOC signed a long-term heads of agreement with Japanese utility Osaka Gas on Aug. 6, the Japanese utility described the deal as a result of the company's overall consideration of \"favorable contractual terms and conditions\" being offered, noting the need for LNG as a key transition fuel for achieving carbon neutrality. Under the agreement, LNG cargoes will be shipped to the destination ports of Osaka Gas and its Singapore-based subsidiary, Osaka Gas Energy Supply and Trading (OGEST). In recent weeks, ADNOC also announced equity partnerships with Shell, Mitsui, TotalEnergies and BP with the partners being awarded 10% equity each and ADNOC retaining 60% equity in the Ruwais LNG project. As part of the announcement, ADNOC said it signed preliminary long-term LNG deals of 1 million metric tons per year with Shell and 600,000 t\/y with Mitsui and Co. Market sources said these ADNOC deals with Shell and Mitsui were also being negotiated at a slope of 12.6% of crude oil on DES basis. Shell and Osaka Gas did not respond to a request for a comment. ADNOC and Mitsui declined to the comment. Driving prices lower The 12.6% slope level is also lower than the roughly 12.8% slope discussed for ADNOC\u2019s two previous 15-year LNG HoAs for offtake from Ruwais, one signed with German utility EnBW for 600,000 t\/y sourced mainly from Ruwais announced in May 8, and one with Germany's state-owned SEFE for 1 MMt\/y announced in March 18. ADNOC\u2019s Ruwais LNG project has two trains of 4.8 MMt\/y which will take its LNG production capacity to 15 MMt\/y when they come online. ADNOC has also signed a non-binding HoA with China\u2019s ENN for 1 MMt\/y for 15 years. In the announcements for offtake agreements with Shell, Mitsui and Osaka Gas, ADNOC said that its sale commitments have risen to 70% of the project\u2019s production capacity. So far, ADNOC has already announced agreements for a combined 5 MMt\/y. A 70% sales commitment from the 9.6 MMt\/y Ruwais project would imply that another 1.72 MMt\/y of long-term LNG agreements are yet to be announced. ADNOC would likely be keen to convert these HoAs into SPAs before further declines in the long-term contracting market, which could make current price slopes tougher to finalize. Market participants are anticipating additional LNG supply to be online from 2026 from Qatar and North America which could potentially lead to change in expectations for the LNG spot market in terms of prices and supply being available. Platts, part of S&P Global Commodity Insights, assessed JKM for September at $14.19\/MMBtu on Aug. 12. ","headline":"ADNOC\u2019s LNG offtake agreements being discussed at around 12.6% oil slope: sources","updatedDate":"2024-08-12T12:54:28.000"},{"Unnamed: 0":138,"body":" India's Oil and Natural Gas Corporation has signed its first couple of master sales and purchase agreements with Middle East based Emirates National Oil Company and trading house Gunvor, the state-owned oil and gas explorer and producer said late Aug. 9 on social media platform X. \u201cThis venture complements ONGC\u2019s leading role as a top domestic natural gas supplier, positioning ONGC as a future leader in RLNG,\u201d it said. A master sales and purchase agreement essentially notes the standard terms for sale and purchase of an LNG cargo. The development is significant as it marks ONGC\u2019s intent to enter the LNG market as a direct importer. It also signals the intent of ONGC to market not just domestically produced natural gas but also regasified LNG from imports. A source familiar with the development said that in the next four to five months, ONGC could sign up to 12 MSPAs and begin sourcing LNG on its own through tenders possibly by the end of 2024. Currently, Petronet issues tenders for procuring LNG cargoes for ONGC for delivery to the Dahej terminal. ONGC is a joint venture partner in Petronet and holds 12.5% equity in Petronet, according to the Petronet website. ONGC also receives volumes from the long-term contract between Qatar Energy and Petronet. ONGC\u2019s subsidiary company ONGC Petro additions Limited is a key consumer of natural gas, consuming around 1.4 million cu m\/day on average, according to trade sources. Besides holding regasification capacity at Dahej, ONGC plans to hold regasification capacity in the upcoming Chhara terminal, the source familiar with the development said. ONGC said it expects to increase its natural gas marketing operations. Currently, ONGC is the largest domestic gas producer producing 20 billion cu m in April 2023-March 2024. ","headline":"India\u2019s ONGC signs LNG MSPAs with ENOC, Gunvor","updatedDate":"2024-08-12T12:41:46.000"},{"Unnamed: 0":139,"body":" Cargoes carrying high sulfur fuel oil from the Americas into Europe are set to relieve some relatively prompt tightness in the week of Aug. 12-16, with pull from the Middle Eastern power market weighing on HSFO in Europe, sources said. HSFO ** The European high sulfur fuel oil market is balanced, with the Latin American arbitrage status being deemed closed, traders said. This comes after HSFO cargoes are due to arrive in Northwest Europe and the Mediterranean from the Caribbean, Mexico and the US Gulf Coast in the first half of August. ** In the Mediterranean, heightened geopolitical tensions in the Middle East have been hindering bunkering demand with ships avoiding transit via the Red Sea. Coupled with a slight tightness in supply due to Saudi Aramco and Egypt having contracts with refineries in the region, sources expect the Mediterranean market to be fairly balanced. ** The bitumen demand season is winding down toward the end of the European summer, sources said. In the peak summer months in Europe, refineries often switch from producing HSFO to maximizing bitumen yields as the warm weather is ideal for road construction. LSFO ** The European 1%S fuel oil complex remains strong amid prompt demand within the Mediterranean as utilities continue to stock up on LSFO amid peak temperatures during summer. Within Northwest Europe, LSFO cargoes remain in good supply, traders said. ** In the 0.5%S fuel oil market, a strong and open Europe-to-Asia VLSFO arbitrage has boosted demand within Europe while bunkering activity remains stable. ** The front-month paper fuel oil hi-lo ended the week to Aug. 9 at $26\/mt, having widened by $3.75\/mt, while the front-month paper Hi-5 widened by $2\/mt to $88\/mt. Bunkers ** The retail bunker fuel market was slow in the week to Aug. 9, both in Northwest Europe and the Mediterranean. This was attributed to the peak summer season, which meant that demand levels were subdued. ** In the Mediterranean, 380 CST HSFO became available from Lisbon, Sines and Setubal, and traders will be monitoring whether this could be set to change going forward. Meanwhile in Piraeus, low levels of activity were reported, but a market source said that from the middle of August onward, new deliveries were set to occur. ** Prices in Northwest Europe had reached relatively low levels in the previous trading week, but improved Aug. 9 at the port of Rotterdam. Traders will be examining price developments in the Amsterdam-Rotterdam-Antwerp hub. Feedstocks ** Participants continued to cite a quiet market for low sulfur straight-run fuel oil within Europe, while the vacuum gasoil market has been slightly more active. ** Barges were trading at a slightly higher premium to cargoes within the VGO market. Stagnant end-product crack spreads continued to act as a headwind for the overall European feedstocks complex, traders said. ","headline":" Key market indicators for Aug 12-16","updatedDate":"2024-08-12T12:20:31.000"},{"Unnamed: 0":140,"body":" There has been an oil leak at a refinery in Nieuwdorp, the local safety authority said Aug. 10. Nieuwdorp is the site of Netherland's Zeeland refinery. The disturbance was temporary, the local authority said. The refinery was not immediately available to comment. ","headline":" Oil leak at Netherland's Zeeland: report","updatedDate":"2024-08-12T12:16:26.000"},{"Unnamed: 0":141,"body":" Wheat Platts assessed FOB Russia wheat down $1 per metric ton on the week at $221\/mt. The FOB Constanta Varna Burgas 12.5% and 11.5% stayed firm on the week at $229.75\/mt and $224.75\/mt, respectively. The Russian agriculture ministry set its variable export tax for wheat for Aug. 14-20 at Rb257\/mt ($2.84\/mt), down Rb187\/mt from the previous seven-day period. Egypt is due to buy 3.8 million mt of wheat Aug. 12 for delivery over October-April. The payment of choice is a 270-day letter of credit. French wheat crop ratings continued to decline, with 48% of the crop in good\/excellent condition compared to 50% in the previous week. This is the lowest level since 2016, farm office Agrimer said. Ukraine has so far harvested 20.9 million mt of wheat (97% of total completion) with a yield of 44.2c\/ha, the agrarian ministry said. Corn Platts assessed FOB Ukraine corn down $1\/mt on the week at $200\/mt, and FOB CVB corn down $2\/mt on the week at $210\/mt. In Ukraine, traders are looking forth for the trade of coaster size ships rather than handysize ships for the remaining stock of old crop from Ukraine. In the EU market, participants are anticipating liquidity for Serbian corn. The Constanta-Varna-Burgas market is expected to witness small trades of old Serbian corn out of Constanta during the week. Market participants are keeping an eye on the freight rates from Ukrainian ports to various destinations, which are anticipated to drop down with the low grain trade and availability of ships. Traders are expecting a gradual increase in the liquidity for new corn crop in the region amid the expected early harvest of the new season crop. Market participants are looking out for more competitive prices for new crops. Sunflower oil Platts assessed sunflower oil FOB Black Sea Ukraine for September loading down $28\/mt on the week at $921\/mt. Harvesting in Ukraine is drawing to a close, with agrarians across Bukovyna, Vinnytsia, Kyiv, Poltava, Odesa, Kherson, Kirovohrad and Cherkasy regions having completed the collection of early grains and pulses. The slow performance in the sunflower oil market over the last week indicates that buyers are still processing the recent economic shocks. The introduction of duty reductions in Turkey and the promise of support for local agriculture might restore some market optimism, but a cautious approach is expected as traders wait to see the impact of measures. Rapeseed oil Platts assessed rapeseed oil FOB Dutch Mill front run down Eur16\/mt on the week at Eur965\/mt on Aug 9. This season\u2019s Ukrainian rapeseed harvest stands at 3.318 million tons, with 1.22 million hectares threshed, achieving 99% completion. Overall, the new harvest has been gathered from an area of over 7.741 million hectares, yielding a total of 30.64 million tons of grains and oilseeds. ","headline":" Key market indicators for Aug 12-16","updatedDate":"2024-08-12T11:50:34.000"},{"Unnamed: 0":142,"body":" Crude futures were higher in midmorning trading in London, as investors assessed geopolitical risks and eyed a host of economic indicators. At 12:44 pm London time, the ICE October Brent futures contract rose 75 cents\/b from the previous close to $80.41\/b, while the NYMEX September light sweet crude contract gained 84 cents\/b to $77.69\/b. Tensions persisted in anticipation of an Iranian response to Israel over the killing of a senior Hamas leader after military drills were conducted by Iran's elite Revolutionary Guards. \u201cA fair amount of uncertainty over Iran\u2019s response to last month\u2019s assassination of a top leader of Hamas in Tehran has been supportive of the risk premium for crude oil,\u201d said ING's Warren Patterson and Ewa Manthey. Meanwhile, OPEC+ struck a more bearish tone in its monthly oil market report Aug. 12. The producers group said the \u201ccall\u201d on the OPEC+ alliance\u2019s crude -- the volume of oil it must produce to balance the market -- would be 43.0 million b\/d in 2024 and 43.6 million b\/d in 2025. That is down 100,000 b\/d and 300,000 b\/d respectively from July\u2019s forecast. Overall volatility has persisted across risk assets, with geopolitical worries counterbalanced against a stronger dollar, while market participants await further economic indicators. \u201cThis week the market will focus on a major release of economic data ... On Wednesday, the US July Consumer Price Index data will dominate this week\u2019s market performance. Given the weakness in July figures, the market might get a surprise with inflation surprising to the downside,\u201d said Saxo Bank commodity strategists. Net long bets on products have been weak particularly on the gasoline side. Positioning data from the US Commodity Futures Trading Commission shows money managers' net long bets on gasoline at 7,624 lots in the week to Aug. 9, the lowest total volume since July 2017. Weaker profit margins for refiners have come along with less bullish sentiment for products. \u201cThere are suggestions that some of the major oil refineries in the US are restricting operations at their facilities this quarter following shrinking profit margins,\u201d said Patterson and Manthey. Traders were looking forward to the International Energy Agency's monthly oil market report Aug. 13. Some other major economic data expected this week includes Chinese retail sales and industrial production. ","headline":" Crude higher amid geopolitical risks, economic data","updatedDate":"2024-08-12T11:45:56.000"},{"Unnamed: 0":143,"body":" PetroChina's Dalian Wepec is back from maintenance, according to refinery sources. The plant was shut for full maintenance from June 5 to July 24. \"Refinery downtime [in Asia] decreased by 135,000 b\/d, with total outages at around 1.6 million b\/d for the week ending Aug. 9 as refineries restarted from maintenance,\" S&P Global Commodity Insights analysts wrote in a recent report. ","headline":" China's Dalian Wepec back from maintenance","updatedDate":"2024-08-12T11:40:26.000"},{"Unnamed: 0":144,"body":" Suezmax freight rates for ships loading in the Black Sea and Mediterranean have fallen to the lowest level in 10 months in August after a bearish second half of July, hurt by a weaker Atlantic market, declining VLCC and Aframax rates and seasonally slower demand. Platts, part of S&P Global Commodity Insights, assessed freight on the 135,000 mt Caspian Pipeline Consortium terminal-Med route, exclusive of EU Emissions Trading Scheme charges, at w85 on Aug. 9, the lowest since Oct. 11, 2023. Rates for ships loading in the Med have also fallen, with Platts assessing freight on the 135,000 mt Med-Med route, exclusive of EU ETS charges, at w79.5 on Aug. 9, the cheapest since Oct. 11, 2023. Short-term crude inquiry levels in the Med could be affected by Libya's National Oil Company declaring a force majeure at the Sahara oilfield Aug. 7, putting further pressure on rates, according to trade sources. \u201cWe are in the summer doldrums, there is very little activity, and no support from Aframaxes or VLCCs,\u201d a Europe-based trader said, commenting on the broader Suezmax segment. \u201cPeople are on holiday or are not interested.\u201d A Europe-based shipbroker emphasized the importance of the West African Suezmax market, which is currently seeing rates at a 10-month low in the wake of a seasonal slowdown, in influencing Suezmax rates in the Med and Black Sea. \u201cEveryone tells me that WAF plays a significant role when I have a cross-Med cargo -- it either pulls or keeps vessels in the Med,\u201d the broker said. Suezmax voyages for the cross-Med route have declined in popularity for both charterers and owners, according to the broker. \u201cThere are not many cross-Med Suezmax cargoes nowadays, back in the day there were a lot more. I think Aframax vessels have taken over this trade,\u201d the broker said. \u201cIt is to do with refinery capacity, as Aframax [cargoes] are more suitable for the volume they require, while Suezmax owners are also not offering for cross-Med runs, since they prefer longer voyages.\u201d Eastbound rates decline Weakness in the global Suezmax segment has also put pressure on rates for long-haul voyages loading in the Med and Black Sea and discharging in the Far East. Platts assessed freight on the 130,000 mt Libya-Ningbo route, basis a voyage transiting the Suez Canal, at $4.2 million on Aug. 9. Prior to this, rates were slightly above the $5 million mark for most of May and June, before retreating slightly in July and falling at the beginning of August. The premium for a voyage around the Cape of Good Hope versus a transit through the Suez Canal has also decreased, with Platts assessing the differential at $200,000 for both the 130,000 mt Libya-Ningbo and 135,000 mt Black Sea-Ningbo runs on Aug. 9. This represents a significant fall from levels seen earlier in the year. Platts assessed the Cape of Good Hope premium for both the routes at $1 million on April 2, when the assessments were launched. The volume of eastbound Suezmax ships loading in the Med and Black Sea has decreased since the beginning of the Red Sea crisis in October 2023, with not more than four west-east Suezmax shipments each month since January 2024, according to S&P Global Commodities at Sea . Prior to the Houthi attacks, the monthly shipment count for these routes often reached as high as 18, according to CAS. Despite the recent decline in Suezmax rates, the advent of the fourth-quarter loading window could provide some support, as owners will begin expecting higher rates in anticipation of seasonally stronger demand, a London-based Suezmax broker said. ","headline":"Black Sea, Med Suezmax rates fall to lowest in 10 months as demand cools","updatedDate":"2024-08-12T11:22:02.000"},{"Unnamed: 0":145,"body":" ADNOC Gas is accelerating growth plans in line with its parent company Abu Dhabi National Oil Co.'s plan to boost production capacity to 5 million b\/d by 2027, the company said in its first-half earnings report on Aug. 12. In May, ADNOC announced it had upped its production capacity to 4.85 million b\/d. As crude production climbs, so will associated gas production that ADNOC Gas will be responsible for processing, and so it has allocated $13.2 billion to its growth portfolio. \u201cWe have today capacity in our systems that can handle the additional gas coming our way,\u201d ADNOC Gas CFO Peter van Driel told reporters in an Aug. 12 earnings call. He said that expansion operations to boost capacity by 20% by 2028 are part of efforts to \u201cplan ahead\u201d for when supply from ADNOC exceeds existing gas processing capacity. During the second quarter of 2024, ADNOC Gas spent $400 million, primarily on growth projects. ADNOC Gas expects domestic gas demand in the UAE to grow 3.6% by 2029, compared to 2.3% in advanced economies and 2.6% in emerging economies. Domestic gas demand is expected to be driven by GDP and population growth alongside UAE government initiatives to attract new industries to the country, including energy-intensive AI data centers, according to information provided during the earnings call. Domestic projects include the IGD-E2 and Meram projects that are expected to be completed next year as well as the P 5.0, slated for 2027, and the Bab Gas Cap and LNG 2.0, which are said to be online in 2028. \u201cVia these investments, it expresses confidence in the growth of the UAE economy, and it is the strength of that growth that gives us the confidence to build for increased demand in the UAE,\u201d van Driel said. Some of the additional volume will head overseas, and at the center of those export plans is the $5.5 billion Ruwais LNG facility. ADNOC Gas intends to acquire its parent company\u2019s majority stake, according to its 2024 first-half results released Aug. 12. The Ruwais LNG facility, slated to begin exports in 2028, will include two 4.8 million metric ton\/year LNG trains. Prerequisites for construction had begun, ADNOC\u2019s executive vice president for downstream asset management Fatema al-Nuaimi told S&P Global Commodity Insights in a July interview. Commodity Insights analysts forecast LNG demand to grow by 50% between 2024 and 2030 to 618 MMt\/y, at an annualized average growth rate of 7%. Demand growth during this period will be driven by higher LNG supply primarily as a large wave of liquefaction capacity comes online from mid-2025. \u201cThis new supply reaching the markets from the second half of the decade could overtake LNG demand by 2030, leading to a period of loose market conditions and downward pressure on prices,\u201d Commodity Insights analysts said. From ADNOC Gas\u2019s view, van Driel said: \u201cIn the long-term we\u2019ve committed sales. In the short-term there\u2019s pressure on spot prices, but we\u2019re still well-positioned to go to the West and East and optimize our revenues, and spot pricing LNG has always been more volatile.\u201d ADNOC has said 70% of the offtake agreements have been signed, but publicly known contracts account for 52% of the project\u2019s 9.6 MMt\/y capacity, Commodity lnsights analysis finds. Total contracted volumes stand at 5 MMt\/y. van Driel said that LNG contracts were \u201coil-price linked.\u201d Al-Nuami said in July that more agreements would be announced \u201cin due course.\u201d ADNOC Gas reported $12 billion in revenue in the first half of 2024, up 14% year on year due to a favorable pricing environment, with exports growing slightly in the first half to 507 TBtu compared to 466 TBtu in the previous year. Two-thirds of revenue come from export sales, van Driel said. Additionally, ADNOC Gas\u2019s share of LNG sales volumes saw an increase, moving from 124 TBtu to 130 TBtu. ","headline":"ADNOC Gas pushes ahead with expansion projects","updatedDate":"2024-08-12T11:12:26.000"},{"Unnamed: 0":146,"body":" West African oil producer Angola loaded 34.5 million barrels of crude intended for international export in July, the joint highest monthly volume of 2024, along with March\u2019s figure, according to the latest ship tracking from S&P Global Commodities at Sea on Aug. 12. China\u2019s take of the July export program totaled 17.2 million barrels, the same volume as the consumer purchased from the June program, CAS showed. China is Angola\u2019s most important export market, with the country regularly picking up close to half of all exported Angolan crude oil. Spain and the Netherlands saw month-on-month increases worth 1.9 million barrels, taking receipt of 3.9 million barrels and 2.9 million barrels from July, respectively. Angola\u2019s Dalia crude, one of West Africa\u2019s heavier grades, maintained its spot as the highest or joint highest volume export grade from the country, rising from 3.8 million barrels in June to 4.8 million barrels in July. Mostarda took second spot at 3.8 million barrels, the same volume that has been loaded for four consecutive months, according to CAS. Market participants in Angola are focusing on the placement of September-loading volumes, with loading programs for October expected in the coming days. \u201cThe market has been steady overall, maybe a bit softer for some grades and a bit stronger for others,\u201d said one WAF crude trader of the current trading cycle. \u201cFreight has been cheap, and the market has ticked over supported by some Western demand.\u201d One of Angola\u2019s signature export grades Girassol was assessed by Platts, part of S&P Global Commodity Insights, at a $2.70\/b premium to global benchmark Dated Brent on Aug. 9, compared with a $2.65\/b premium on July 9. Over the course of the month, the differential has been rangebound between a $2.75\/b premium and a $2.50\/b premium, according to Platts data, showing the steady nature of the trading cycle. ","headline":" Angolan crude loadings match YTD high 34.5 mil barrels in July","updatedDate":"2024-08-12T11:04:18.000"},{"Unnamed: 0":147,"body":" The Middle East sour crude complex saw two convergences during the Singapore Platts Market on Close assessment process Aug. 12, while medium sour crude cash differentials gave up gains from the prior session to be assessed narrower on the day. Platts, part of S&P Global Commodity Insights, assessed October cash Dubai and cash Oman at a premium of 78 cents\/b to the same-month Dubai futures at the market close, both down 29 cents\/b on the day. October cash Murban was assessed at a premium of $1.03\/b to the same-month Dubai futures, down 4 cents\/b on the day. During the Platts MOC process, 40 October Dubai partials of 25,000 barrels each traded. The sellers were Trafigura, Reliance, Phillips 66, ExxonMobil, Mitsui, Mercuria, Unipec and PetroChina, and the buyers were Vitol, Gunvor and Glencore. Mitsui declared a cargo of October Upper Zakum crude to Gunvor following the convergence of 20 partials in Platts cash Dubai, while Unipec declared a cargo of October Oman crude to Vitol following a convergence. A convergence occurs when 20 partials are traded between two counterparties, resulting in a full 500,000-barrel physical cargo being declared from the seller to the buyer. In the broader market, Saudi Aramco was heard to have allocated full term volumes to Asian refiners for September-loading crude supply, while QatarEnergy has also issued its monthly sell tender offering Al-Shaheen, Qatar Land and Marine crude for October loading. ","headline":" Middle East sour crude complex sees two convergences","updatedDate":"2024-08-12T10:23:35.000"},{"Unnamed: 0":148,"body":" China UCOME prices are expected to remain stagnant for the week starting Aug. 12, with little to no buying interest from buyers, while supply remains lower for Asian palm fatty acid distillates. Sustainable Aviation Fuel ** Platts assessed Asia Sustainable Aviation Fuel (SAF) cost of production prices in the week ended Aug. 8 with Used Cooking Oil-based SAF up by $15.33mt to $1,726.54\/mt, while Palm Fatty Acid Distillate-based SAF dropped by $30.62\/mt to $1,592\/mt, S&P Global Commodity Insights data showed. ** Japan's ENEOS Holdings is considering imports and higher production of jet fuel as part of its response to aviation fuel shortages in the country, Executive Vice President and CFO Tanaka Soichiro said Aug. 9. Over April-June, ENEOS reported a 2.7% year-on-year increase in its domestic jet fuel sales to 380,000 kiloliters, or 2.39 million barrels, as a result of the recovery in aviation demand following the pandemic. ** Avina Clean Hydrogen Inc. has selected the sustainable aviation fuel technology, PureSAF, for its project in the US. The technology is developed by Swedish Biofuels and is exclusively licensed by KBR Inc. worldwide. Under the terms of the contracts, KBR will provide the technology licensing, proprietary engineering design, and front-end engineering design (FEED) for Avina's facility to produce 120 million gallons of SAF per year. ** The Chinese government will accelerate the development of biofuels such as biobunkers and SAF to achieve a comprehensive green transformation, the government said in a statement Aug. 11. Under the plan, the Chinese government will promote low-carbon sectors such as energy management, waste management and environmental pollution management, thus increasing their weightage in the energy-saving industry. By 2030, the industry is projected to reach a scale of approximately Yuan 15 trillion ($2.1 trillion). ** The Asian jet fuel\/kerosene complex is anticipated to remain stable to soft over Aug. 12-16 as support from summer travel diminishes while trade participants await fresh demand cues from China\u2019s upcoming Golden Week holiday from Oct. 1-7. Renewable Diesel\/Hydrotreated Vegetable Oil ** Asia\u2019s Hydrotreated Vegetable Oil (HVO) prices ended the week on a mixed note with UCO-based HVO prices up by $13.73\/mt to $1,591.28\/mt while PFAD-based HVO prices down by $28.32\/mt to $1,468.47\/mt, according to Platts assessments Aug. 8. ** China's UCOME prices dropped as some producers sold lower to clear their remaining UCOME stocks for the week. Platts assessed the FOB China UCOME price at $995\/mt on Aug. 8, down $20\/mt compared to the previous week. ** Market structure for the Asian gasoil complex is expected to remain in contango Aug. 12-16, though this, along with weak LR2 freight rate could spur some East-West arbitrage cargo movement. Feedstocks ** China\u2019s UCO prices increased by $10\/mt to $890\/mt for the week ended Aug. 8, amid an increase in demand for China UCO shipments heading to the US, according to market sources. ** The price of Asian palm fatty acid distillates dipped due to weaker crude palm oil prices. Market demand remains stable, while supply is lower as many refineries have temporarily halted operations to reduce losses from negative margins. Platts assessed the FOB Dumai PFAD price down $25\/mt at $800\/mt in the week to Aug. 8. Summary table for prices UCO based Asia SAF($\/mt) PFAD-based Asia SAF ($\/mt) FOB Singapore Jet ($\/b) UCOME FOB China ($\/mt) UCO-based Asia RD ($\/mt) PFAD-based Asia RD ($\/mt) FOB Singapore Gasoil ($\/b) UCO FOB NE Asia ($\/mt) PFAD FOB Dumai ($\/mt) 8-Aug 1726.54 1592 91.44 ($722.38\/mt) 995 1591.28 1468.15 92.8 ($691.36\/mt) 890 800 2-Aug 1711.21 1622.62 94.06 ($743.07\/mt) 1015 1577.55 1496.47 95.20 ($709.24\/mt) 880 825 26-Jul 1701.35 1596.16 96.98 ($766.14\/mt) 1015 1570.6 1474.1 97.80 ($728.61\/mt) 880 813 ","headline":" Key market indicators for Aug 12-16","updatedDate":"2024-08-12T09:55:57.000"},{"Unnamed: 0":149,"body":" Malaysia's palm oil inventories fell 5.4% on the month to 1.733 million metric tons in July, the Malaysian Palm Oil Board said Aug. 12, as exports from the world's second-largest palm oil producer outperformed industry expectations. Markets had anticipated end-July stocks to be around 1.84 MMt, a slight increase from 1.83 MMt at the end of June, according to a survey of 10 analysts, traders and growers by S&P Global Commodity Insights on Aug. 9. The country's palm oil exports in July rose 39.2% on the month to 1.689 MMt, MPOB said, exceeding industry expectations of 1.52 MMt. Palm oil production in July was up 13.9% on the month at 1.841 MMt, according to MPOB. However, this was slightly below the industry median forecast of 1.85 MMt. Malaysia's local consumption of palm oil fell 24% on the month to 260,137 t in July, MPOB said. The MPOB data is bullish for palm oil prices, as stocks have eased, contrary to market expectations of a slight increase, and are now at levels seen in July 2023, Anil Kumar Bagani, head of research at vegetable oil brokerage Sunvin Group, said in a note Aug. 12. \"On the other hand, the overall weakness in soybean oil prices due to a strong downside momentum in CBOT soy oil will continue to keep a cap on any recoveries in the palm oil prices,\" Bagani said. Palm oil and soybean oil prices are interlinked as they compete for market share in the international vegetable oil markets. The benchmark crude palm oil futures on the Kuala Lumpur Commodities Exchange edged 0.5% lower to MR3,728\/t ($837.28) in the afternoon trading session Aug. 12. ","headline":"Malaysia's palm oil stocks drop 5% in July on higher exports","updatedDate":"2024-08-12T09:15:55.000"},{"Unnamed: 0":150,"body":" Australia\u2019s Arrow Energy, an equal joint venture between Shell and PetroChina, plans to develop Phase 2 of its Surat Gas Project in the state of Queensland, according to statements from Arrow Energy and Shell on Aug. 12. Shell said gas from the project will flow to the Shell-operated QCLNG LNG facility on Curtis Island, near Gladstone, to meet long-term contracts and supply domestic customers. \"This is part of an existing 27-year gas sales agreement between Arrow Energy and QGC. Phase 2 is expected to contribute around 22,400 barrels of oil equivalent\/day (or 130 million standard cubic feet\/day) at peak production,\" Shell added. Shell said first gas from Phase 2 is expected in 2026 and will be processed through QCLNG infrastructure, comprising up to 450 production wells, a field compression station and new pipeline infrastructure. The oil major had previously said it would secure feedgas supply for its existing LNG facilities through additional backfill projects. Shell and PetroChina formed the Arrow Energy joint venture in 2010 and Arrow announced a 27-year gas sales agreement to supply gas to QCLNG in 2017. Phase 1 of the Surat Gas Project was approved in April 2020 and included more than 600 wells, according to Shell. QCLNG is a Shell-operated joint venture between Shell (73.75%), CNOOC (25%) and MidOcean Energy (1.25%) and supplied 15% of demand on Australia's east coast in 2023, Shell said. In a separate statement, Arrow Energy said the expansion of the Surat Gas Project in Queensland, also known as SGP North, is scheduled to begin later in 2024. The overall project sources natural gas from coal seams in the Surat Basin. ","headline":"Australia's Arrow Energy to develop Phase 2 of Surat Gas Project to backfill QCLNG","updatedDate":"2024-08-12T09:08:46.000"},{"Unnamed: 0":151,"body":" Singapore's commercial stockpiles of heavy distillates edged 0.9% higher on the week and rebounded from a three-week low to 19.7 million barrels in the week ended Aug. 7, despite a drop in imports, Enterprise Singapore data released late Aug. 8 showed. Stockpiles in the latest week, however, were down 3.6% on the year, the data showed. Residual fuel inventories in Singapore have averaged at about 20.39 million barrels so far in 2024, compared with a weekly average of 20.43 million barrels in 2023 and 20.9 million barrels in 2022, according to the data. Singapore's fuel oil imports dropped 28.6% on the week to 584,020 metric tons in the week to Aug. 7, with volumes from Asian suppliers accounting for about 38.5% of the total at 224,611 t, down 41% on the week, the data showed. The city-state imported about 79,234 t of fuel oil from Malaysia in the week to Aug. 7, down about 68% on the week, while inflows from Japan nearly halved to 15,260 t over the same period. Imports from the Middle East shrank for the third consecutive week to 191,249 t in the week to Aug. 7, with about 81,185 t from Oman, 62,202 t from the UAE and the rest from Iraq. Meanwhile, inflows from Europe -- all from Greece -- rose on the week to 49,972 t. There were no fuel oil imports from Russia for the second straight week, while inflows from Brazil slipped 10.4% on the week to 93,592 t. Singapore exported 300,134 t of fuel oil in the week to Aug. 7, up 22.1% on the week, according to the data. Outflows to Bangladesh rose 49% on the week to about 30,097 t in the week to Aug. 7, while exports to China dropped 53% to 64,209 t over the same period. Singapore's inventory data counts only stocks at onshore terminals. Enterprise Singapore describes heavy distillates as \"residues,\" which include cracked and straight-run fuel oil and low-sulfur waxy residue. Bunker demand lukewarm A sharp spike in low sulfur fuel oil premiums in Singapore -- the world's largest bunkering hub -- has capped demand, while inquiries for high sulfur fuel oil remained steady, traders said Aug. 12. While overall upstream LSFO stockpiles were mostly adequate, loading disruptions in late July reportedly due to off-specification cargoes have been gradually resolved, with most downstream suppliers having secured ample ex-wharf loadings since early-August, according to traders. Some downstream suppliers reportedly have unfilled \"pockets\" of early LSFO refueling slots, as the recent sharp increase in delivered premiums was especially pronounced for prompt requirements, with some sellers hoping to leverage the temporarily stronger market to lift profit margins. However, traders expect that progressively normalizing supply conditions will ease bunker premiums. The Platts-assessed Singapore-delivered marine fuel 0.5%S bunker premium over the benchmark FOB Singapore Marine Fuel 0.5%S cargo value softened to $24.08 per metric ton over Aug. 5-8, down from $27.29\/t the previous week, S&P Global Commodity Insights data showed. In the HSFO segment, traders anticipate very ample cargo availabilities around Singapore in the near term, although the slightly tighter-than-usual barging schedules for prompt refueling dates may continue to support bunker premiums to some extent. Nevertheless, steady inflows of HSFO replenishment cargoes to the hub could continue to keep the region well-supplied for the rest of August, industry sources said. The Platts-assessed Singapore-delivered 380 CST HSFO bunker premiums over the FOB Singapore 380 CST HSFO cargo values averaged at $19.42\/t over Aug. 1-8, above the $13.49\/t in July, Commodity Insights data showed. ","headline":" Fuel oil stocks edge higher on week despite lower imports","updatedDate":"2024-08-12T08:15:36.000"},{"Unnamed: 0":152,"body":" Term contractual supply of August-loading barrels of Singapore ex-wharf low sulfur marine gasoil, with 0.1% sulfur, were inked at differentials ranging minus $2\/b to minus $2.50\/b against benchmark FOB Singapore 10 ppm sulfur gasoil cargo assessments, traders said Aug. 12, as lagging downstream demand weigh on valuations. This compared with July\u2019s range of differentials concluded at around minus $1.30-minus $2\/b, and differentials of the minus $1-minus $2.50\/b earlier in June. Even though LSMGO stockpiles around the world\u2019s largest bunker hub of Singapore was mostly adequate for downstream deliveries, bumpy demand from end-users is expected to weigh on valuations and have largely dampened traders\u2019 sentiments so far in Q3. \u201cThe market is still bad, so we are conservative [on ex-wharf procurement],\u201d a Singapore-based bunker supplier said Aug. 12. Sales of LSMGO around the Singapore hub, inclusive of bioblended products, totaled only 278,800 mt in June, a sharp 15.8% decline from May despite a 2.7% increase on the year, latest preliminary data from the Maritime and Port Authority of Singapore showed. In the absence of any significant pickup in LSMGO bunker demand over the past many weeks, barge schedules for prompt refueling dates were also mostly made available to end-users, according to bunker suppliers. Thus, downstream suppliers with monthly ex-wharf requirements were reportedly cautious of procuring excessive volumes, traders said, while the much-softer clean tanker rates also drastically reduced importers\u2019 costs over the past month. Platts, part of S&P Global Commodity Insights, assessed clean Singapore-South Korea Medium Range-sized tanker rates at a near nine-month low of $17.66\/mt Aug. 7 before inching up to $17.77\/mt Aug. 8. Clean MR tanker rates along this route was last assessed lower at $17.41\/mt Nov. 24, 2023. A replenishment cargo amounting to around 345,000 barrels, or 46,309 mt, of gasoil originating from South Korea\u2019s Daesan refinery reportedly last landed around Singapore Straits in early-August, while another shipment of an estimated 326,000 barrels, or 43,758 mt, of gasoil reportedly sourced from the similar origin could arrive in Singapore around the last week of August, according to industry sources. Platts assessed the Singapore-delivered LSMGO differential against the FOB Singapore 10 ppm sulfur gasoil assessment to average $1.90\/mt Aug. 1-8, compared to $4.41\/mt across July. Singapore\u2019s delivered LSMGO differential slipped to an over seven-week low of minus $6.66\/mt Aug. 8, down $5.70\/mt on the day, and was last assessed lower at minus $7.90\/mt June 19, Commodity Insights data showed. ","headline":"Singapore Aug term ex-wharf LSMGO differentials slip amid tepid downstream demand","updatedDate":"2024-08-12T06:36:47.000"},{"Unnamed: 0":153,"body":" Crude oil futures were higher in midafternoon Asian trade Aug. 12, as geopolitical tensions remained in focus ahead of fresh demand cues from China and the US later in the week. At 2:20 pm Singapore time (0620 GMT), the ICE October Brent futures contract was up 22 cents\/b (0.28%) from the previous close at $79.88\/b, while the NYMEX September light sweet crude contract rose 34 cents\/b (0.44%) at $77.18\/b. The uptick in crude prices at the start of the trading week came amid renewed uncertainty over the state of global geopolitics. The US has ordered the deployment of a guided missile submarine to the Middle East amid mounting concerns of a potential escalation in the ongoing conflict, regional media reported. Fears of an Iranian response to Israel over the killing of a senior Hamas leader continued to grow following military drills by the Revolutionary Guards. While tensions threatened crude supply dynamics in the region, the potential expansion of the theatre of conflict also lifted the US dollar in Asian trade, Saxo's APAC Research Team said Aug. 12. The ICE US Dollar Index was at 103.015 as of 0555 GMT Aug. 12, up 0.06% from the previous close. A stronger dollar results in dollar-denominated assets like oil futures becoming more expensive to investors holding foreign currencies, thus dampening demand for these assets. Crude prices were further supported by stronger-than-anticipated inflation data from China in the previous week, Yeap Jun Rong, market analyst at IG, said Aug. 12. \"But delving further will show the core CPI at its lowest level since February this year, which raised doubts of whether domestic demand is actually at play here,\" he said. A slate of economic data prints -- including industrial production data and retail sales figures due Aug. 15 -- from China could offer fresh demand insights about the world's largest importer of crude. Going ahead, volatility is anticipated to persist into the fresh trading week, warned SPI Asset Management's Managing Partner, Stephen Innes. \"The idea of quickly returning to a state of low Macro and FX volatility might be overly hopeful,\" he cautioned. \"We\u2019re coming off a week of extreme stress patches, with ludicrous intraday swings that had traders feeling like they were on a financial rollercoaster.\" On supply, Russia reiterated its commitment to its OPEC+ compensation plan , despite overproducing its quota by 67,000 b\/d of oil in July. In a statement, the country's energy ministry said its \u201cproduction in July has further decreased comparing to June, coming at 67,000 b\/d above the target levels.\u201d Dubai swaps Dubai crude swaps and intermonth spreads were higher in midafternoon Asian trading Aug. 12 from the previous close. The October Dubai swap was pegged at $77.72\/b at 2:15 pm Singapore time (0615 GMT), up $1.65\/b (2.17%) from the previous Asian market close. The September-October Dubai swap intermonth spread was pegged at 64 cents\/b, unchanged over the same period, and the October-November intermonth spread was pegged at 52 cents\/b, up 3 cents\/b. The October Brent-Dubai exchange of futures for swaps was pegged at $2.19\/b, unchanged from the previous Asian close. ","headline":" Crude higher on geopolitical risk, further volatility likely","updatedDate":"2024-08-12T06:31:35.000"},{"Unnamed: 0":154,"body":" Kuwait Petroleum Corp. kept steady on the month the September official selling price differential for its Asia-bound Kuwait Export Crude blend, while OSPs for other Asia-bound grades were also left unchanged or saw small increases or declines, according to a notice seen by S&P Global Commodity Insights Aug. 12. For Asia-bound KEC on a FOB basis, KPC left the price differential unchanged at plus $1.25\/b against the average of DME Oman and Platts Dubai crude assessments in September, the notice said. The differential for its Kuwait Super Light crude to Asia was cut by 10 cents\/b on the month to plus $1.25\/b for September. The September OSP differentials for Kuwait Export Crude on an FOB basis to the US and ex-ship delivered to the US Gulf Coast were both cut by 75 cents\/b on the month at premiums of $4.70\/b and $6\/b, respectively, to the ASCI. The September OSP differentials for KEC headed to Northwest Europe and the Mediterranean were both cut by $2.80\/b on the month to minus $2.50\/b against Dated Brent. The September OSP differential for FOB Sidi Kerir was also cut by $2.80\/b to minus $2.20\/b to Dated Brent. KUWAIT'S CRUDE OIL OFFICIAL SELLING PRICES: (Unit: $\/b) Grade\/Location Basis July August September Change KEC to Asia Oman+Dubai 1.95 1.25 1.25 0.00 KSLC to Asia Oman+Dubai 1.95 1.35 1.25 -0.10 Khafji FOB Asia Oman+Dubai 1.20 0.50 0.50 0.00 Hout FOB Asia Oman+Dubai 2.16 1.51 1.60 0.09 KEC FOB to US ASCI 5.45 5.45 4.70 -0.75 KEC ex-ship delivered to USGC ASCI 6.75 6.75 6.00 -0.75 KEC FOB to Med Dated Brent -0.70 0.30 -2.50 -2.80 KEC FOB to NWE Dated Brent -0.70 0.30 -2.50 -2.80 KEC FOB Sidi Kerir Dated Brent -0.40 0.60 -2.20 -2.80 Source: Kuwait Petroleum Corporation ","headline":"Kuwait's KPC keeps Asia-bound September KEC crude OSP steady on month","updatedDate":"2024-08-12T05:43:30.000"},{"Unnamed: 0":155,"body":" Singapore's commercial stockpiles of light distillates fell 2.27% on the week over Aug. 1-7 amid lower gasoline and naphtha imports, Enterprise Singapore data showed Aug. 12. Total stocks of light distillates -- which include gasoline, reformates and naphtha but exclude gases like LPG -- declined to 14.071 million barrels in the week ended Aug. 7. The city-state's gasoline imports slumped 73.97% on the week to around 61,409 mt in the week ended Aug. 7, while exports plunged 44.27% to around 312,046 mt over the same period, the data showed. Although Singapore remained a net exporter of gasoline, the city-state's net exports declined 22.66% over the week to around 250,637 mt. China's gasoline exports to Singapore were down 67.81% on the week, but it remained the largest gasoline exporter to Singapore with its outflows contributing 56.22% to Singapore's overall gasoline imports. According to a market source, China's gasoline production in July had dipped mainly due to poor gasoline margins. However, market participants were optimistic that China's gasoline outflows in August will likely increase from July as refineries are expected to produce more gasoline in anticipation of an improvement in margins, industry sources said During the same period, Japan exported nil gasoline compared to 37,140 mt the prior week, amid several unplanned refinery shutdowns. Indonesia, the largest regional importer of gasoline, reduced its imports by 68.89% to 47,719 mt on the week and Malaysian imports from Singapore fell 70.18% to 39,674 mt on the week. Higher naphtha inflows Singapore's imports of naphtha, reformates and other blendstocks soared 79.75% on the week to 146,887 mt in the week to Aug. 7, amid higher inflows from India, the data showed. Singapore imported 56,374 mt of naphtha from India in the week ended Aug. 7 as compared to none the week before. Inflows from Russia also rose to 910 mt as compared to none the week before, the data showed. Naphtha exports -- mainly to Vietnam -- plunged over 47.35% on the week to 10,123 mt. The fall came amid lower outflows to Malaysia, with volumes decreasing to nil from 11,988 mt the previous week. Asian naphtha prices may be marginally supported by the closed EW arbitrage despite the fall in crude prices, market sources said. ","headline":" Light distillate stocks edge lower on week over Aug 1-7","updatedDate":"2024-08-12T05:15:40.000"},{"Unnamed: 0":156,"body":" Asian light ends refined products, including gasoline and LPG, may face downward pressure due to ample regional gasoline supplies and lackluster Chinese propane dehydrogenation demand over Aug. 12-16, market sources said. Meanwhile, Asian naphtha prices could experience some upward pressure ahead of trading activity in the first half of October, the sources added. At 11:45 am Singapore time Aug. 12, ICE August Brent crude futures traded at $79.73\/b, compared with $78.26\/b at the Aug. 8 Asian close. Gasoline Asian gasoline prices are likely to trend downward in the week to Aug. 16 as fresh supplies are expected in the region. Platts assessed the gasoline cash differential at a premium of 42 cents\/b to 92 RON Mean of Platts Singapore gasoline assessments Aug. 8, up from minus 26 cents\/b on Aug. 2, S&P Global Commodity Insights data showed. The negative East-West arbitrage, ranging between minus $7\/b and minus $8\/b, indicates that gasoline values in Europe are more favorable, encouraging ships to remain in European waters due to better margins. The East-West spread was pegged at minus $7.95\/b at 0300 GMT on Aug. 12. Market participants anticipate fresh gasoline supply from the Middle East, with multiple cargoes reportedly heading to Asia. Naphtha Asian naphtha prices may find marginal support despite falling crude prices in the week ending Aug. 16 due to the closed East-West arbitrage, market sources said. The Asian market is set to see trading activity begin for first-half October delivery to North Asia as the half-month trading cycle rolls forward Aug. 16. Olefin margins improved as the Platts-assessed CFR Northeast Asia ethylene-CFR Japan naphtha physical spread -- closely watched by petrochemicals producers -- widened $14.25\/mt on the week to $198\/mt at the Aug. 8 Asian close, Commodity Insights data showed. However, the spread still remains below both the typical breakeven spread of $250\/mt for integrated producers and $300-$350\/mt for non-integrated producers. LPG Asian propane prices are anticipated to face downward pressure in the week to Aug. 16 due to lower Chinese PDH plant run rates, market sources said. Run rates at Chinese PDH plants averaged 73% in the week to Aug. 9, down 1% on the week, the sources added. However, LPG demand in India could rise ahead of the Independence Day holiday on Aug. 15, market sources said. Brokers pegged the front-month September FEI swap at $632\/mt early Aug. 12, unchanged from the Platts assessment of $632\/mt at the Aug. 8 Asian close. ","headline":" Key market indicators for Aug 12-16","updatedDate":"2024-08-12T04:22:14.000"},{"Unnamed: 0":157,"body":" Singapore's bitumen exports dropped 38% on the week to 27,991 mt in the week ended Aug. 7, data released by Enterprise Singapore late Aug. 8 showed. The city-state exported 1,473 mt bitumen to Thailand in the week to Aug. 7, slumping from 9,104 mt in the preceding week, while bitumen exports to Indonesia dropped nearly 17% on the week to 6,031 mt in the latest week, the data showed. Although Singapore\u2019s bitumen exports to China jumped about 54% on the week to 10,007 mt in the week to Aug. 7, there were no bitumen exports to Australia, Brunei, or Cambodia in the latest week, according to Enterprise Singapore data. Traders remain optimistic that regional bitumen demand would gradually strengthen after the monsoon season, as road construction works typically pick up pace in the fourth quarter. The FOB Singapore bitumen price was assessed at $493.25\/mt at the Asian close Aug. 8, buoyed by a competitive bid from Trafigura during the Platts Market on Close assessment process by S&P Global Commodity Insights. The Singapore bitumen price, which hit a more than eight-month high of $494\/mt Aug. 2, has averaged at $491.70\/mt over Aug. 1-7, compared with $486.78\/mt in the preceding week, Commodity Insights data showed. The differential for PEN 60-70 grade bitumen loading in Singapore to the benchmark Singapore 380 CST high sulfur fuel oil, which flipped into a positive territory on July 25 for the first time since late February, has averaged at a premium of $40.85\/mt over Aug. 1-7, compared with an average discount of $14.37\/mt in the previous week, Commodity Insights data showed. ","headline":" Bitumen exports shrink 38% on week as outflows to Thailand plunge","updatedDate":"2024-08-12T04:20:23.000"},{"Unnamed: 0":158,"body":" The Asian low sulfur fuel oil market is expected to remain under pressure over Aug. 12-16 amid adequate supplies available in the region, but traders said a recent strength in the downstream bunker market would likely cap any major downsides. But some traders expect the recent steep spikes in delivered LSFO premiums around the world\u2019s largest bunker hub of Singapore to soften and progressively normalize, with the downstream supply disruptions and loading delays which started since late-July ease, while most sellers have managed to secure the on-specification product for deliveries to end-users. Meanwhile, the Asian high sulfur fuel oil market remains steady amid stable bunker demand, but the fundamentals would likely start to lose some seasonal support in coming weeks once the peak summer power generation demand wanes, market sources said. In the crude oil market, the ICE Oct Brent futures contract was trading at around $79.74\/b at 0336 GMT Aug. 12, compared with $78.26\/b at 0430 GMT Aug. 8, Intercontinental Exchange data showed. Marine fuel 0.5% ** The Singapore marine fuel 0.5%S balance August-September swaps time spread was pegged at around $7\/mt in midmorning Aug. 12, compared with Platts\u2019 assessment of the spread at $6.70\/mt at the Asian close Aug. 8. ** Platts assessed the Singapore marine fuel 0.5%S cargo's cash differential over the Mean of Platts Singapore marine fuel 0.5%S assessment 13 cents\/mt higher on the day at a premium of $3.33\/mt Aug. 8. The LSFO premium, however, posted a weekly decline of nearly 25% in the week ended Aug. 8, Commodity Insights data showed. ** On the downstream side, owing to adequate LSFO stockpiles around Singapore, downstream premiums could also come under increasing pressure, especially as overall demand was at least slightly affected due to astronomical surges in bunker premiums during the momentary downstream supply disruptions in the past couple of weeks, suppliers said. ** Meanwhile, choppy LSFO bunker demand around Fujairah hub is likely to weigh on downstream valuations, while supply conditions are expected to remain largely ample for the near term with buoyed cargo inflows from within the Middle Eastern region, according to traders. High sulfur fuel oil ** The Singapore 380 CST high sulfur fuel oil cargo\u2019s cash premium over the MOPS 380 CST HSFO assessment was assessed 21 cents lower on the day at a premium of $5.54\/mt Aug. 8, hurt by competitive offers from Shell during the Platts Market on Close assessment process, Commodity Insights data showed. But the benchmark HSFO cash premium posted a weekly gain of 25.3%, the data showed. ** The adequate HSFO inventories around Singapore hub may limit any potentially significant upside to bunker premiums, even as decent demand from end-users which resulted in tighter-than-usual barging schedules for prompt refueling dates recently helped lift downstream valuations, traders said. ** Traders in Singapore also expect competition among downstream HSFO suppliers to intensify in the coming weeks, as the gradual slowdowns in Middle Eastern power generation demand during the peak summer season may buoy arbitrage flows toward Asia and keep inventories well-supplied. ** At the UAE\u2019s bunker hub of Fujairah, ample product availabilities led to stiff competition among HSFO suppliers, which most sellers expect to prolong as some players exhibited eagerness to draw down cargoes and capture shipowners\u2019 inquiries consisting of very sizable requirements. ","headline":"Asia residual fuels: Key market indicators for Aug 12-16","updatedDate":"2024-08-12T04:09:20.000"},{"Unnamed: 0":159,"body":" The Asian gasoline market will likely edge lower in the Aug. 12-16 week amid expectations of fresh regional supplies and following news of the Yokkaichi RFCC restart. Meanwhile, the physical 92 RON gasoline premiums against the Mean of Platts Singapore 92 RON gasoline assessments strengthened to 42 cents\/b at the Asian close Aug. 8 from minus 26 cents\/b Aug. 2, S&P Global Commodity Insights data showed. The prompt August reforming spread -- the difference between FOB Singapore August 92 RON and August naphtha -- narrowed $2.21\/b from the previous close to end the week at $13.15\/b Aug. 8. The wider the reforming spread, the more favorable it is to blend naphtha into the gasoline pool. Naphtha **The Asian naphtha market may be slightly supported on the back of shut East-West arbitrage despite the fall in crude prices, sources said. **Last week, the Asian reforming spread reached an over two-year low of $12.60\/b at the Aug. 5 close, as weakness in gasoline prices outpaced that of naphtha. ** Demand for gasoline blending has been weak from the region, trade sources said. **Platts assessed the front-month Singapore reforming spread -- the difference between Singapore 92 RON gasoline and naphtha derivatives and a barometer of the economic attractiveness of naphtha's use in gasoline blending -- at $13.15\/b on Aug. 8, down $3.10\/b on the week, Commodity Insights data showed. MTBE ** Weak MTBE demand in Straits will likely continue to weigh on the Asian MTBE market in the week starting Aug. 12 amid thin trading and import activity. ** The FOB China market also remained quiet with no arbitrage opening to Southeast Asia for the time being. ** MTBE fell $24\/mt from Aug. 2 at $760\/mt FOB Singapore on Aug. 8 amid lower upstream prices and sluggish demand. Toluene ** The Asian toluene market in Northeast Asia is expected to track price movements in related markets such as upstream crude oil and naphtha, along with downstream benzene ** Fundamentally, little has changed in the toluene market in the previous week, with Chinese markets heard witnessing stable demand. ** The Platts-assessed toluene FOB Korea marker edged down $2\/mt on the week to $884\/mt on Aug. 8, below an offer heard at $885\/mt, Commodity Insights data showed. ** The FOB China marker was stable on the week at $895\/mt, while CFR China prices were down $12\/mt over the same period, in line with the weaker domestic China ex-tank market. Ethanol ** The current decline in freight rates from the US Gulf to the Philippines is due to reduced vessel availability heading to the Gulf, leading owners to cut rates to return their vessels to Asia, sources said. ** US Energy Information Administration data for the week ended Aug. 2 showed ethanol production fell to a four-week low of 1.067 million b\/d, down 42,000 b\/d, or 3.79%. On the year, production was up 44,000 b\/d, or 4.30%. ** The Platts-assessed CIF Philippines bioethanol marker jumped $2\/cu m to $617\/cu m Aug. 8, Commodity Insights data showed. Isomer-MX ** Asian isomer-grade mixed xylene is likely to be under pressure from lengthening supply and sluggish demand in the week starting Aug. 12, while also continuing to track paraxylene and crude oil price developments. ** A snug inventory of MX in China below 30,000 mt in the week starting Aug. 6 could support continued imports, although reports of increased cargo arrivals in the second half of August seems to put a dampener on demand and domestic prices. ** Compared to Aug. 2, isomer-MX fell $18.50\/mt at $855\/mt FOB Korea on Aug. 8 with lower upstream prices and also reports of ample supply of MX from South Korea. Aug-08 W-o-W Change RON Price per Ron ($\/mt) Price per Ron ($\/cu m) GASOLINE FOB Singapore 91 RON non-oxygenated $87.27\/b -2.97% 91 NA NA FOB Singapore 92 RON oxygenated $85.03\/b -3.04% 92 FOB Singapore 95 RON oxygenated $89.62\/b -3.49% 95 FOB Singapore 97 RON oxygenated $90.31\/b -3.58% 97 BLENDSTOCKS FOB Singapore Naphtha $72.42\/b 0.11% 72 3.55 4.51 FOB Korea Toluene $884\/mt -0.23% 115 7.01 10.43 FOB Singapore MTBE $760\/mt -3.06% 115 1.62 1.84 FOB Korea Isomer-MX $855\/mt -2.12% 113 6.30 10.64 CIF Philippines Ethanol $617\/cu m 0.33% 118 2.18 3.72 ","headline":" Key market indicators for Aug 12-16","updatedDate":"2024-08-12T04:05:23.000"},{"Unnamed: 0":160,"body":" Fundamentals in the Asian middle distillates complex will likely be unchanged on week over Aug. 12-16, with trade participants awaiting fresh spot activity for directional cues while oversupply continues to weigh on both gasoil and jet fuel\/kerosene markets. Front-month ICE October Brent crude oil futures rose to $79.54\/b at 9:10 am Singapore time (0110 GMT) on Aug. 12, from $78.26\/b at the Aug. 8 Asian close. Jet fuel\/kerosene **The Asian jet fuel\/kerosene complex is seen remaining stable to soft over Aug. 12-16, as support from summer travel diminishes while trade participants await fresh demand cues from China\u2019s Golden Week holiday Oct. 1-7. **The Platts FOB Singapore cash differential for jet fuel\/kerosene to the Mean of Platts Singapore jet fuel\/kerosene assessment was minus at 77 cents\/b at the Aug. 8 Asian close, compared with minus 56 cents\/b a week earlier, S&P Global Commodity Insights data showed. ** Demand for jet fuel is expected to remain strong for the rest of the year, driving global oil consumption alongside gasoline and petrochemicals, Saudi Aramco CEO Amin Nasser told reporters on a media call Aug. 6. ** Brokers pegged the balance-month August-September jet fuel\/kerosene swap time spread at minus 28 cents\/b at 0110 GMT on Aug. 12, compared with minus 42 cents\/b at the Aug. 8 Asian close. **The Platts fourth quarter-first quarter jet fuel\/kerosene swap spread averaged plus 33 cents\/b over Aug. 5-8, narrowing from plus 50 cents\/b the week before. Gasoil **Market structure for the Asian gasoil complex is expected to remain in contango Aug. 12-16, though this, along with weak LR2 freight rate could spur some East-West arbitrage cargo movement. **Brokers pegged the balance-month August gasoil exchange of futures for swaps -- an indicator of East-West arbitrage flows -- at minus $22.64\/mt at 0110 GMT on Aug. 12, compared with Platts' assessment of minus $25.80\/mt at the Aug. 8 Asian close. **Brokers pegged the balance-month August-September gasoil swap time spread at minus 22 cents\/b at 0110 GMT on Aug. 12, compared with Platts' assessment of minus 27 cents\/b at the Asian close Aug. 8. ** Singapore's onshore commercial stocks of gasoil and jet fuel\/kerosene rose 5.64% over Aug. 1-7 to a more than three-year high of 11.99 million barrels, amid a decline in exports, Enterprise Singapore data showed Aug. 12. **The Platts-assessed Q4-Q1 gasoil swap spread averaged plus 41 cents\/b over Aug. 5-8, narrowing from plus 64 cents\/b in the previous week. ","headline":" Key market indicators for Aug 12-16","updatedDate":"2024-08-12T01:26:55.000"},{"Unnamed: 0":161,"body":" Singapore's onshore commercial stocks of gasoil and jet fuel\/kerosene rose 5.64% over Aug. 1-7 to a more than three-year high of 11.99 million barrels, amid a decline in exports, Enterprise Singapore data showed Aug. 12. Middle distillate stocks were last higher over June 24-30, 2021 at 13.78 million barrels, historical Enterprise Singapore data showed. While the city-state remained a net export of gasoil over Aug. 1-7, outflows tumbled 56.85% to an 11-month low at 190,551 mt (1.42 million barrels), with volume last seen lower in the week to Sept. 6, 2023 at 137,774 mt. New Zealand was the top destination for Singapore\u2019s gasoil outflows at 65,700 mt. This was followed by Papua New Guinea and Mozambique at 29,716 mt and 18,921 mt, respectively. \"Demand now is about same as July, quiet,\" said a Northeast Asia-based refinery source. Gasoil imports to Singapore fell 69.96% over Aug. 1-7 to 65,732 mt, mainly from India at 64,159 mt and Malaysia at 1,572 mt, Enterprise Singapore figures showed. This marks the fifth straight week India has sent gasoil to Singapore, with volume rising more than doubling on week. Refiners in India typically export during the June-September monsoon period amid dwindling domestic demand as industrial and agricultural activities are hampered, trade sources said. Jet fuel\/kerosene exports almost halve on week Singapore remained a net exporter of jet fuel\/kerosene over Aug. 1-7, though outflows almost halved on the week to 56,852 mt. The decline comes from a high base with exports at a near three-month high of 90,537 mt in the previous week, the data showed. Jet fuel\/kerosene exports went mainly to the Netherlands at 27,077 mt. This was followed by New Zealand and Vietnam at 12,324 mt and 9,552 mt, respectively. Meanwhile, jet fuel\/kerosene inflows, mainly from Belgium and France, trickled in at just 40.35 mt. Asia's jet fuel demand growth is expected to be around 270,000 b\/d in H2 2024, which would eventually pull down the annual rate of demand growth in 2024 below 2023 levels, according to S&P Global Commodity Insights. \u201cAsian jet\/kerosene demand will maintain its upward momentum, growing by around 320,000 b\/d year over year in Q3 [2024] due to the summer travel season. Mainland China and Southeast Asia will continue to lead regional jet\/kerosene growth at a rate of 198,000 b\/d and 67,000 b\/d, respectively,\u201d said Wang Zhuwei, director of East of Suez Oil Market Research at Commodity Insights. ","headline":" Middle distillate stocks reach 3-year high of 11.99 mil barrels over Aug 1-7","updatedDate":"2024-08-12T01:05:01.000"},{"Unnamed: 0":162,"body":" Market valuations for Australian North West Shelf condensates cargoes loading in October was seen stable-to-lower, as the complex grapples with thin downstream margins coupled with more attractive naphtha prices, trade sources said. For the October-loading trading cycle, two 650,000-barrel cargoes of NWS condensates have been scheduled, stable on the month, market sources said. Oil major BP holds the first cargo for loading over Oct. 10-14, while Australia's Woodside Energy holds the second cargo for loading over Oct. 24-28. Valuations for October-loading NWS were heard at a discount ranging $7s\/b to $8\/b to Platts Dated Brent crude assessments, FOB. The Platts second-month naphtha swaps crack against Dubai crude swaps averaged minus $5.82\/b as of Aug. 8 Asian close, compared to an average of minus $9.65\/b in July, S&P Global Commodity Insights data showed. In the previous trading cycle, the last trade of the grade was the second and final 650,000-barrel cargo held by Chevron for loading over Sept. 28-Oct. 2 sold via a tender issued by Pertamina, at a discount in the high-$4s\/b to Platts Dated Brent crude assessments, CFR Tuban. \u201cTPPI bought up 1 of the NWS [in the previous cycle], so it seems that the refineries are pushing up the market instead of end-users,\u201d a trader said. Participants have emphasized that the recent improvement in naphtha cracks was not reflective of the market, attributing the strength in cracks to the decline in crude prices. The CFR Japan naphtha physical crack spread against front-month ICE Brent crude futures widened $16.28\/mt, or 23.66%, on the month to $85.05\/mt at the Aug. 8 Asian close, Commodity Insights data showed. \u201c[Market] might get some swing players support for October, but overall demand situation doesn\u2019t look like it will get stronger,\u201d a trader said, adding that \u201cfew splitters was heard to have reduced runs [in] late July.\u201d Trades sources continue to eye fresh pricing cues from Indonesian Pertamina's monthly condensate tender for October delivery, which closed Aug. 6, with validity until Aug. 8, along with QatarEnergy\u2019s monthly condensate tender for October loading which closes Aug. 14, with next-day validity. \u201cTwo Qatari cargoes is the minimum and the market can easily stomach 3-4 spot [condensate] cargoes. If nothing [in particular] happens [in the market], we should see a fairly stable market,\u201d a trader said. QatarEnergy previously sold two 500,000-barrel cargoes of low sulfur condensate for September loading to a trader and a South Korean buyer at discounts in the high $1s\/b to $2s\/b to the Platts front-month Dubai crude assessments on FOB basis, Commodity Insights reported previously. Naphtha complex pressured The Asian naphtha market was subdued on thin trading activity despite a slight uptick in olefin margins, sources said. Reflecting unviable olefin margins, the key CFR Northeast Asia ethylene-CFR Japan naphtha physical spread -- closely watched by petrochemical producers -- widened $55.38\/mt, or 38.83%, on the month to $198\/mt at the Aug. 8 Asian close, Commodity Insights data showed. The spread continued to remain below the typical breakeven level of $250\/mt for integrated producers and $300-$350\/mt for non-integrated producers. Conversely, \"naphtha prices seems to be better than condensate prices\" industry source said. In the latest spot activity for heavy full-range naphtha, South Kore's GS Caltex was heard seeking 25,000 mt of naphtha for H2 September delivery via a tender closing Aug. 7, with same-day validity. Meanwhile, Indonesia's Pertamina issued a tender previously seeking at least 22,000 mt of naphtha as a splitter feedstock for Sept. 14-16 delivery to TPPI Tuban. The tender closed July 24, with validity until July 29. \"The tender was awarded\", a company source said without revealing the awarded level. This is also likely a reissue of PT Kilang Pertamina's previous tender that sought the same volume of naphtha over the same delivery dates for TPPI Tuban, Commodity Insights reported earlier. ","headline":"Australia\u2019s Oct-loading NWS condensates market valuations seen stable to lower","updatedDate":"2024-08-12T00:43:25.000"},{"Unnamed: 0":163,"body":" US Gulf Coast high-sulfur fuel oil prices rose from a five-month low on Aug. 9, amid a drop in HSFO exports to the USGC from Mexico and consistent activity in the Platts Market on Close assessment process since the start of the month. There has been activity on the USGC HSFO bid side every day in August in the MOC, but no selling interest nor offers for the product, indicating supply impacts. Platts, part of S&P Global Commodity Insights, assessed USGC HSFO at $67.85\/b Aug. 9, up 86 cents from the five-month low of $66.99\/b seen Aug. 5. The outright price was previously lower at $66.31\/b on Feb. 29. \"[It] feels like most people have empty tanks from what I am hearing,\" an area source said and added that the cause of the supply tightness was Mexico moving barrels out of the region. A shipping source said July was very busy, and that August seemed busy so far as well. The same source said a major USGC HSFO supplier was exporting HSFO to the Amsterdam-Rotterdam-Antwerp hub in Europe, which meant less supply would go into the USGC. A USGC-based trader also said Mexican product was moving across the Atlantic to Europe and the Arab Gulf, rather than to the USGC. Kpler shipping data showed Mexico's HSFO exports to the USGC have decreased for four consecutive months since March. July USGC HSFO imports totaled 275Kt compared to 669Kt in March, according to Kpler shipping data. In addition, predictive shipping data showed Mexico's HSFO exports will continue to decrease in August as supply will be impacted. Historically, the majority of Mexican HSFO exports are delivered to the USGC, but recently a decent amount has been going to Asia and the Caribbean, Kpler shipping data showed. Although the USGC HSFO outright price reached a low in August, it has increased since. Market participants reported less HSFO supply from Mexico, which could further impact prices and cracks if it continues throughout the month. ","headline":"Mexico HSFO exports to USGC at a four-month decline; supply tightness increases","updatedDate":"2024-08-09T20:57:28.000"},{"Unnamed: 0":164,"body":" Crude oil futures settled higher Aug. 9, ending the week up around 4% as the market braced for a potential escalation in tensions in the Middle East. NYMEX September WTI settled 65 cents higher at $76.84\/b, and ICE October Brent climbed 50 cents to $79.66\/b. Markets remain in a wait-and-see mode regarding retaliatory strikes on Israel promised by the leadership of Iran and Lebanon-based Hezbollah. Cross-border shelling continues between Israel and Hezbollah, but so far there has been no escalation beyond fiery rhetoric. A ship -- widely reported to be a Greek-operated Suezmax tanker -- has emerged unscathed from four attacks within 24 hours in the Red Sea, the UK Maritime Trade Operations said Aug. 9 amid renewed threats from Yemen-based Houthi rebels to regional shipping. On Aug. 8, the US, Egypt and Qatar released a joint statement calling on Israel and Hamas to resume negotiations over a ceasefire and hostage-release delay. These diplomatic talks serve as an attempt to ease the heightened tensions in the region following the assassination of Hamas' leader Ismail Haniyeh previously. As the world still awaits responses from both sides as to their attendance in the talks, the supply concerns over Middle Eastern oil remain elevated, thus pushing prices upwards. Commenting on escalating tensions in the Middle East, Ole Hvalbye, a commodities analyst at Seb Research, said, \"While deeper involvement with Iran could theoretically disrupt their 1.7 million-barrel crude and condensate exports, OPEC+ spare capacity would likely offset this impact. The Strait of Hormuz remains a critical chokepoint for global crude and refined product shipping, accounting for roughly 20% of global shipments. However, a potential blockade is unlikely to persist due to significant international interests in the region.\" NYMEX September RBOB dipped 89 points to $2.3903\/gal, and September ULSD declined 1.81 cents to $2.3397\/gal. Russia reaffirms OPEC+ compensation plan Russia remains committed to its OPEC+ compensation plan , despite overproducing its quota by 67,000 b\/d of oil in July, the country's energy ministry said Aug. 9. In a statement, the ministry said its \"production in July has further decreased comparing to June, coming at 67,000 b\/d above the target levels.\" It blamed the overproduction on \"one-off supply scheduling issues\" and said its August and September levels would \"remedy this.\u201d Along with other serial overproducers Iraq and Kazakhstan, Russia submitted plans on July 24 to compensate for high crude output in recent months. The Russian plan covers overproduction in Q2 2024, when it pledged to implement deeper reductions to bring its quota in line with Saudi Arabia's. ","headline":" Crude climbs as Middle East tensions remain in focus","updatedDate":"2024-08-09T20:03:55.000"},{"Unnamed: 0":165,"body":" Brazilian independent onshore oil and natural gas producer PetroReconcavo continued to evaluate potential construction of gas treatment plants and other export infrastructure as part of a new resiliency plan aimed at ensuring operational continuity, CEO Jose Firmo said Aug. 9. PetroReconcavo expects to make a final investment decision on whether to expand its company-owned gas treatment facilities, including the potential construction of two plants, before the end of 2024, Firmo said during a conference call with analysts and investors. The plans include a plant at the Miranga cluster of onshore fields in Bahia state as well as a potential plant to serve its Potiguar Basin assets in Rio Grande do Norte state. The expansion would follow PetroReconcavo's startup of the UTG Sao Roque gas treatment plant in Bahia state, which started operations in June. The treatment plant has installed capacity to process up to 400,000 cu m\/d from the Mata de Sao Joao, Remanso, Jacuipe and Riacho Sao Pedro complexes of onshore fields in Bahia state, according to the company. \"The plant is operating within expected parameters,\" said Joao Vitor Moreira, PetroReconcavo's director for sales and new business. In addition, PetroReconcavo also completed work on a truck-export hub that would allow the company to export 100% of its Rio Grande do Norte oil output, Firmo said. PetroReconcavo prefers to export oil production by pipeline, but the truck hub offers the company an excellent secondary alternative, the executive added. The projects aim to insulate PetroReconcavo from technical and maintenance issues involving infrastructure operated by third-party companies, which undermined the company's output in late 2023 and early 2024, Firmo said. PetroReconcavo was forced to reduce oil and gas output after 3R Petroleum shuttered a refinery and gas treatment plant at the Guamare industrial complex in Rio Grande do Norte state, which is utilized by PetroReconcavo and other independent producers in the region. PetroReconcavo and 3R Petroleum are currently in talks to firm up infrastructure sharing, Firmo said. While the UPGN Guamare gas treatment plant primarily processes PetroReconcavo's output, the two companies are trying to come up with a technical and economic deal that works for both. \"Infrastructure sharing has always been known as something that needed to be done onshore Brazil,\" Firmo said. Drilling to expand PetroReconcavo also expects to accelerate drilling and workover campaigns at its onshore assets after a difficult start to 2024, Firmo said. Heavier-than-usual rains to start the year caused well failures and electricity shortages that required repairs, delaying efforts to expand drilling, according to the executive. \"Basically, we want to accelerate execution,\" Firmo said. \"We want to return to the production curve as soon as possible.\" Drilling programs will be boosted by the company's new PR-14 rig, which is the only onshore rig currently in operation in Brazil that can reach targets up to 5,000 meters deep, Firmo said. The rig completed the TIE-11 sidetrack well at the end of July, nearly tripling output to 822 b\/d. \"The PR-14 is going to transform our drilling capacity,\" Firmo said. In addition, PetroReconcavo expects two rigs hired out to partners in the first half of 2024 will return to drill internal projects, Firmo said. PetroReconcavo also is evaluating new drilling opportunities after reviewing workover plans that could bear fruit in the second half of 2024. \"Today, we have the equipment, people and programs for drilling and workovers we need to reach the maximum possible production curve,\" Firmo said. PetroReconcavo carried out 109 workovers in the first seven months of 2024, including 68 in the company's Potiguar assets and 41 in its Bahia assets. ","headline":"Brazil's PetroReconcavo evaluates onshore infrastructure buildout: CEO","updatedDate":"2024-08-09T19:57:49.000"},{"Unnamed: 0":166,"body":" Brazilian state-led oil company Petrobras expects to meet its 2024 production target of 2.8 million b\/d of oil equivalent, despite reduced investment spending and a series of unexpected technical issues that undermined output in the first half of the year, company executives said Aug. 9. \"We're working within our projections,\" said Wagner Victer, an adviser to Petrobras CEO Magda Chambriard, during a conference call with analysts and investors. \"We're within the average range and, certainly, will continue to meet the target in the second half of the year.\" According to Victer, Petrobras encountered a series of technical issues and unplanned production stoppages that affected oil and natural gas output in recent months. Victer also noted that Petrobras typically schedules a majority of its maintenance shutdowns and other work in the first quarter, when activity in Latin America's largest economy is weaker. More recently, Petrobras carried out maintenance work that affected production onboard the FPSO P-38 floating production, storage and offloading vessel anchored at the Marlim Sul field; the FPSOs P-73 and P-74 at the Buzios subsalt field; and issues at platforms operating at the Roncador heavy oil field, Victer said. Petrobras expects to compensate for the barrels lost to the maintenance shutdowns in the second half of the year in order to hit the production target, Victer said. In the second half of 2024, Petrobras expects to pump first oil from two new FPSOs that will start operations, executives said. The FPSO Marechal Duque de Caxias, which has installed capacity to produce 180,000 b\/d and process 12 million cu m\/d, will be installed at the Mero field in the Libra production sharing area in the second half of 2024, Petrobras officials said. The FPSO Maria Quiteria, meanwhile, will be installed at the Jubarte field in the so-called Parque das Baleias complex of offshore heavy oil fields. The FPSO Maria Quiteria has installed capacity to produce 100,000 b\/d and process 5 million cu m\/d. In addition, Petrobras also received approval from Brazil's National Petroleum Agency, or ANP, to increase output from the FPSO Almirante Barroso installed at the Buzios field to more than the vessel's installed capacity of 180,000 b\/d, Victer said. Improvements in gas-processing efficiency onboard FPSOs installed at the field have allowed the vessels to produce more than their installed capacity in recent years. Oil and natural gas output from subsalt fields could also get a boost from the startup of the Rota 3 offshore gas export pipeline and a gas processing plant under construction at the GasLub Itaborai complex outside Rio de Janeiro, Petrobras CFO Fernando Melgarejo said. Petrobras now expects to make the first gas available from the pipeline and plant by the end of the third quarter. Construction of the gas processing plant is in the final stages and Petrobras has started to pressurize the Rota 3 pipeline, Melgarejo said. The Rota 3 pipeline and GasLub Itaborai plant will inject about 21 million cu m\/d of fresh gas supplies into Brazil's domestic market when it starts operations. Investment retreat The second-half growth, however, is expected despite Petrobras' plans to reduce investment spending in 2024, Melgarejo said. Petrobras previously planned outlays of $18.5 billion in 2024 under the company's $102 billion investment plan for 2024-2028, but that was reduced to $13.5 billion-$14.5 billion. Despite the reduction, that would be up from the $12.7 billion invested in 2023. The spending cuts, however, will not affect Petrobras' production curve, Melgarejo said. The reductions were attributed to schedule changes in FPSO deliveries, with the second floating production units planned for the Atapu and Sepia subsalt fields now outside the scope of the current 2024-2028 investment plan, Renata Baruzzi, the company's director for engineering, technology and innovation, said. The vessels are expected to enter operations in 2029-2030. Petrobras also utilized its fleet of drilling rigs to carry out maintenance work and well interventions rather than exploration and development drilling, Baruzzi added. That meant more operating expenses. In addition, Petrobras delayed a maintenance shutdown at the Refinaria do Nordeste, or RNEST, to coincide with construction work that will be carried out in 2025. The spending cuts will not affect Petrobras' plan to rebuild reserves through greater exploration efforts, with the company evaluating mergers and acquisitions opportunities outside Brazil, Melgarejo said. Petrobras is still awaiting environmental permits to drill in Brazil's equatorial margin, but could be forced to search elsewhere if the Brazilian Institute for the Environment and Natural Resources, or IBAMA, fails to approve. \"The fewer opportunities we see in Brazil, the greater the need to move internationally,\" Melgarejo said. Petrobras was primarily focused on South America, the US Gulf of Mexico and the west coast of Africa, where the company is making a play for a stake Galp Energia's Mopane discovery offshore Namibia. Petrobras, however, is feeling more confident about winning permits from IBAMA, executives said. Since the work-to-rule movement started in January, Petrobras has received 25 licenses and approvals from IBAMA, Clarice Coppetti, Petrobras' director for corporate relations, said. IBAMA's unionized workers are currently voting on the government's latest proposal, with many assemblies approving the offer. \"We have a very positive outlook on the licenses, that they are close to being emitted,\" Melgarejo said. \"We're optimistic.\" ","headline":"Brazil's Petrobras confirms to meet 2024 production target of 2.8 million boe\/d","updatedDate":"2024-08-09T19:14:42.000"},{"Unnamed: 0":167,"body":" Service operator Solaris Oilfield Infrastructure felt the effects of the recent lull in oil and gas drilling activity in the US, resulting in fewer utilized sand and top fill systems and a decrease in fully utilized frac crews, company executives said Aug. 9. \"We saw the anticipated choppiness in US drilling and completions activity we referenced in our last earnings call, mostly due to a continued activity decline in natural gas-exposed basins as a result of low gas prices,\" founder and CEO William Zartler said during the company's second-quarter earnings call. \"Most of this decline appears to be behind us now and we saw stabilization in gas-exposed activity and continued strength in oil basins such as the Permian.\" However, the lull left an impression on the company's equipment rental segment during the second quarter. Solaris operated 92 fully utilized systems during the second quarter, which include sand and top fill systems. Total fully utilized systems were down 10% from Q1 and down 15% from the same period last year. The Texas-based company followed an average of 56 industry frac crews on a fully utilized basis during the second quarter, compared with 64 industry frac crews in Q1. Looking ahead, executives expect US land completion activity to remain mostly flat during the third quarter \"as natural gas weakness appears to have bottomed, and oil prices continue to support stable activity in basins such as the Permian,\" CFO Kyle Ramachandran said. Zartler noted that while there's been some stabilization, he doesn't expect gas activity to pick up by the fourth quarter but probably early 2025, suggesting there won't be a \"radical\" shift in activity this year. \"It just feels like this [frac] market has been pretty stable, and I think the election may have something to do with, but more likely, it's about capital spending from the upstream sector,\" he said. On July 9, the company announced its plan to acquire Mobile Energy Rentals LLC, a power distribution services company. The move aims to diversify the company's portfolio into the \"growing distributed power market,\" the company notes in an earnings press release. Solaris remains on track to close on the acquisition during the third quarter of this year. ","headline":"Solaris Oilfield Infrastructure feels pinch of lull in oil, gas drilling activity in Q2","updatedDate":"2024-08-09T19:10:28.000"},{"Unnamed: 0":168,"body":" Texas-based Excelerate Energy is in discussions with Southcentral Alaska utilities on a plan to import LNG to the region beginning in 2028, company officials told investors in an earnings call. The company would use a floating storage regasification unit to bring LNG to a terminal in Cook Inlet, in southern Alaska, Excelerate CEO Steven Kobos told investors during the call Aug. 8. \u201cExcelerate is in advanced discussions with local utilities in Southcentral Alaska for the development of an integrated LNG import terminal in the lower Cook Inlet region,\u201d Excelerate said in a statement. Kobos would not identify the utilities Excelerate is working with, but Enstar Natural Gas, the regional gas utility, has been taking the lead in an LNG import plan with electric utilities that also use gas, which include Anchorage-based Chugach Electric Association and Matanuska Electric Association, which serves communities north of Anchorage. The utilities' planning is at an advanced stage and Enstar has told state regulators it intends to have an LNG supply contract in place by the end of the year. The utilities also said they intend to have decisions in place for imports \u201cwithin a couple of months,\u201d according to a source within utility group who is familiar with the plan. Enstar said it is considering development of an import facility at Nikiski, where there are dock facilities available at a mothballed fertilizer and ammonia plant owned by Agrium, or in Upper Cook Inlet at Port MacKenzie, a facility owned by the Matanuska Susitna Borough. Utilities in the region rely on natural gas to fuel space heating and most power generation, but production will be declining in gas fields in Cook Inlet, the state Division of Oil and Gas has warned. Hilcorp Energy, the major regional gas producer, has warned utilities that it will not be able to renew gas supply contracts for utilities as they expire. Because there is no physical connection with gas supply infrastructure in the continental US, Alaska has been dependent on local gas supplies in Cook Inlet for most of its energy since the 1960s. The issue has urgency because half of Alaska's population lives in Southcentral Alaska communities. There is 35 Tcf of gas stranded on the North Slope, 800 miles north, but a plan for a $40-billion-plus pipeline that would take that gas to market is on hold. Cook Inlet has potential for new gas discoveries, but the economics are tough given high costs and a limited regional market. State officials worry that LNG imports, once they begin, will undercut the efforts of explorers now hoping to develop known gas deposits in the Inlet, but they concede utilities must have a gas supply backup plan. For years Alaska exported gas, as LNG, from Cook Inlet to Japan, but declining gas reserves led to an end of shipments in 2016. ","headline":"Excelerate Energy in talks to import LNG to Southcentral Alaska","updatedDate":"2024-08-09T19:01:38.000"},{"Unnamed: 0":169,"body":" The environmental costs of deepwater ports are too severe and should be a greater consideration of the government's approval of future projects, a group of United States congressional Democrats told the Biden administration. The United States Department of Transportation's Maritime Administration should pause and reconsider its approval of the Enterprise Product Partners' Sea Port Oil Terminal (SPOT) and change the way it assesses permits for similar pending projects, climate-focused Democrats wrote in a letter to MARAD administrator Adm. Ann Phillips Aug. 9. \"Deepwater oil export terminals and their supporting infrastructure threaten the health and safety of frontline coastal communities and marine ecosystems, exacerbate climate change, and prolong fossil fuel dependence,\" according to the letter, co-authored by Senator Ed Markey, Democrat-Massachusetts and chair of the Senate Environment and Public Works Clean Air, Climate, and Nuclear Safety Subcommittee; and US representative Raul Grijalva, Democrat-Arizona, the ranking member of the House Natural Resources Committee. It was signed by 20 other Democratic lawmakers in both the House and Senate. \"MARAD should, therefore, pause all new and pending deepwater port licensing decisions and reopen the record of decision for a recently approved oil export facility,\" the co-signors said. \"During the pause, MARAD must update its approval criteria based on environmental justice, climate, and public health impacts to more accurately determine whether new deepwater oil projects are in the national interest.\" A spokesperson for MARAD and the US DOT could not be reached for comment. Markey's Senate office could not be reached for comment. Targeting SPOT The Aug. 9 letter is the latest in an intraparty rift over Enterprise's new deepwater oil port. Situated 35 miles off the coast of Brazoria, Texas, in the Gulf of Mexico, the deepwater port is an offshore platform that aims to optimize VLCC loading and expand export capacity in the face of ever-increasing global demand for US crude. The terminal would be able to load 2 million b\/d, Enterprise has said, utilizing two 46-mile pipelines carrying crude from the shore to the 115-foot deep terminal. Initially planned for 2025, it is expected to become operational by late 2026 or early 2027. The project survived multiple legal challenges from environmentalist groups. In April 2024, after a federal appellate court upheld the administration's argument that the port would be in the US national interest, MARAD awarded a final license it had first approved in 2022. In its April statement, MARAD said the project \"would make the transport of oil safer for the public and the environment.\" In an April 9 statement, Enterprise CEO Jim Teague said SPOT's new technology and reduction of ship-to-ship transfers would \"reduce operational risks\" and \"significantly reduce emissions.\" Environmentalists have argued that the project would lead to more local air pollution and oil spills, as well as allow an overall increase in the production and sale of fossil fuels -- framing approval as a betrayal of US President Joe Biden's climate and environmental justice agendas. In a 2023 study, the Center for Biological Diversity said carbon emissions from fossil fuel projects would \"undermine\" the gains of Biden's signature Inflation Reduction Act. Markey and his colleagues echoed those arguments Aug. 9, arguing that failing to consider broader environmental impacts is not in the \"national interest.\" \"One of President Biden\u2019s first executive orders called on federal agencies to suspend, rescind, or halt actions that conflict with goals to protect public health and the environment, advance environmental justice, bolster resilience, and confront the climate crisis,\" the letter said. \"Broadening MARAD\u2019s interpretation of national interest to more fully include environmental justice, climate, and public health considerations -- in addition to their existing requirement to assess the impact on energy sufficiency and environmental quality -- would be consistent with President Biden\u2019s directive.\" Other ports pending While the Democratic letter authors hope MARAD will still pause and reconsider SPOT's approval, they also took aim at three pending deepwater terminal projects: Phillips 66 and Trafigura's joint project Bluewater, Energy Transfer's Blue Marlin offshore port and Sentinel Midstream's GulfLink export terminals, all of which would operate off the coast of Texas in the Gulf of Mexico. \"While SPOT alone would cause great environmental harm, when combined with the three other pending oil export facilities, the results would be devastating,\" they said. \"Altogether, the crude oil from SPOT, Gulflink, Bluewater, and Blue Marlin would generate 24 billion metric tons of greenhouse gases over 30 years, equivalent to the annual output of nearly 6,170 coal plants.\" In its approval of SPOT, MARAD cited its own analysis that the terminal would merely optimize transport of already existing crude for export, rather than increase it. All three terminals remain in the preliminary approvals phase. Phillips 66 and Trafigura first submitted a port license application in 2019, which was granted in 2020 but revoked by the Biden EPA in 2022 over approved pollution levels. S&P Global Commodity Insights analysts expect US annual output growth of roughly 387,000 b\/d in 2024 to an average 13.31 million b\/d, and output growth of 739,000 b\/d in 2025. \"Expanding domestic oil production and export is inconsistent with the national interest,\" the lawmakers' letter said. \"These deepwater oil ports would represent a sharp expansion in exports and production.\" ","headline":"Warning of climate damage, Democrats ask Biden to pause deepwater oil port approvals","updatedDate":"2024-08-09T18:53:18.000"},{"Unnamed: 0":170,"body":" Inventories of jet fuel and kerosene in the Amsterdam-Rotterdam-Antwerp refining hub fell 45,000 mt to 882,000 mt in the week to Aug. 8, data from market research company Insights Global showed. This puts ARA stocks 23.87% higher than the same year-ago week, Insights Global data showed. The draw in stocks comes as the European jet fuel market experiences strong seasonal aviation demand. \"The market is tricky right now; lots of supply, but everything is getting absorbed as there's strong demand,\u201d a source said, adding that he's waiting to see \u201chow much of an impact refinery maintenance from September onwards will have on the market\u201d. Due to the strong supply, the market has stayed in contango this summer, with Platts assessing the Jet M1 vs M2 differential swaps spread at minus $2.75\/mt on Aug 9. Platts is part of S&P Global Commodity Insights. Going forward, \u201cwhether the jet fuel market will stay in contango will depend on supply and demand in next few months, but also on diesel cracks,\u201d the source added. Imports of jet fuel from East of Suez into Europe are set to drop by 100,000 mt in August, according to S&P Global Commodities at Sea shipping data retrieved Aug. 9. The dip comes after three straight months of heavy imports at 1.7 million mt each. Imports from Kuwait, Saudi Arabia and the UAE are expected to drop in August to 672,400 mt, 171,500 mt and a complete absence of flows, respectively, while flows from India are set to increase from 396,100 mt to 580,700 mt on the month in August. Inflows from China are expected to dip too, after seeing volumes of 201,700 mt in July, while flows from South Korea are expected to rise from 135,600 mt to 147,500 mt. China's oil product exports fell 7.1% month on month to a three-month low of 4.98 million mt in July, data from the General Administration of Customs showed Aug. 7. ","headline":"ARA jet fuel, kerosene stocks see second week of draws amid strong summer demand","updatedDate":"2024-08-09T18:00:31.000"},{"Unnamed: 0":171,"body":" Portuguese energy company Galp restarted offering 380 CST high sulfur fuel oil in the domestic ports, the company said Aug. 9. The head of the company's bunkering team, Pedro Ornelas, informed customers via email Aug. 9 that the company was offering 380 CST HSFO at the ports of Lisbon, Sines, and Setubal. The company had stopped offering the high sulfur grade as it transitioned to offering very low sulfur fuel oil as part of the IMO 2020 marine fuel requirements. But rising demand for HSFO, amid an increasing number of scrubber-fitted ships, made the Portuguese bunker supplier restart offering the grade. The company had announced in May during its annual Atlantic meeting that it was planning to restart HSFO supply from the beginning of August. The situation in the Red Sea, with vessels diverting around Africa to avoid Houthi attacks , played a key role in lengthening voyage times and raising bunkering demand. Vessels that choose these longer trips are mainly container ships, most of which are equipped with scrubbers, which has pushed up demand for HSFO, industry sources said. ","headline":"Galp restarts 380 CST HSFO bunker supply in Portuguese ports amid rising demand","updatedDate":"2024-08-09T17:57:20.000"},{"Unnamed: 0":172,"body":" Pembina Pipeline Corp. started up last quarter an expansion of its light oil, NGL and condensate intra-Western Canadian Sedimentary Basin pipeline, providing incremental well-head to market solutions to producers, CEO Scott Burrows said August 9. \u201cPhase VIII of the Peace Pipeline is now in service and will allow segregated service for ethane-plus and propane-plus NGL mix from Gordondale, Alberta, which is centrally located within the Montney trend, into the Edmonton area for market delivery,\u201d Burrows said on the company\u2019s second quarter 2024 earnings webcast. \u201cWe see lots of liquids production that is growing significantly in the WCSB and those volumes are seeking markets. The latest Peace Pipeline expansion will move those barrels to the Edmonton market,\u201d he said. At Edmonton, NGL and condensate producers could transfer their molecules for fractionation and processing at facilities in the Alberta Heartland Industrial Area which is also home to petrochemical plants, while light oil producers will have options to load crude on to dual mainlines like the 300,000 b\/d Trans Mountain and the 590,000 b\/d Trans Mountain Expansion, or put into storage or even transfer to TC Energy\u2019s 600,000 b\/d Keystone and the 3 million-b\/d Enbridge\u2019s Mainline systems. Phase VIII includes new 10-inch and 16-inch pipelines, totaling nearly 150 kms (96 miles) in the Gordondale to La Glace corridor of Alberta, as well as new mid-point pump stations and terminal upgrades located throughout the Peace Pipeline system, Pembina said in its release, stating the expansion has added about 235,000 b\/d of incremental capacity between Gordondale, Alberta and La Glace, Alberta, as well as some 65,000 bpd of capacity between La Glace, Alberta and the Namao hub near Edmonton, Alberta. The current total capacity of the Peace Pipeline and the fellow Northern Pipeline systems is about 1.1 million b\/d and Pembina has the ability to add another 200,000 b\/d of capacity to its market delivery pipelines from Fox Creek to Namao through the relatively low-cost addition of pump stations on these mainlines, bringing the total throughput to 1.3 million b\/d, Burrows said. \u201cThere are a few options for us. In Alberta, we will focus on optimizing volumes through the use of pumps, while at North East BC [British Columbia] we can add more capacity as demand is set to increase with the start of the LNG Canada plant,\u201d he said. The Shell-led 12 million mt\/year LNG Canada is due to start warming up its first train this fall in preparation for first exports early 2025. Revised 2024 capex Pembina has revised its 2024 capital expenditure to C$1.3 billion ($947 million), representing a C$140 million increase as it pursues growth projects to meet the growing midstream and gathering and processing demand of its customers, Burrows said. Last quarter, the company handled pipelines volumes of 2,716 million b\/d of oil equivalent NGL, condensate and crude oil, a 11% increase compared with the same quarter in the prior year, it said. \u201cMomentum across the Canadian energy industry remains strong, and we continue to observe robust year-over-year volume growth in the WCSB, which is reflected in our expectation for annual growth of nearly 6% in conventional pipelines volumes and 4% in gas processing volumes,\u201d he said, adding the start of TMX, LNG Canada and other West Coast LNG projects too will drive demand further. Pembina is an equity partner in the planned 3.3 million mt\/year Cedar LNG project in British Columbia for which a final investment decision was taken this summer, Burrows said. New NGL pipeline, RFS IV expansion Last quarter, Pembina filed its project application for the 56-mile, 16-inch-diameter Taylor to Gordondale project (an expansion of the Pouce Coupe system) with the Canada Energy Regulator, it said. Besides installing the pipeline, the developer will also upgrade the Taylor tank farm and a Pouce Coupe block valve, CER said without providing details on the capacity and the timeline for constructing it. The project also includes a booster, mainline pumps, metering equipment, pipeline inspection gauge launchers and receivers and other associated pipeline assemblies, Pembina Pipeline said on its website. Separately, Pembina is constructing a new 55,000 b\/d propane-plus fractionator at its existing Redwater Complex in central Alberta, Burrows said. The estimated project cost has been revised to C$525 million from an earlier budget of C$460 million to reflect changes in the project\u2019s scope and also higher equipment, material and labor costs in light of Alberta construction activity, he said. \u201cWe have secured additional contracts for the base plant capacity that includes RFS phase I, II and III. Customer demand for fractionation capacity post-2026 remains robust and ongoing contracting efforts have been constructive, allowing Pembina to improve project economics relative to expectations at the time RFS IV was originally sanctioned,\u201d Burrows said. Engineering and procurement activities continue, with onsite construction underway last quarter. RFS IV is expected to be in-service in the first half of 2026, the company said. ","headline":"Pembina starts up expansion of its intra-basin Canadian light oil\/NGL pipeline","updatedDate":"2024-08-09T17:42:04.000"},{"Unnamed: 0":173,"body":" Argentina\u2019s state-run energy YPF plans to sell or return to the state 20 more mature conventional blocks after recently reaching deals to sell 15 blocks and getting closer to selling others in a latest move to focus on its more profitable Vaca Muerta shale assets, CEO Horacio Mar\u00edn said Aug. 9. The 20 blocks are located in the southern provinces of Santa Cruz and Tierra del Fuego, and the negotiations have begun with the state-owned oil companies there for taking them back, he said on a conference call with investors. If they are not reverted, they will be considered for selling to private companies, he added. YPF, the country\u2019s biggest oil and natural gas producer, began divesting its non-core assets early this year to focus on Vaca Muerta, one of the world\u2019s largest shale plays. The first sales agreements were reached Aug. 5 for 15 blocks in the provinces of Chubut, Mendoza, Neuqu\u00e9n and R\u00edo Negro out of a total of 55 now on the sales block. Deals for some of the remaining 40 are under negotiations, Mar\u00edn added. \u201cWe want to close the deals for all the blocks by year-end,\u201d he said. Mar\u00edn, who doubles as YPF\u2019s chairman, said the divestment will allow the company to \u201creallocate resources to our most profitable assets located in Vaca Muerta.\u201d Vaca Muerta, in northern Patagonia, costs less to develop in terms of output, in effect boosting its production per dollar invested. The formation is driving YPF's oil and natural gas production growth and boosting its export potential, with projects in the works to export up to 800,000 b\/d of crude by 2028 and up to 120 million cu m\/d of gas by 2031. That would be up from Argentina\u2019s total exports of 168,000 b\/d of crude in the first half of this year and some 5 million cu m\/d of gas, according to industry and government data. Boosting shale output Mar\u00edn said YPF\u2019s goal for shale oil production is to reach 140,000 b\/d by the end of this year, up from 127,000 b\/d Aug. 8. \u201cThis is totally our focus right now,\u201d he said of Vaca Muerta. Indeed, YPF\u2019s shale oil production increased 20% to 113,800 b\/d in the second quarter of this year from 94,600 b\/d in the year-earlier quarter, offsetting a 7.3% decline in conventional output and a 12% plunge in tight oil production to boost its total crude output 3.2% to 248,800 b\/d from 240,900 b\/d over the same period, according to company data. The growth in shale output allowed the company to step up exports by 25% via a 110,000 b\/d pipeline to Chile, Mar\u00edn said. YPF has said it will redirect its investment from the conventional assets it is selling to invest in boosting output in Vaca Muerta and building takeaway capacity from the play with the goal of taking its portfolio to 80% Vaca Muerta and 20% conventional from a current 50\/50. Palermo Aike YPF is also testing Palermo Aike, a shale play in southern Patagonia, and the initial signs from a first well appear promising, Mar\u00edn said. \u201cIt has very good pressure,\u201d he said of the well. The initial production rate is 1,000 b\/d, he added. However, Mar\u00edn said that the content still has to be determined, adding that it would take another few weeks to see if it is oil. YPF is testing Palermo Aike with Argentina-based Compa\u00f1\u00eda General de Combustibles. The play is considered a smaller version of Vaca Muerta but easier to frack, which compensates for the lower quality of the rock in terms of cost of development vs output. Palermo Aike is also closer to the Atlantic ocean for exporting supplies through existing facilities that have for years handled shipments of heavier conventional crude. ","headline":"Argentina\u2019s YPF to offload more conventional assets to focus on Vaca Muerta","updatedDate":"2024-08-09T17:26:47.000"},{"Unnamed: 0":174,"body":" Brazilian independent onshore oil and natural gas producer PetroReconcavo registered an 5.6% year-on-year drop in output in July, as natural declines offset drilling and workover programs at mature fields, according to the company's latest production report. PetroReconcavo pumped an average of 26,883 b\/d of oil equivalent in July, down from 28,474 boe\/d in July 2023, the company said Aug. 8. July's production also tumbled 0.2% from 26,930 boe\/d in June. The latest production slide came amid natural declines from new wells drilled at onshore fields, including the Boa Esperanca and Lorena fields in PetroReconcavo's Potiguar assets and the Miranga and Remanso fields in Bahia, the company said. PetroReconcavo, however, continued to ramp up well interventions and workovers, completing 20 projects in July. So far in 2024, PetroReconcavo carried out 109 workovers in the first seven months of the year, according to the company. That includes 68 in Potiguar assets and 41 in the company's Bahia assets. Drilling activity will be supported in the second half of 2024 by the recent commissioning of the company's PR-14 rig, which can reach onshore reservoirs that are up to 5,000 meters deep, PetroReconcavo CEO Jose Firmo said during a conference call Aug. 9. That makes it the deepest-drilling rig at work onshore Brazil. The PR-14 rig completed drilling the TIE-11 sidetrack well at the Tie field, which is pumping more than 800 b\/d, at the end of July. Despite the year-on-year output decline, PetroReconcavo maintained monthly production near levels registered before the company confronted heavier-than-usual seasonal rains and maintenance-related shutdowns of important infrastructure operated by rival producer 3R Petroleum, the report showed. 3R Petroleum carried out maintenance work at the Guamare industrial complex in Rio Grande do Norte state, closing a gas-processing plant and refinery in the fourth quarter of 2023 that forced PetroReconcavo to limit output in the region until early January. PetroReconcavo CEO Jose Firmo said previously that PetroReconcavo expected to return to pre-maintenance production levels of about 27,000 boe\/d by May. Potiguar slide Production from PetroReconcavo's Potiguar assets tumbled for a third-consecutive month in July, the production report showed. The tumble was attributed to declines in new production and workover wells at the Boa Esperanca and Lorena fields. New wells were drilled at Boa Esperanca and fracturing was undertaken at Lorena in June, according to the company. Gas output from the region, meanwhile, was stable, PetroReconcavo said. PetroReconcavo's Potiguar assets pumped 13,243 boe\/d in July, down 15.9% from 15,765 boe\/d in July 2023, the company said. July's production also fell 2.3% from 13,548 boe\/d in June. The company's Potiguar Basin assets include 31 production fields, with 29 fields directly operated by PetroReconcavo and two operated by Mandacaru Energia. PetroReconcavo's mature fields in Bahia state once again led gains in July, according to the company. The new TIE-11 production well at the Tie field offset output lost to workovers at the Remanso and Miranga clusters of onshore fields. Gas output, meanwhile, advanced with the return of several production wells and recent improvements in compression systems at the Miranga cluster. The Bahia production assets produced 13,639 boe\/d in July, up 7.3% from July 2023, PetroReconcavo said. July's production also rose 1.9% from 13,382 in June. PetroReconcavo's Bahia production cluster includes the BTREC, Remanso, Miranga, Tie and Tartaruga groups of fields. ","headline":"Brazil's PetroReconcavo July oil, gas output falls nearly 6% on mature-field declines","updatedDate":"2024-08-09T17:21:47.000"},{"Unnamed: 0":175,"body":" Diesel and gasoil stocks in the Amsterdam-Rotterdam-Antwerp hub rose 2.88% to 2.071 million mt in the week ended Aug. 8, the first build of more than a percentage point over the previous seven weeks, Insights Global data shows. The build puts stock levels up less than a percentage point on the year, with levels still considered relatively low following multiple consecutive weeks of draws that ran contrary to market expectations for the season and strong imports into Europe. \u201cEveryone saw quite a hefty arrival program for August and the anticipation was that this would really cause a significant build in ARA,\u201d said a source. \u201c[However], it looks like the majority of arrivals found a welcoming home somewhere, so the build is not as spectacular as most people expected.\u201d Europe is currently scheduled to receive 1.885 million mt of diesel and gasoil import volumes from the US, according to S&P Global Commodities at Sea data Aug. 9. If all volumes land, this would be a record high volume in history. Strong imports are expected from the Middle East as well, with spike in fixing activity being partly owed to a pivot to larger crude oil tankers to transport diesel to economize logistics costs around the Cape of Good Hope, which has increased import volatility week to week. As the majority of vessels continue to avoid the Red Sea, high freight rates for conventional 75,000 mt large-range product carriers have spurred traders to clean out 280,000 mt very large crude carriers to transport products, offering almost four times the cargo volume. Two VLCCs are set to discharge diesel in Rotterdam in the coming month, CAS data showed, with the Plata Glory and Landbridge Glory expected to arrive from the UAE. Another VLCC, the Nissos Kea, was due to arrive in Rotterdam from Saudi Arabia Aug. 9 but appeared to reroute to Malta. In addition, market participants also suggested that the upcoming transition to winter specification diesel in September was complicating the positive storage economics suggested by an ongoing contango in the ICE LSGO prompt structure. \u201cEven though the structure of the market tells you that you should be able to store the product in tank, if it\u2019s not the right quality there is no point storing it,\u201d said a second source. Platts, part of S&P Global Commodity Insights, assessed the ICE LSGO prompt intermonth spread at a $3\/mt contango Aug. 9, although the spread could see some volatility ahead with the upcoming expiry of the ICE LSGO August contract Aug. 12. \u201cFrom the US, you\u2019ll get winter quality [diesel] and this is the product that can go into tanks and be used during winter but not all the product that is coming meets winter specifications,\u201d added the second source. ","headline":"ARA diesel, gasoil stocks rise 2.88% on week: Insights Global","updatedDate":"2024-08-09T16:37:22.000"},{"Unnamed: 0":176,"body":" Nigeria\u2019s government plans to spend $500 million (Naira 800 billion) on supporting its transition to compressed natural gas (CNG), presidential spokesperson Bayo Onanuga announced via X Aug. 9. Bold spending plans by the government are intended to deflate the cost of living by helping Nigerians to switch to CNG from gasoline to power their cars, reducing the country\u2019s import reliance on expensive motor fuel. In new details shared by Onanuga Aug. 9, the government has targeted over 100 new CNG filling stations to be rolled out across Nigeria by May 2025 through its collaboration with the retail arm of Nigeria\u2019s state oil firm, NNPC, and Nigerian Oil and Gas companies NIPCO and Bovas. In July, NNPC revealed that it had already commissioned 12 of the 100 planned CNG filling stations in Abuja and Lagos, pledging to also build three liquefied natural gas (LNG) filling stations in Ajaokuta to support its operations. The government has aimed for 1 million cars to be converted into CNG vehicles by 2027, with 250,000 to be converted within the year. New targets appear to dial back on previous goals to make 10 million gasoline-powered cars capable of running on CNG by 2027, a lag which NNPC CEO Mele Kyari acknowledged in July. \u201cIs it late? Yes, but we will make progress,\u201d Kyari said in a July 5 statement. \u201cWe will cover the gap in order to ensure that the volatility we see with Premium Motor Spirit (petrol) does not apply to gas,\u201d he said. According to government figures, 2.5 million vehicles on Nigeria\u2019s roads currently run on diesel and CNG, a figure dwarfed by 10 million gasoline-powered vehicles and amounting to only 20%. To address affordability concerns, commercial and rideshare vehicles should be made available either for free or at a heavy discount, while 2.8 million cu m of domestic gas per day should be offered at a 40-70% concession to consumers at the pump, Onanuga shared. The government also hopes to attract over $250 million in new investment in the CNG industry by 2025 to supplement its own financing. The push to develop the CNG sector comes in sync with Nigeria\u2019s first major step into the downstream refining space, which has promised to end its import dependency for gasoline. After beginning production earlier this year, Nigeria's giant 650,000 b\/d Dangote refinery has yet to produce its first gasoline, leaving markets attentive for what would be a major milestone for the new plant. The refinery could take until 2027 to reach expected steady-state capacity of some 327,000 b\/d gasoline, according to S&P Global Commodity Insights analysts. Meanwhile, continued import reliance has kept on straining public finances, as the devaluation of Nigeria\u2019s naira has pushed import costs higher and caused the government to plough money into expensive subsidies to cushion consumers . According to S&P Global Commodities at Sea data, Nigeria imported some 132,000 b\/d of gasoline in July, down from a 2023 average of 218,800 b\/d. ","headline":"Nigeria commits $500 million to support its transition to compressed natural gas","updatedDate":"2024-08-09T16:27:54.000"},{"Unnamed: 0":177,"body":" Israel is aiming to choke off Iran's fundings for its overseas proxy organizations by targeting 18 oil tankers transporting Iranian oil in the country's first publicly announced shipping sanctions, government officials told S&P Global Commodity Insights amid heightened tensions in the Middle East. On Aug. 6, Israel\u2019s National Bureau for Counter-Terror Financing, part of the Ministry of Defense, announced \u201cseizure orders\u201d for the ships with a total capacity of nearly 1.88 million dwt to thwart \"the activity of a terrorist organization.\" This refers to the utilization of those ships by Iran's Quds Force to ship Iranian crude to Syria for refining and sell refined products to external buyers, with revenues from the sales used to fund Hezbollah, Hamas and the Houthis, according to NBCTF officials. The Houthis have claimed to attack more than 100 ships in the Red Sea and Gulf of Aden in support of the Palestinians since the Israel-Hamas war broke out Oct. 7, 2023, while Hezbollah and Israel have also exchanged cross-border fire. An Israeli official said this was the first time that sanctions related to the shipping industry were issued, adding that \"international security and, in this case, international maritime security is very important.\" Data from S&P Global Commodities at Sea , which tracks 12 of the 18 ships, suggests the targeted tankers have been trading in international markets with recorded loadings from not just Iran but also Russia, Iraq, the UAE and other countries. Their actual destinations could be mostly under the radar: S&P Global Maritime Intelligence Risk Suite data shows 15 of the 18 ships are confirmed or suspected to have turned off their ship-tracking system during their operations in the past two years. Enforcement The NBCTF official said Israel will take a \"proactive\" approach in enforcing the seizure orders by partnering with the US and European countries to ask maritime industry participants, including bunker suppliers, ship managers, and other players, to not service the ships. Currently, just five of those ships are sanctioned by Western authorities. Two of them are covered by members of the International Group of P&I Clubs, which dominate the maritime third-party liability insurance market. \"We encourage our [maritime] stakeholders to maintain the international maritime security, which is also very, very important for them,\" the official said. NBCTF declined to comment on whether the Israeli navy will physically arrest the ships if they sail across East Mediterranean, citing the sensitivity of the matter. Iran and Hezbollah have vowed to retaliate against Israel after Israel killed leaders of Hezbollah and Hamas. ","headline":"Israel issues sanctions against 18 oil tankers to thwart Iran's funding for overseas allies","updatedDate":"2024-08-09T15:50:59.000"},{"Unnamed: 0":178,"body":" Argentine pipeline operator Oleoductos del Valle said late Aug. 8 it has teamed up with Trafigura on a $25 million project to build a pipeline to increase deliveries of Vaca Muerta crude to the Singapore-based commodities company\u2019s oil refinery in the country and an Atlantic port for exporting. The 14-inch-diameter pipeline run for 11 km (6.8 miles) from a connection to Oldelval\u2019s backbone pipeline to Trafigura\u2019s 30,000 b\/d refinery in Bah\u00eda Blanca, a port city in southern Buenos Aires province, Oldelval said in a statement. Oldelval said the project will start this month and be completed next year. This will improve crude supplies for the refinery, the sixth largest in Argentina, by bringing in supplies directly from Vaca Muerta in the country\u2019s southwest, the company added. The project will also increase the capacity to export Medanito, a sweet light crude produced in Vaca Muerta, via Puerto Rosales on the outskirts of Bah\u00eda Blanca, Oldelval said. Vaca Muerta, one of the world\u2019s biggest shale plays, is leading a surge in oil production in Argentina, boosting its export capacity. In June, the play in the country\u2019s southwest produced 94% of the 401,000 b\/d of crude in Neuqu\u00e9n, home to most of its in-production fields, up 25% from the year-earlier period. That offset declines in conventional fields elsewhere in the nation to increase national output 6.5% to 660,414 b\/d over the same period, according to data from the Energy Secretariat. The production growth is boosting export potential given that local demand is averaging 525,000 b\/d. The country\u2019s oil exports shot up 45% to 168,000 b\/d in the first half of this year from 116,000 b\/d in the year-earlier period, according to data from Econom\u00eda y Energ\u00eda, a consulting firm. ","headline":"Argentina's Oldelval teams up with Trafigura to build Vaca Muerta crude pipeline","updatedDate":"2024-08-09T15:40:29.000"},{"Unnamed: 0":179,"body":" NuVista Energy has recently reached new record condensate, NGL and natural gas output of 88,000 b\/d of oil equivalent on the back of strong new well performance at its acreages in the Western Canadian Sedimentary Basin, with the expecting monthly otput volumes to exceed 90,000 boe\/d \u201cat some point\u201d in the second half of 2024, it said. \u201cDue to the unusually long stretch of hot weather in Alberta, we have incurred cooling restrictions in July and these have had an impact of nearly 2,400 boe\/d on third quarter average production volumes thus far,\u201d CEO Jonathan Wright was quoted as saying late Aug. 8 in the company\u2019s second-quarter 2024 earnings statement With low gas prices, NuVista has limited any costly efforts to maximize production through this hot period, Wright said, adding the company is targeting a third quarter output of 83,000 boe\/d to 86,000 boe\/d, with the lower end of that range allowing contingency in case of hot weather through August. Given the weather-related issues, the company has tightened its 2024 annual production guidance to 83,500 boe\/d to 86,000 boe\/d, from 83,000 boe\/d to 87,000 boe\/d previously, the statement said. NuVista is engaged in the exploration, development and production of oil and natural gas in the WCSB, with its primary focus being on the condensate-rich Montney formation in the Alberta Deep Basin (Wapiti Montney). Q2, 2024 output up 17% Last quarter, the company\u2019s total output was 83,152 boe\/d, up 17% compared with 71,029 boe\/d in the same quarter the prior year, NuVista said, adding that it maintained an operating netback at C$21.59 ($15.72)\/boe supported by continued condensate pricing. Of the total Q2 2024 output, condensate was 25,761 b\/d, followed by NGL at 7,424 b\/d and natural gas at nearly 300 MMcf\/d, it said. The condensate volumes fetched an average price of C$103.89\/b last quarter, compared with C$94.92\/b in the same quarter of 2023, NuVista said. NuVista invested C$121.5 million last quarter in the drilling of 11 gross wells and completing eight wells in its Wapiti Montney asset base, Wright said, noting in the first half infrastructure projects including an expansion of the Elmworth compressor station was completed to serve growth in the Gold Creek and Elmworth areas. Also in the first half of 2024, NuVista completed a 12-well pad in Pipestone North on budget and on time, he said. \u201cProduction has averaged 1,750 boe\/d which reflects an improvement of nearly 25% on a boe\/d basis compared to our historic average in Pipestone North,\u201d Wright said. NuVista is maintaining its 2024 capital expenditure of C$500 million with the company being \u201cwell-positioned with top-tier assets and highly favorable economics,\u201d he said. \u201cOur disciplined execution has enabled us to achieve growth in production and the high condensate weighting, for which pricing has remained strong, continues to drive superior economics despite the weakness in natural gas prices through the first half of 2024,\u201d Wright said. \u201cIn 2024, the company plans to drill, complete and tie in around 40 wells which is in line with 2023 activity levels and they will be split evenly between the Pipestone and Wapiti areas,\u201d NuVista said, noting multiple facility debottlenecking and expansion projects will also be continuing through 2024 in the Wapiti area. Tamarack sees 4% decline in Q2 output Fellow Western Canadian Sedimentary Basin producer Tamarack Valley Energy has successfully recovered oil volumes that had been shut-in last quarter due to an unplanned outage at its gas plant, the company said. The shut in started April 13 and the volumes were brought online June 24, it said in its second-quarter earnings release Aug 7. Tamarack was able to deploy various temporary mitigation strategies including redirection of gas to an alternative third-party gas plant, gas injection and storage, it said. A total of 6,200 boe\/d (5,250 b\/d of oil, 50 b\/d of NGLs and 5,700 Mcf\/d of natural gas) was shut in from the company\u2019s assets at the Nipisi area, Tamarack said, adding the plant processes Tamarack\u2019s solution gas from various batteries in the Nipisi area. Tamarack has its prime assets in the Charlie Lake and Clearwater areas in Alberta and its last quarter output was 64,143 boe\/d, some 4% lower than a production of 66,738 b\/d in the same quarter the prior year, it said. Of the total Q2, 2024 output, heavy oil accounted for 37,660 b\/d, followed by light oil at 14,807 b\/d and NGL at 2,533 b\/d, it said. Tamarack is targeting to spend C$390 million to C$440 million in the current year to maintain an annual exit production rate of 61,000 boe\/d to 63,000 boe\/d, it said. ","headline":"Canada\u2019s NuVista sees NGL, condensate output of over 90,000 boe\/d in H2","updatedDate":"2024-08-09T15:32:55.000"},{"Unnamed: 0":180,"body":" Libya\u2019s attorney general has ordered the detention of oil minister Khalifa Rajab Abdulsadek on corruption charges, potentially ending a period of dysfunction during which two people were simultaneously holding the role. In a statement, the Attorney General\u2019s Office alleged that the oil minister of the internationally recognized government in Tripoli had illegally threatened an accounting officer to force him to \u201capprove a document authorizing the disposal of 457,000 euros and 600,000 euros for the benefit of a foreign company\u201d. Sources and local media reports confirmed it was Abdulsadek who had been charged with behavior \u201cinconsistent with his job duties\u201d, rather than rival oil minister Mohamed Aoun. Abdulsadek could not be immediately reached for comment. He was appointed interim oil minister in the Government of National Unity in March, rising from deputy minister, after Aoun was suspended by the Administration Control Authority, a watchdog, over a corruption investigation. When the probe was subsequently dropped and Aoun returned to work in May, Abdulsadek -- who has ties to GNU prime minister Abdul Hamid al-Dbeiba -- refused to make way. For months, the two men have held the role of oil minister, operating from neighboring buildings. Abdulsadek also sits on the board of the Libyan National Oil Company. Confusion over who was heading the ministry posed a fresh challenge for international oil companies, which have lifted forces majeures and returned to Libya in recent years in a bid to tap Africa\u2019s largest oil reserves. The country has been plagued by political chaos since the fall of Moammar Qadhafi in 2011, with influential actors including Dbeiba, NOC chairman Farhat Bengdara and eastern warlord Khalifa Haftar vying for control of the oil sector. The country is run by separate governments in the west and east. Libya hopes to boost output to 2 million b\/d in the next five years, above pre-2011 levels, but political strife continues to threaten those plans. On July 7, Libya declared force majeure on the 300,000 b\/d Sharara oilfield, it\u2019s largest by production, after it was shut down on the orders of Haftar\u2019s son, according to sources. Saddam Haftar took the action, the sources said, after a Spanish arrest warrant was issued for him related to an alleged botched drone deal. Spain\u2019s Repsol is among the operators of the field. Libya pumped 1.15 million b\/d of crude in July, according to the latest Platts OPEC Survey from S&P Global Commodity Insights. Its light, sweet crudes are popular among refiners in the Mediterranean and Northwest Europe. ","headline":"Libyan oil minister charged with corruption","updatedDate":"2024-08-09T15:12:00.000"},{"Unnamed: 0":181,"body":" Notes: Scotland's Grangemouth refinery was restarting one of its units, Petroineos said Aug. 9 \"With work scheduled to start from Sunday this may give rise to spells of controlled elevated flaring and steam venting,\" Petroineos said via X. Petroineos said the recommissioning should take up to 48 hours to complete. Previously Ineos, part of the joint venture Petroineos, had provided notice of works happening at the refinery Aug. 6 and 7, warning of flaring from the Kinneil site, in a separate Aug. 5 statement. Ineos had said late July that a plant at Kinneil had been successfully restarted and further works were underway. The maintenance activity follows a series of outages affecting operations across both the north and south of the site over the last year, most recently impacting the refinery's hydrocracker. Large-scale maintenance requirements to service the 100-year-old refinery had part-motivated a decision by Petroineos to halt crude processing from the site after 2025, which it announced last November. Meanwhile, the future of the refinery remains in focus under the new UK government, which announced GBP1.6 million ($2.04 million) of joint funding for Grangemouth under 'Project Willow' in July to help secure a future for the site. Source: Company ","headline":" UK's Grangemouth restarting unit","updatedDate":"2024-08-09T14:59:34.000"},{"Unnamed: 0":182,"body":" Marine fuel prices were down sharply in the week to Aug. 9 as recession fears took crude oil prices to two-month lows amid a wider stock market slump. Prices rebounded slightly by the end of the week, however, supported by revived Houthi attacks in the Red Sea and robust HSFO demand for power generation in the Middle East . The Platts Bunkerworld 0.5% sulfur fuel oil index ended the week at $594 per metric ton, up $2\/t on the day, down $17\/t on the week and down $39\/mt on the month. The BW380 index, which represents value for 3.5% sulfur fuel oil, ended the week at $514\/t, up $5.50\/t on the day, down $10\/t on the week and down $40\/t on the month. A slide on the week was triggered by a wider selloff in financial markets after weaker-than-expected US employment data and contracting Chinese manufacturing activity stoked concerns around a wider economic slowdown. Ongoing tensions in the Middle East provided support later in the week, however, evidenced Aug. 9 by four Houthi attacks on a Greek-operated Suezmax in the Red Sea. Yemen-based Houthi rebels have attacked more than 100 ships in the Red Sea and Gulf of Aden since the Israel-Hamas war broke out Oct. 7, though market focus has increasingly shifted to the threat of direct conflict between Israel and Iran. Longer voyage routes around the Cape of Good Hope for vessels avoiding the Red Sea have continued to support bunker demand, however, providing a source of underlying support. Tanker operator Euronav expects global seaborne cargo to grow by 2.3% to 12.6 MMt in 2024, it told S&P Global Commodity Insights Aug. 8, adding that ton-mile demand could rise by 5.1%. A new US presidency more open to relaxed sanctions on oil-producing countries remains a key downside risk for demand, however. \u201cCaution prevails as any easing of sanctions that reinstates pre-war trading patterns...poses a downside risk to ton-mile demand,\u201d Euronav told Commodity Insights. Inventory health Globally, fuel oil markets remained well-supplied on the week, though robust Middle Eastern power generation demand has continued to provide support to high sulfur grades. In Asia, 0.5%S marine fuel prices were depressed by weak buying activity and ample supplies, while the expected arrival of some 200,000-300,000 t supply in August was expected to add pressure. Meanwhile, Saudi fuel oil imports matched an all-time high in June at 316,000 b\/d, consistent with record levels in 2023, according to tanker tracking data from S&P Global Commodities at Sea . The strong seasonal pull comes despite wider aims to pivot from oil-fired power in the Kingdom, with volumes drawn mostly from Russia and Asia. \"Saudi Arabia has long been planning to shift away from oil burn with a combination of natural gas and renewables, and has been moving toward this direction. But for the short term, the incremental power supply from natural gas and renewables in the country are more used in meeting the increased overall power demand, rather than replacing oil burn,\" said Dong Wang, an oil analyst at S&P Global Commodity Insights. In Europe, a balanced HSFO market dented arbitrage activity from South America, traders said, though the arrival of several inbound cargoes could add pressure. In the Americas, Residual Fuel stocks reached a three-week high of 26.7 million barrels in the week ended Aug. 2, up 841,000 barrels from the previous week, reflecting ample availability, while USGC VLSFO demand stayed lackluster, sources said. The BW Indexes are weighted daily indexes made up of price assessments at 20 key bunkering ports. To obtain a representative geographical spread, the ports were selected by size with reference to their geographical importance. The BW 0.5% Sulfur Index ports are Hong Kong, South Korea, Shanghai, Singapore, Japan, Las Palmas, Durban, Fujairah, Gibraltar, Piraeus, Rotterdam, St. Petersburg, Houston, Los Angeles, New York, Balboa and Santos. The BW380 Index ports are Busan, Canary Islands, Colombo, Durban, Fujairah, Gibraltar, Hong Kong, Houston, Los Angeles, New York, Offshore Nigeria, Panama Canal, Piraeus, Rotterdam, Santos, Shanghai, Singapore, St. Petersburg, Suez and Tokyo. ","headline":" Prices slip on macro fears, supported by Middle East power burn","updatedDate":"2024-08-09T14:32:54.000"},{"Unnamed: 0":183,"body":" Gasoline stocks in the Amsterdam-Rotterdam-Antwerp hub fell 5.8% to 1.007 million mt on the week to Aug. 8, data from Insights Global showed, amid a relatively steep prompt backwardation. Platts assessed the Balmo\/M1 Eurobob spread at $12\/mt Aug. 8, up from $10.5\/mt Aug. 6, S&P Global Commodity Insights data showed. Despite the steeper structure, sources said the market was weak on the prompt and relatively well-supplied. \u201cI don\u2019t see much demand on the very prompt,\u201d said a source. The bulk of trading activity happened late-last week, when a sharp drop in crude saw the gasoline flat price shift and blending economics change sharply. But sources have pointed to a closed arbitrage to PADD 1 and weak demand from Nigeria, which continues to weigh on the NWE market. Naphtha stocks edge lower Naphtha stocks in the Amsterdam-Rotterdam-Antwerp hub fell 1.46% in the week to Aug. 8 to 404,000 mt, according to Insights Global data. Naphtha withdrawals have increased in the ARA as the market remained backwardated with relatively narrow crack spread, thus showing strength on the week. Platts, part of Commodity Insights, assessed the August\/September time spread for Platts CIF NWE Naphtha at $10\/mt on Aug. 8 and the crack spread for Platts CIF NWE naphtha at minus $5.90\/b. Naphtha values remained strong on the week despite relative weakness in many other crude and refined oil product markets, as the demand for naphtha to go into both petrochemical production and gasoline blending pools remained strong. According to a trader source, gasoline blending demand for naphtha is strong, even though gasoline naphtha is narrow as a result of supply tightness and high availability of high octane blendstocks. Commenting on the petrochemicals, another source said that \u201cthanks to the delay in the USA and stronger Asian demand seen in the propane market, the propane naphtha spread has appreciated considerably\u201d, with strengthening propane prices making naphtha more competitive as a petrochemical feedstock. ","headline":"ARA gasoline stocks fall 5.8%, naphtha inventories drop 1.46%: Insights Global","updatedDate":"2024-08-09T12:58:25.000"},{"Unnamed: 0":184,"body":" Fuel oil stocks in the Amsterdam-Rotterdam-Antwerp refining hub fell 2.2% to 1.362 million mt in the week to Aug. 8, Insights Global data showed. This represents the lowest level since early February, when it was seen at 1.318 million mt. Fuel oil\u2019s share of overall oil product inventories in the ARA region remained at 24%. Insights Global does not differentiate by type of fuel oil. Traders said healthy supply and demand economics were playing out for high sulfur (3.5%S) fuel oil in both Northwest Europe and the Mediterranean. One trader source said things were slightly tighter in the Med amid Egypt and Saudi Arabia buying to \"fill in summer demand for this and next month.\" Platts, part of S&P Global Commodity Insights, assessed the HSFO paper front-month to second-month spread at a backwardation of $7.75 per metric ton Aug. 8, from the $8.25\/t backwardation a week ago. Within the very low sulfur (0.5%S) fuel oil markets, bunkering demand was slowly improving from a poor June. Traders said the open Europe to Asia arbitrage was helping to lift some of the pressure in the European VLSFO market. Demand for the VLSFO remains strong within Singapore and is acting as a major tailwind for the European markets currently. EU fuel oil 0.5% marine fuel swaps also had a backwardated structure. The VLSFO 0.5% paper equivalent was assessed at a backwardation of $6\/t backwardation on Aug. 8, up from $5.75\/t a week ago. The front-month paper fuel oil hi-lo ended the week at $26\/t, having widened by $3.75\/t, while the front-month paper Hi-5 widened by $2.75\/t to $88.75\/t. The European bunker market had a mixed week in terms of prices and fundamentals. In Northwest Europe, trading activity was limited amid the summer season. \"I don\u2019t see any other reason apart from summer seasonality,\" said a Rotterdam-based trader. Similar sluggish activity was reported in Hamburg too, even though prices started finding some support after weeks of dipping. In the Mediterranean, demand was more vibrant. Gibraltar had good demand, especially during the beginning of the week, with the market being relatively tight on VLSFO. A local trader suggested Aug. 10 as a possible date for a new cargo arrival. In East Med, Piraeus was also busy, while the local market was dry of HSFO since none of the two refineries had any product due to increased demand. A local trader suggested mid-August onward as the promptest delivery date. ","headline":"ARA fuel oil stocks fall 2.2% on week to 1.36 mil mt: Insights Global","updatedDate":"2024-08-09T12:53:45.000"},{"Unnamed: 0":185,"body":" State-owned Chennai Petroleum Corporation Ltd. posted a 24% year-on-year decline in gross refining margin at $6.33\/b in the April-June quarter at its Manali refinery, company officials said, reflecting lower returns from cracks despite processing higher crude volume. The GRM stood at $8.33\/b a year ago. CPCL\u2019s fiscal year runs from April to March. In Q1 (April-June), the crude throughput at Manali refinery rose 5.6% year on year to 2.83 MMt. The refinery plans to shutdown a crude processing unit with a capacity of 86,000 b\/d during the remaining period of the second quarter (August-September). The maintenance shutdown is schedule to start from Aug. 26. The shutdown has been planned during the rainy season when demand for oil products weaken. India\u2019s summer rain season runs from June to September. Previously, the maintenance was planned during the July-August period. The refinery in South India has a Nelson Complexity Index of 9.71. Manali\u2019s product portfolio includes LPG, motor spirit, superior kerosene, aviation turbine fuel, high-speed diesel, naphtha, bitumen, lube base stocks, paraffin wax, fuel oil, hexane, and petroleum coke. The refinery recorded the highest-ever crude throughput at 11.64 MMt in 2023-24 or FY24, up 2.8% from a year ago. The refinery recorded 111% runs in 2023-24 compared with 108% runs a year ago. In FY24, Manali's GRM stood at $8.64\/b compared to $11.91\/b in the previous fiscal. The refinery specializes in processing high-sulfur crude grades. ","headline":" India's Manali posts $6.33\/b GRM in Q1","updatedDate":"2024-08-09T12:30:43.000"},{"Unnamed: 0":186,"body":" Azerbaijan's oil exports in July averaged 525,161 b\/d, up 6.5% month on month and broadly unchanged on the year, data from the country's energy ministry showed. Exports by the international consortiums that operate Azerbaijan's ACG oil complex and produce condensate from the Shah Deniz and Absheron gas fields averaged 453,548 b\/d in July, up 8.2% on the month and mostly unchanged on the year, while exports by Azeri state oil company Socar averaged 71,613 b\/d, down 3.2% from June and broadly unchanged on the year, the data showed. Over the first seven months of the year, exports averaged 489,859 b\/d, down 5.4% over the same period in 2023. Production during July averaged 619,098 b\/d, up 2.6% on the month and up 14.5% on the year, the data showed, with production over January-July averaging 600,526 b\/d, down 4.3% year on year. Crude production from the BP-operated ACG oil field averaged 358,065 b\/d in July, up 3.7% on the month and was broadly unchanged year on year with the seven-month production averaging 336,995 b\/d, down 8.5% from the same period in 2023. Crude output from the ACG complex has been declining since 2010, when it peaked at 835,000 b\/d, but has been rising again since Q1 this year due to the start of production from the new Azeri Central East (ACE) production facility. Condensate production from the BP-operated Shah Deniz gas field averaged 107,097 b\/d in July, up 29.0% on the month and 273.5% year on year, with the seven-month production averaging 97,418 b\/d, down 3.8% over the same period in 2023. The reason for the sharp rise in production in July is unclear but it follows an unusually large monthly rise in production during March through May which coincided with unusually cold spring weather and a sharp rise in gas exports to Europe, as well as the start of production from two wells on the East North flank of the Shah Deniz field on Feb. 25. Condensate production from the TotalEnergies-operated Absheron gas field, which began operation in July 2023, averaged 10,710 b\/d in July, down 22.4% on the month. The newly commissioned field is currently ramping up to a planned phase-one plateau of 1.5 Bcm\/year of gas with plans to expand to 5.5 Bcm\/year in a second phase. TotalEnergies announced June 6 that it was preparing for a \"fully fledged\" development of the Absheron field after a \"very reassuring\" first phase, but cautioned it was seeking \"greater transparency\" on access to pipeline infrastructure. Azerbaijani Energy Minister Parviz Shahbazov announced July 10 that Absheron had produced 1.5 Bcm of gas over its first year of development and around 580,000 mt of condensate. He added that the plans for expanding production from 1.5 Bcm\/year to 6 Bcm\/year are \"significant contributions to the energy security of our country, as well as of our regional and European partners\" but did not indicate when he expected expansion work to start, when peak production could be reached, or whether any final agreements for the expansion had been concluded with TotalEnergies. Crude production from fields operated by Socar averaged 143,226 b\/d in July down 17.1% on the month and broadly unchanged year on year, with production over the first seven months of the year averaging 152,864 b\/d down 2.2% on the same period in 2023. The volume of oil processed by Azerbaijan\u2019s Heydar Aliyev refinery during July was reported at around 500,000 mt (about 123,333 b\/d), unchanged on the month and around 17% lower than a year earlier. Refinery throughput for the first seven months of the year was at 3.7 million mt (around 128,545 b\/d), down around 0.5% from the same period in 2023. ","headline":" July oil exports rise 6.5% on month","updatedDate":"2024-08-09T12:15:16.000"},{"Unnamed: 0":187,"body":" A ship -- widely reported to be a Greek-operated Suezmax tanker -- has emerged unscathed from four attacks within 24 hours in the Red Sea, the UK Maritime Trade Operations said Aug. 9 amid renewed threats from Yemen-based Houthi rebels to regional shipping. In a statement, the British government agency said the merchant ship was first attacked by a rocket-propelled grenade 45 nautical miles south of Al Mukha, Yemen, with explosion reported in close proximity. The vessel was later attacked by a missile, an uncrewed surface vessel, and then a second missile. The UKMTO suggested the ship, with private armed guards aboard, was not directly hit and remained safe. It is proceeding to the next port of call. Security consultancy Ambrey said the ship was assessed to be aligned with the Houthi target profile. Several media outlets identified it as the 158,000-dwt Delta Blue operated by Greek firm Delta Tankers. The Suezmax is transporting 970,000 barrels of Basrah Medium crude from Iraq to Greece, according to S&P Global Commodities at Sea . Delta Tankers did not immediately respond to an email seeking comment. With market focus shifting to potential direct conflicts between Israel and Iran following recent assassination of Hamas and Hezbollah leaders, Iran-backed Houthi had stayed quiet for two weeks before several incidents reported in recent days. On Aug. 7, the militants said they shot several ballistic missiles and drones at the 1,080-TEU containership Contship Ono in the Red Sea. The 2,496-TEU containership Groton was separately hit by an unknown explosive 125 nautical miles east of Aden in Yemen, the UKMTO said Aug. 3. The Houthis have claimed to attack more than 100 ships in the Red Sea and Gulf of Aden in support of the Palestinians since the Israel-Hamas war broke out Oct. 7. Lates IMF PortWatch data showed the average daily ship transits via the Bab al-Mandab Strait stood at 21 in the week ended July 29, down from the year-ago level of 73. ","headline":"Ship survives four attacks in Red Sea despite renewed Houthi threats","updatedDate":"2024-08-09T11:59:05.000"},{"Unnamed: 0":188,"body":" Renewable hydrogen and biofuel projects are moving forward in Europe and Asia. ** The European Commission\u2019s competition service has cleared a Eur998 million ($1.08 billion) Dutch program to support the production of renewable hydrogen under state aid rules, the commission said July 29. The funding is to support construction of at least 200 MW of electrolysis capacity. The Netherlands aims for 500 MW of electrolyzer capacity in 2025 and 3-4 GW by 2030. The EU's ambition is for 6 GW of electrolysis by 2024, and at least 40 GW by 2030. ** BP has entered the final stage of funding negotiations with the UK government on its planned 1.2-GW H2Teesside low-carbon hydrogen production plant in Teesside, the company said in a statement Aug. 8. It has also awarded front-end engineering design contracts with Costain and Technip Energies. Technip will deliver the FEED work for the planned hydrogen production and carbon capture plant, including engineering procurement and construction execution methodology, schedule, and cost, while Costain will design pipeline infrastructure for the 31-km hydrogen distribution network. Both studies are due to be completed in 2025. ** International Airlines Group and Spanish energy company Repsol have agreed on Spain\u2019s largest sustainable aviation fuel (SAF) purchase deal to date, calling for greater government support to secure lower prices for the fuel. The deal is for the purchase and supply during the next six months of more than 28,000 mt of SAF, Repsol said in a statement July 29. The SAF provided by Repsol will be used by the IAG airlines, including Aer Lingus, British Airways, Iberia, Iberia Express and Vueling, flying from Spanish airports. Repsol began to produce 100% renewable fuels in 2024 at its facilities in Cartagena. Separately, Repsol signed an agreement with Spanish airline operator Volotea to supply 6.1 million liters (5,000 mt equivalent) of sustainable aviation fuel from 2025 to 2029, it said Aug. 1. The fuel will be supplied to the airline from airports in Spain. ** Finnish refiner Neste said that its Singapore facility will have six weeks of maintenance and its Rotterdam facility four weeks in the third quarter. Singapore is also scheduled for another eight-week maintenance period in the fourth quarter, \"after which full capacity is expected to be reached.\" Meanwhile, its Martinez joint venture with Marathon Petroleum in the US operated slightly below 50% of nameplate capacity in the first half of 2024 since the fire at the end of 2023 but is targeting about 75% in the third quarter and 100% by the end of the year. The facility was damaged by a fire in November 2023. \"Work is ongoing to proceed with repairs to ensure safe and reliable operations,\" Neste said. Its renewable production capacity had an average utilization of 81% in the second quarter, down from 107%. In the first half of the year utilization was 84%, down from 100% last year. ** Bio throughput at Eni's facilities in the second quarter was more than 328,000 mt, up from 140,000 mt in the year-ago quarter. For January-June, throughput was 676,000 mt, up from 276,000 mt. The higher throughput was attributed to \"the Chalmette biorefinery contribution and higher volumes processed at the Gela and Venice biorefineries driven by higher plant availability.\" Average utilization was 88% in Q2, up from 60% but down from 90% in H1. Meanwhile, Eni\u2019s Porto Marghera biorefinery is restarting its ecofining and ancillary units that were halted for maintenance Aug. 2, the regional authority in Italy reported Aug. 9. The restart process should last five days, Comune di Venezia said. The work was initially slated to take 15 days, it said. ** ExxonMobil is currently consulting on the potential construction of a carbon capture and storage pipeline to decarbonize operations at its Fawley refinery near Southampton, the company said. The proposed pipeline will be able to transport millions of tons of captured CO2 from Fawley to a CCS storage basin in the English Channel, it announced in a July 18 statement. ** Singapore-based commodities trader Wellbred Trading acquired French refinery La Nivernaise de Raffinage SAS which processes used cooking oil as feedstock, with plans to expand capacity next year by taking advantage of increased demand for renewables-based refined products. The 60,000 mt\/year refinery in Premery produces biodiesel and is Wellbred's first refinery, it said. ** Australia's Queensland state has earmarked A$1.5 million ($980,000) to support two new sustainable aviation fuel proposals while also backing a multiseed crushing and processing facility, it said July 29. The government's Industry Partnership Program will contribute to grains processing company Energreen Nutrition Australia's multiseed crushing and processing facility near central Queensland, it said in the statement. The facility would have the capacity to process 70,000 mt\/year of feedstock, including pongamia oil production -- a potential SAF feedstock. Queensland will also grant private-sector domestic company Wagner Sustainable Fuels and Australian-owned energy company Liquid Power A$760,000 each for feasibility studies to help develop the case for investment in their own SAF proposals. ** The Japanese government has begun a month-long process to invite public comments on a set of draft basic principles and criterion for the country's new cost-for-difference hydrogen subsidy. ** The Singapore government will work with CAPGC, which is buying over Shell\u2019s assets in the city-state, as well as others in the refining and petrochemicals sector to help decarbonize their product slate, Trade and Industry Minister Gan Kim Yong said Aug. 6. Gan, who is also Singapore\u2019s deputy prime minister, was responding to a parliamentary question on how the sale of Shell\u2019s assets would impact the city-state\u2019s emissions levels. In May, Shell Singapore confirmed that it will sell its Energy and Chemicals Park in Singapore to CAPGC -- a joint venture between Chandra Asri Capital and Glencore Asian Holdings -- and the sale is due to be completed by end-2024. ** Indonesia\u2019s biodiesel production in June was up 3.7% year on year at 1.06 million kiloliters (222,250 b\/d), taking production for the first half of 2024 to 6.57 million kiloliters (227,062 b\/d), up 12.7% from 5.83 million kiloliters (202,600 b\/d) in the same period of 2023, trade body Indonesia Biofuel Producer Association or APROBI said Aug. 5. APROBI said consumption was pushed higher by increased biodiesel mandates, which are set to rise further next year. Indonesia already has the world\u2019s highest biodiesel blending mandate, set at 35% of gasoil consumption, as Jakarta looks to reduce energy imports as well as support its domestic palm oil industry. ** South Korea\u2019s top oil refiner SK Innovation said Aug. 8 that its upstream unit has joined a project to build a submarine carbon storage facility in Australia as part of its strategy to diversify beyond oil and natural gas development. ** S-OIL, the leading South Korean refiner, is aiming to make a significant expansion in the biofuels sector, focusing on sustainable aviation fuel (SAF) and renewable diesel as part of its commitment to sustainability and decarbonization, the company said in its ESG report Aug. 1. The company plans to raise production of SAF after 2028 by constructing a dedicated SAF plant. A feasibility study for a dedicated SAF plant is slated for the second half of 2024. Biofuel, hydrogen upgrades Refinery Total capacity b\/d Country Owner Upgrade Completion Gdansk 210,000 Poland Lotos Hydrogen 2025 Trzebinia 7,400 Poland PKN Orlen Hydrogen 2021 Jedlicze 25,000 Poland PKN Orlen Biofuel NA Izmir 220,000 Turkey Tupras Biofuel 2026 Sisak 44,000 Croatia INA Bioethanol NA Grandpuits 101,000 France TotalEnergies Renewables 2024 Antwerp 150,000 Belgium TotalEnergies Biofuel NA Huelva 220,000 Spain Cepsa Biofuel NA San Roque 245,000 Spain Cepsa Biofuel NA Cartagena 220,000 Spain Repsol Biofuel 2023 Bilbao 220,000 Spain Repsol Hydrogen 2024 Tarragona 186,000 Spain Repsol Renewables 2025 Sines 220,000 Portugal Galp Renewables NA Haifa 197,000 Israel Bazan Group Expansion NA Petrotel 48,000 Romania Lukoil Hydrogen NA Fawley 270,000 UK ExxonMobil Hydrogen NA Humber 221,000 UK Phillips66 Renewables 2021 Grangemouth 150,000 UK Petroineos Renewables 2030 Stanlow 205,500 UK Essar Oil Renweables 2024 Venice 400,000 Italy Eni Upgrade NA Sarroch 300,000 Italy Saras Hydrogen NA Miro 310,000 Germany Joint Hydrogen 2021 Heide 90,000 Germany Klesch Hydrogen 2025 Lingen 96,000 Germany BP Hydrogen\/SAF 2024 Rhineland 327,000 Germany Shell Hydrogen 2021 Bayernoil 206,000 Germany Joint Biofuel NA Schwechat 192,000 Austria OMV Biofuel 2023 Cressier 68,000 Switzerland Varo Solar NA Brofjorden 220,000 Sweden Preem Renewables NA Porvoo 260,000 Finland Neste Renewables 2023 Fredericia 70,000 Denmark Postlane Partners Hydrogen 2025 Rotterdam 88,000 Netherlands Gunvor Biofuel NA Pernis 404,000 Netherlands Shell Biofuel NA Bangchak 120,000 Thailand Bangchak Biofuel 2022 Jamnagar 1,360,000 India Reliance Bioenergy NA Numaligarh 60,000 India BPCL Bioplant 2023 Cilacap 348,000 Indonesia Pertamina Biofuel 2023 Ulsan 840,000 Skorea SKEnergy Recycling 2027 Lytton 109,000 Australia Ampol Renewable diesel NA Geelong 120,000 Australia Viva Energy Recycling NA Kwinana 146,000 Australia BP Hydrogen NA Marsden Point 135,000 New Zealand Channel Hydrogen NA Sodegaura 143,000 Japan Fuji Oil Biofuel 2027 Wakayama 120,400 Japan ENEOS Biofuel 2026 Asia-Pacific New and revised entries ** Indonesia\u2019s Kilang Pertamina Internasional is looking for a strategic investor for the Cilacap Green Refinery project, the company said July 10. Phase 1 of the green refinery project, which allows it to process HVO at a rate of 3,000 b\/d, has already been completed. Currently, the company is working on phase 2, which will increase the processing capacity to 6,000 b\/d. The new unit will include a palm oil treater and fractionator. The company said that the project is progressing as planned. Previously, it has said that the second phase is expected to come online in 2026. The company started production of sustainable aviation fuel at its Cilacap refinery in 2023. The production of renewable diesel and SAF is part of the company's Green Refinery road map, which also includes producing renewable gasoline at Plaju and renewable diesel at Dumai. Existing entries ** Thailand's Bangchak said the new unit for the production of sustainable aviation fuel (SAF) is set to start commercial operation in Q2 2025. The unit which is at the Bangchak Phra Khanong Refinery in Bangkok will have 1 million liters\/day capacity and the feedstock will be used cooking oil. The company has begun construction of a SAF manufacturing plant at the Bangchak Phra Khanong Refinery in Bangkok, with a production capacity of 1 million liters\/day using material derived from UCO. The SAF production unit comprises two main units -- the used oil quality improvement unit (Pretreating Unit) and the SAF production unit. Japanese refiner Cosmo Oil also signed an agreement December 2023 to buy SAF from Bangchak. ** Japan's ENEOS Power said April 2024 it has installed and started operating utility-scale energy storage with 50 MW output and 88 MWh capacity, the largest of its kind in the country, at ENEOS' former Muroran refinery in Hokkaido, northern Japan. The utility-scale energy storage is being operated under Virtual Power Platform, a business ENEOS Holdings sees among decarbonization solutions for energy transition as it would help store renewable energy. ENEOS's move follows the startup of its first energy storage with 5 MW output and 10 MWh capacity at its 153,000 b\/d Negishi refinery in Tokyo Bay in August 2023. ENEOS also plans to install and startup 100 MW, 202 MWh utility-scale energy storage at its 129,000 b\/d Chiba refinery in Tokyo Bay in fiscal year 2025-26 (April-March). ** Japanese refiner Eneos and Monogatari Corp. have entered into a deal to collect and recycle 420 kiloliters (about 380 mt\/year) of used cooking oil as raw material for sustainable aviation fuel. Eneos will process the feedstock at the Wakayama plant, which is scheduled to start up in 2026. The plant aims to process 400,000 kiloliters (about 300,000 mt\/year). Eneos plans to decommission the sole 120,400 b\/d crude distillation unit at its Wakayama refinery in mid-October. The company will build a SAF plant on the refinery site and convert the area into a renewable and clean energy supply base. Under a feasibility study, the currently proposed SAF unit would process waste or residue sourced from the circular economy, mainly used cooking oil and animal fat. ** A final investment decision for Malaysia's 12,500 b\/d biorefinery planned by Japan's Euglena, Malaysia's Petronas and Italy's Eni at the Pengerang Integrated Complex, is now expected to take place around mid-2024. The latest FID outlook was released as the board of Euglena approved the establishment of a Special Purpose Company April 8 for the project announced in December 2022, which targeted to complete construction of the plant by 2025. In its latest update, Euglena, however, said that the plant construction schedules and its investment for the project will be finalized after taking the FID. In their December 2022 announcement, Euglena, Petronas, and Eni said they are exploring the development and operation of a biorefinery within the Pengerang Integrated Complex, with an investment decision anticipated by 2023 and completion of the plant targeted for 2025. The biorefinery aims for a versatile setup to optimize production of sustainable aviation fuel, hydrogenated vegetable oil for various transportation sectors. It is projected to process approximately 650,000 mt\/year of raw materials, yielding up to 12,500 b\/d of biofuels, including SAF, HVO, and bio-naphtha. ** Japan's Idemitsu Kosan aims to start up a 250,000 kl\/year (1.57 million barrels\/year) plant to produce sustainable aviation fuel from hydroprocessed esters and fatty acids (HEFA) feedstocks at its Tokuyama complex in fiscal year 2028-29 (April-March), the company said April 2024, as it also reviews its 2030 SAF supply plan. Idemitsu has also delayed the planned startup of its first 100,000 kiloliters\/year alcohol-to-jet technology-based SAF production plant at its Chiba complex in Tokyo Bay in 2026 to FY 2028-29. ** India's Numaligarh Refinery Ltd is set to start its Bio Refinery unit in the 2024\/25 fiscal year (April-March), around three months behind schedule than an earlier deadline. NRL's fiscal runs April to March. The biorefinery was forecast to produce 49,000 mt of ethanol and other chemicals and contributing towards India's objective of achieving 20% ethanol blending in gasoline by 2025. The company will use bamboo biomass as feedstock at Numaligarh via a Joint Venture Company with Finnish collaborators. ** France's TotalEnergies and China's Sinopec will jointly develop and own a 230,000 mt\/year sustainable aviation fuel production unit at a Sinopec refinery in China, the companies said March 26. The planned unit will process local waste or residues such as cooking oils and animal fats, they said. The companies have yet to decide on a location, although sources familiar with the matter said that only two existing refineries were being considered. The project would be located either in Tianjin Petrochemical, which is close to Beijing, or at Guangzhou Petrochemical, to serve the Guangdong-Hong Kong-Macao Greater Bay Area. The SAF unit could also be retrofitted from existing facilities instead of being a newbuild. ** South Korea's S-Oil started using cooking oil, vegetable oil and waste plastic pyrolysis oil in its crude oil refining process January 2023. \"Through the co-processing, we plan to produce sustainable aviation fuel, biodiesel and eco-friendly petrochemical feedstocks such as naphtha and polypropylene,\" the refiner said in a statement. ** SK Innovation aims to start SAF production at its main Ulsan complex in 2026. SK Innovation plans to invest Won 5 trillion in the Ulsan complex by 2027 to transform its fossil fuel-focused process into a green energy-oriented one with a waste plastic recycling cluster, which would reform 25,000 mt\/year of used plastic. ** GS Caltex launched a set of biofuels projects with the country's largest airline, Korean Air, and shipping company HMM Co. ** Hyundai Oilbank has built a 130,000 mt\/year biodiesel plant at its refining complex in Daesan. It plans to transform the biodiesel plant into a bigger facility that can produce 500,000 mt\/year of hydrogenated vegetable oil by the end of this year. ** Japanese refiner Cosmo Oil, JGC Holdings and Revo International established a joint venture called Saffaire Sky Energy, which started construction of Japan's first SAF production facility at Cosmo's Sakai Refinery in Osaka in May 2023. Cosmo Oil expects to complete construction of the facility by the second half of financial year 2024. It plans to use used cooking oil to produce hydro-processed esters and fatty acids SAF. ** India's biggest private refiner, Reliance Industries, is looking to expand its presence in the bioenergy segment. The aim is to use 5.5 million mt of agricultural residue and organic waste to produce biogas. The company is making significant investments in green energy in the bioenergy segment, in addition to hydrogen and solar energy, and renewable fuels to diversify its product portfolio. ** Sinopec Zhenhai's 100,000 mt\/year biojet fuel unit, which was completed in 2020, is the first existing unit of its kind in China. ** Australia's Ampol said September 2023 it is starting \"in the coming weeks\" a renewable diesel trial, with Hanson confirmed as its first customer partner. The trial announcement follows Ampol's partnership with Japan's ENEOS to explore production of renewable diesel at the Lytton refinery. ENEOS and Ampol agreed to explore producing up to 500,000 kl\/year (3.14 million barrels\/year) of sustainable aviation fuel and renewable diesel at Lytton by the late 2020s. Hanson is a leader in building and construction materials, with an extensive production and logistics network across Australia. ** Australia's Viva Energy has plans to build infrastructure at Geelong, which will enable the refinery to receive and process feedstocks such as \"used cooking oil, animal fats and synthetic crude made from waste plastics which would otherwise find their way into landfill.\" The feedstocks will be blended with crude oil in order to \"reduce the energy intensity of fuels that are produced at Geelong Refinery and recycle waste plastics through the polypropylene plant which was acquired by the company last year.\" This will result in the \"first commercial production in Australia of recycled plastic from waste soft plastics,\" it said. ** Technip Energies said it has been awarded a \"significant contract\" for a hydrogen production unit at BP's Kwinana biorefinery in Australia. The contract is in support of the planned project to produce sustainable aviation fuel and biodiesel from bio feedstocks at the former refinery. Technip Energies said the contract covers engineering, procurement and fabrication of a modularized hydrogen production unit with 33,000 normal cu m\/hour capacity. The unit will be able to produce hydrogen from natural gas or biogas produced by Kwinana. BP Australia said in 2022 that it continues to advance plans to develop a renewable fuels plant at its Kwinana site, by producing sustainable aviation fuel and renewable diesel. The plan is part of BP's \"broader plans to develop its Kwinana site as an integrated energy hub that produces and distributes fuel for the future.\" ** New Zealand's Channel Infrastructure said July 2023 a pre-feasibility study will be carried out for development of a green hydrogen manufacturing facility at its Marsden Point site to produce synthetic sustainable aviation fuel. Channel Infrastructure said Fortescue Future Industries would \"progress further investigation\" into the development of the facility, which could potentially supply around 60 million liters\/year of eSAF. The proposed facility would use electrolyzers to produce 35,000 mt\/year of green hydrogen. ** Japanese refiner Fuji Oil aims to start supplying 180,000 kl, or 1.13 million b\/year sustainable aviation fuel at its Sodegaura refinery in Tokyo Bay in fiscal year 2027-28 (April-March) and has started front-end engineering design work for the project. Middle East Existing entries ** Japan's Mitsui has started construction of a 1 million mt\/year ammonia plant in Al Ruwais, UAE alongside Abu Dhabi's TA'ZIZ, Fertiglobe and South Korea's GS Energy. The project plans to start production of ammonia with lower CO2 emissions compared to conventional ammonia from 2027 and to start production of clean ammonia by 2030 by installing additional facilities that will capture and store CO2 emitted in the manufacturing process, the company said. Mitsui added it will take a stake in the project and \"offtake a certain volume of the clean ammonia\" produced at the plant for supplying Japan and other Asian markets. ** Iran's Persian Gulf Star refinery will build an ammonia production unit to produce clean fuel for exports to Europe. \u201cProduction of green ammonia is one of the most important projects of the refinery and is being implemented. Its EPC tender will start within the next two months,\u201d Hadi Golbabaie, deputy managing director of Persian Gulf Star refinery for production, was quoted as saying by Shana. Some 450,000 mt\/yr of \u201cgreen\u201d ammonia will be produced to be exported to Europe. The ammonia will be produced using burnt gas in the flares, which comes from gasoline production process, he said. Africa Existing entries ** Angola's Sonangol is planning to build a biorefinery in Luanda as part of its energy transition. ** Kenya is considering converting its shuttered Mombasa refinery to a biofuel plant using technology provided by Italy's Eni. The Mombasa refinery, Eastern Africa's sole refinery, was shut down in 2013. Kenya is deciding upon a location for a new refinery in Lamu or Mombasa. Europe New and revised entries ** Italy's ISAB refinery in Sicily has secured Eur425 million ($460 million) of funding to secure the plant's long-term future, Italian bank Illimity said July 31. Financing for the refinery will be jointly funded by Illimity and Trafigura, a strategic partner and supplier to the refinery, as part of a wider Eur1.4 billion investment plan for the site between 2024 and 2033. In its statement July 31, Illimity called the refinery \"an asset of national strategic interest\" for the Italian and European energy landscape, saying the loan would strengthen the company's core business, support the energy transition and decarbonization of the site. ** Lukoil is considering producing sustainable aviation fuel at its Neftohim refinery in Burgas, Bulgaria, Interfax news agency reported July 24. It has already conducted laboratory tests and has prepared the production scheme. Lukoil has said previously it was considering selling the refinery and has warned it could shut down the plant if crude supplies from Russia are cut off too quickly before it can switch to alternative crude stocks. Subsequently, the company stopped importing Russian Urals crude into the Bulgarian refinery in December 2023 and has since broadened the crude slate it processes. ** At Cepsa's Huelva, work started in the first half of 2024 on a HVO\/SAF production unit with flexible capacity of 500,000 mt\/year, which should be operational in 2026. The refinery started basic engineering and permitting for the first 200 MW phase of green electrolyzer capacity in 2023. This could result in first hydrogen in 2026. It contracted Germany\u2019s Thyssenkrupp Nucera and Siemens Energy as preferred suppliers for a combined 400 MW of green hydrogen electrolyzer capacity. Cepsa is targeting green hydrogen production of 2 GW by 2030, split evenly across its two so-called energy parks at Huelva and nearby Algeciras. It signed a deal with Norway\u2019s Yara Clean Ammonia in June 2023 for a 750,000 mt\/year green ammonia plant at Huelva, designed to establish a green hydrogen corridor and serve industrial and maritime customers in Rotterdam and Central Europe. Cepsa aims to reach 2.5 million mt\/year of biofuel production by 2030, including 500,000 mt\/year of sustainable aviation fuel. The plant will also produce renewable diesel. In the aviation sector, the company started offering SAF at four airports in Spain during July 2023. La Rabida in Huelva increased its biofuel installed capacity in 2023 by 10% to 685,000 mt\/year. Cepsa aims to have second generation biofuels available for bunkering at all the ports it operates by 2030. ** Galp\u2019s Sines expects to start up its new 270,000 mt\/year advanced HVO and SAF unit between the end of 2025 and mid 2026. The latter date would be a slip from a previous timeframe announced by the company, which was targeting a start-up in \u201clate 2025.\u201d The plant, alongside a 100 MW green hydrogen electrolyzer due to start production in 2025, is part of a Eur550 million investment by the refinery that will allow it to save 800,000 mt\/year of Scope 3 emissions. The hydrogen unit will replace around 20% of Sines\u2019 grey hydrogen consumption. Galp could take a final investment decision on a second phase of hydrogen production at the refinery in 2026. ** Shell has taken a final investment decision to go ahead with a 100-MW electrolyzer to produce renewable hydrogen for its Rheinland refinery in Germany. The electrolyzer which is developed under the Refhyne II project, will produce up to 44,000 kg\/day of renewable hydrogen aimed to \"partially decarbonize site operations\" and is scheduled to begin operating in 2027. The project follows on from the 10-MW Refhyne I, which started operations in July 2021, producing up to 1,300 mt\/year of renewable hydrogen. The five electrolyzer modules, with a total 10 MW of capacity, have been installed at the Wesseling site. The refinery comprises the Wesseling (south) and Godorf (north) sites although Shell will end crude processing at the Wesseling site in 2025. It has also taken a final investment decision to convert the hydrocracker at Wesseling to producing Group III base oils. Crude processing will continue at Godorf. ** EET (formerly Essar Oil) is planning to develop a 125-MW hydrogen-ready combined heat and power plant at its Stanlow refinery in the UK by 2027, the company said July 2024. EET Hydrogen Power will be developed over two phases to reach the total power capacity, also generating 6,000 mt\/d of steam, EET said in a statement. The new CHP plant will replace existing 50-MW boiler units that power operations at Stanlow. A final investment decision on the CHP plant is expected later in 2024, with construction to start in 2025. Hydrogen for the plant will come from the planned EET Hydrogen production plant, part of the HyNet cluster in northwest England. The UK's Stanlow refinery will install a new hydrogen-powered furnace at its CDU, which will replace three gas-fired furnaces. The new furnace, which will run on 100% hydrogen from 2027, will help increase capacity from around 72 million barrels\/year at the moment to 76 million-77 million barrels\/year. As part of its drive to a low-carbon future, it is also looking to manufacture 1 million mt\/year of biofuel in countries in Asia where access to raw materials is easier and to import it. ** Repsol said a retrofit at Puertollano will result in a new stream of biofuel production from 2026. In 2025, Spain's Puetrollano will conclude the retrofit of its hydrodesulfurization unit into a 204,000 mt\/year HVO unit. Also at Puertollano, Repsol is planning to build a 25,000 mt\/year production line for recycled polyethylene, expected online by the end of 2024. A deal signed with Bunge earlier this year will ensure 80%-85% of the company\u2019s feedstock needs by 2030, it estimates. Existing entries ** Petronor's Bilbao and Repsol\u2019s Cartagena have been awarded funding from the Spanish government for their electrolyzer projects. The 100-MW electrolyzer project at Bilbao was awarded Eur160 million while the 100-MW electrolyzer project at Cartagena obtained Eur155 million. Repsol brought online its first 2.5-MW green hydrogen electrolyzer at Bilbao in the fourth quarter of 2023. An ensuing 10-MW electrolyzer has a target date of 2025. The green hydrogen will be used to feed a synthetic biofuel plant at Bilbao, which should be completed in 2025. At Cartagena, the project is being developed with Spanish gas grid operator Enagas and France\u2019s Engie. Repsol previously said it might postpone both projects depending on a temporary Spanish tax on energy companies. ** BP has paused plans to construct a standalone biofuel production unit at its Lingen refinery in Germany in a revision to previous expansion plans in Europe, the international oil company said in a statement June 2024. The company added that projects in Rotterdam and Castellon, Spain are under evaluation. BP planned to produce 500,000 mt\/year of sustainable aviation fuel (SAF) from the site by 2030. Meanwhile co-processing is set to continue at Lingen. Representatives for the refinery confirmed that the plant had successfully run 5% bio-feedstock in its hydrocracker plant in February 2024. Separately, the company plans to invest in a 100 MW electrolyzer at Lingen, which could start early 2026 if BP were to receive a speedy confirmation of the \"Lingen Green Hydrogen\" plan as an Important Project of Common European Interest. The project is scalable to 500 MW. ** Shell will temporarily pause construction on its new biofuel plant being built at the site of Europe's biggest refinery, Shell Energy and Chemicals Park Rotterdam (formerly Pernis), it said July 2024. The company will \"address project delivery and ensure future competitiveness given current market conditions,\" it said in a statement. The new 820,000 mt\/year biofuel plant was expected to start up in 2024 or 2025. The plant is aimed to produce sustainable aviation fuel and renewable diesel from waste. ** Germany's Holborn refinery has awarded KT-Kinetics Technology and NextChem, both part of the Maire Group, an EPC contract for developing an HVO complex inside the Hamburg refinery, said Maire Group in a statement. Once completed, the plant will produce around 220,000 mt\/year of renewable diesel and SAF \"using waste and residues feedstocks, biomasses and the residues of the agribusiness industry, as well as low carbon hydrogen,\" the statement said. The plant is expected to be operational in 2027, \"including the pre-treatment and HVO units, and the interconnecting infrastructure with the existing facilities,\" it said. ** OMV Petrom said June 2024 that it has concluded a contract with Expur for the supply of fully refined vegetable oil to be used as a feedstock at its Petrobrazi refinery. The oil will be used in the refinery's sustainable aviation fuel and renewable diesel facility for which the company recently made a final investment decision. Deliveries under the contract, which is for six years and can be extended for another two, will begin in 2028. Expur will supply a maximum of 0.7 million mt. Earlier in June OMV Petrom announced as part of its investment at Petrobrazi a 250,000 mt\/year biofuels plant capable of producing SAF and renewable diesel, which is set to begin production in 2028 and will be powered mostly by two new green hydrogen plants with a total capacity of 55 MW. As part of the Petrobrazi development, two green hydrogen units will be commissioned. With an annual production volume of around 8,000 mt\/year of hydrogen supply, the two plants will be able to substitute a substantial volume of an expected 11,000 mt\/year of hydrogen consumption from the new biofuel plant. ** Repsol\u2019s Cartagena reached full production at its new 250,000 b\/d advanced biofuel unit (C-43) during the first half of 2024. The plant produces biodiesel, biojet, bionaphtha and biopropane from waste, such as used cooking oil. ** Austria's OMV has started biofuels production from it","headline":" Hydrogen, biofuel projects move forward","updatedDate":"2024-08-09T11:47:40.000"},{"Unnamed: 0":189,"body":" Hungarian oil and gas company MOL has so far experienced no interruptions in crude flows via Ukraine following sanctions imposed by Ukraine on Lukoil, but is aware of the risks and is taking steps to secure crude supply flows for the long term, the company said in its second-quarter earnings report on Aug 9. MOL said that if flows via the Druzhba pipeline dropped significantly, the company would be able to increase its utilization of the Adria pipeline and supply about 80% of the intake of its landlocked refineries in Szazhalombatta, Hungary and Bratislava, Slovakia. However, MOL noted that this would also mean higher technical risks and logistics costs. Acknowledging that there were \"downside risks to the current setup\", MOL said that it is \"working actively on potential long-term solutions with stakeholders\" to secure crude supplies and is also continuing investments to make its refineries more flexible in terms of crude oil sourcing and processing. Second-quarter output MOL reported hydrocarbon output of 92,100 b\/d of oil equivalent for the second quarter of 2024, up 5.5% year on year as higher oil and gas output in Hungary and the gradual resumption of oil production in the Kurdistan region of Iraq offset lower production in Azerbaijan and Croatia. Second-quarter results bring MOL's January-June hydrocarbon production to 92,200 boe\/d, 0.7% higher than a year earlier and exceeding the company's full-year 2024 guidance of 90,000 boe\/d. MOL said it estimates production was 95,500 boe\/d in July. MOL's organic capital expenditure totaled $369 million in the second quarter, 33% higher year on year, while six-month capex was up 45% at $685 million. The company said it was keeping its 2024 organic capex target at $1.7 billion. Within total Q2 capex, however, upstream investments fell 12% year on year to $76.7 million. Of this, exploration spending more than doubled to $11.8 million, with growth and total spending both dominated by Hungarian projects; though spending suffered by delays in drilling campaigns in Croatia and Egypt. Spending on field development fell by 26% year on year to just under $50 million, with Hungary and the Kurdistan region of Iraq -- where MOL is holding back spending until export lines are restored -- seeing the biggest declines. Of total field development spending, the Azeri ACG field alone accounted for $32.5 million, little changed from recent quarters. Downstream capex increased by 61% year on year to $191 million in the second quarter. Higher spending was driven by refinery maintenance, both planned and unplanned, MOL said. Crude output Within total Q2 output, crude oil production at MOL's fully consolidated operations was 39,000 boe\/d, up 9% year on year. The Shaikan field in Iraqi Kurdistan accounted for most of this growth, as production -- now focused mostly on domestic buyers -- has been almost fully restored to earlier levels after export restrictions forced a halt to production in Q2 2023. Output in Azerbaijan, now MOL's biggest oil-producing region, was down 9% year on year at 12,300 boe\/d, while Croatian oil production fell 4.8% to 9,300 boe\/d, both mainly because of natural decline. On the positive side, Hungarian oil production surged by 7% to 10,700 boe\/d after the addition of a new well at the Vecses field. MOL's natural gas output was down just 0.6% year on year at 37,400 boe\/d in the second quarter, as natural decline at Croatian fields, both onshore and offshore, was offset by growth in Hungary. MOL also saw a 16% drop in Pakistani output as it held back production at the TAL block due to pipeline constraints. Average hydrocarbon prices realized by MOL have largely stabilized, falling by only 5% year on year to $63.3\/boe in the second quarter. Natural gas prices, down 19% at $46.3\/boe, were responsible for all of the drop, as crude oil prices realized by MOL actually increased by 1.4% to $75.4\/boe. MOL's per-unit production costs (excluding depreciation, and including non-fully-consolidated operations) in th second quarter were virtually unchanged year on year at $5.8\/boe, which MOL attributed to strict cost control and favorable energy price movements. Downstream, MOL's refinery throughput in the second quarter was 3.84 million mt, down 9.6% year on year, mainly because of refinery maintenance works during the period. External refined product sales, on the other hand, increased by 1.9% to 4.53 million mt, thanks to rising fuel demand across Central and Eastern Europe. MOL's Brent-based total refinery margin in the second quarter fell quarter on quarter but increased by 26% year on year to $6.8\/b. The year-on-year increase compensated for the narrowing of the Brent-Ural differential in the same period, from $9.6\/b to $3.4\/b. MOL added that it saw refinery margins narrow further in July to $4.7\/b. ","headline":"MOL says Druzhba flows uninterrupted despite Lukoil sanctions; seeks to diversify","updatedDate":"2024-08-09T11:11:41.000"},{"Unnamed: 0":190,"body":" The new 650,000-b\/d Dangote refinery in Nigeria continues to struggle in securing domestically sourced crude oil for its operations, its owners said Aug. 7. In a statement, a spokesperson for the Dangote Group said the refinery requires 15 cargoes of crude oil to operate in September but has failed to source the necessary volume from either state oil firm Nigerian National Petroleum Co. or international oil companies (IOCs) active in Nigeria. \"For September, our requirement is 15 cargoes, of which NNPC allocated six. Despite appealing to NUPRC, we've been unable to secure the remaining cargoes,\" the company said in its statement. It added that IOCs have demanded a premium of $3-$4\/b from the refinery for sales of Nigerian crude oil or claimed that cargoes were already committed to other buyers and unavailable for sale. Dangote blamed feedstock shortages on lax enforcement by the Nigerian Upstream Petroleum Regulatory Commission (NUPRC) of the country's new domestic crude supply obligation, a measure that commits producers to meeting demand from Nigeria's refineries before exporting supplies. \"Our concern has always been NUPRC's reluctance to enforce the domestic crude supply obligation and ensure that we receive our full crude requirement from NNPC and the IOCs,\" the Dangote spokesperson said in the statement. The NUPRC was not available for comment. Regulatory efforts The latest comments from Dangote represent a change in tone from recent optimism regarding the availability of Nigerian supply, which it said triggered its decision to resell WTI Midland crude oil procured from the US in late June. The NUPRC appeared to signal a detente in relations between Dangote and IOCs active in Nigeria on July 11, when it announced that major oil producers had agreed to develop a framework to ensure sustainable supply of crude oil to local refineries, stressing that material should be supplied at market price. Tensions had previously come to a head in June, when representatives for Dangote alleged that the refinery was being charged a premium of over $6\/b by IOCs for crude oil and reluctance from suppliers had harmed its ability to source feedstock. Additionally, NNPC, once expected to be one of the plant's largest suppliers, has underdelivered relative to its expected crude deliveries, leaving uncertainty around supply channels for the newly commissioned plant. NNPC was originally expected to supply Dangote with 300,000 b\/d of discounted crude but has delivered closer to 82,000 b\/d since the refinery's inauguration, according to S&P Global Commodities at Sea data. The state oil company has subsequently limited its stake in the refinery to 7.2%, down an initially expected 20% from NNPC's reduced stake in the refinery. Domestic preference As NNPC has struggled to deliver on its commitments to Dangote, it could remain an attractive supplier to avoid Nigeria's currency woes. Due to its location in the Lekki Free Zone, Dangote had purchased most of its crude oil in US dollars, leaving its operations exposed to foreign exchange movements. Devaluation in Nigeria's currency has therefore put significant strain on Dangote, amounting to foreign exchange losses of Naira 2.7 trillion (around $1.7 billion) across the Dangote Group in 2023, according to Fitch Ratings. In response, the Nigerian government made provisions in July for 450,000 barrels of NNPC crude to be purchased by Dangote in naira, hoping to alleviate the burden of further naira depreciation. Broader energy security goals have put pressure on Dagnote to prioritize domestic crude oil sourcing; however, it has flagged Brazil, Angola, Senegal and Libya as other potential supply options to supplement local feedstock. To date, Dangote has only sourced WTI Midland crude oil from outside of Nigeria, with the US grade making up approximately 30% of its feedstock imports and totaling 15 million barrels, according to CAS data. According to Fitch Ratings, Dangote operated at around 50% capacity in the first half of 2024, while the refinery has aimed to reach 85% of its installed capacity by the end of the year, a Dangote spokesperson said Aug. 8. S&P Global Commodity Insights analysts forecast the refinery to reach steady-state capacity by 2027. ","headline":"Nigeria's Dangote refinery decries domestic crude shortage","updatedDate":"2024-08-09T11:08:24.000"},{"Unnamed: 0":191,"body":" Crude futures remained largely unchanged with slight increase during the mid-morning trading on Aug. 9 following the recovery seen on Aug. 8 as Middle Eastern oil supply concerns kept the oil prices elevated. At 1109 GMT, the October ICE Brent crude oil futures contract was at $79.19\/b, up 3 cents\/b from the previous settlement at $79.16\/b, while the October WTI Crude Futures contract was at $75.12\/b, up 8 cents\/b from the previous settlement at $75.04\/b. On Aug. 8, the US, Egypt and Qatar released a joint statement calling on Israel and Hamas to resume negotiations over a ceasefire and hostage-release delay. These diplomatic talks serve as an attempt to ease the heightened tensions in the region following the assassination of Hamas\u2019 leader Ismail Haniyeh previously. As the world still awaits responses from both sides as to their attendance in the talks, the supply concerns over Middle Eastern oil remain elevated thus pushing prices upwards. Commenting on escalating tensions in the Middle East, Ole Hvalbye, Commodities Analyst at Seb Research, said, \"While deeper involvement with Iran could theoretically disrupt their 1.7-million-barrel crude and condensate exports, OPEC+ spare capacity would likely offset this impact. The Strait of Hormuz remains a critical chokepoint for global crude and refined product shipping, accounting for roughly 20% of global shipments. However, a potential blockade is unlikely to persist due to significant international interests in the region.\" The crude futures also gained support from the improvement in wider financial markets and EIA data suggesting stronger oil demand in the US. During the morning trading of Aug. 9, stock futures pointed to gains in all major indexes, including S&P 500\u2019s more than 2% rise, while Nasdaq futures are boosted by strength in chip companies\u2019 stocks. The US jobless data released on Aug. 8 showed that claims fell more than expected in the last week, which gave support to investors that recession may not be so inevitable, thereby supporting stocks performance. The EIA data, released on Aug. 7, showed a 400,000 b\/d decrease in global oil inventories with the expectation of an 800,000 b\/d fall in stockpiles in the second half of this year. Higher withdrawals in oil stocks show the strength in oil demand and thus keep oil prices elevated. As Bjarne Schieldrop, Chief Commodities Analyst at Seb Research, said, \u201cThe good news for the oil bulls is that US crude oil production looks like it is now going sideways rather than up, up, up.\u201d ","headline":" Crude futures steady, Middle East supply concerns in focus","updatedDate":"2024-08-09T11:05:04.000"},{"Unnamed: 0":192,"body":" Eni\u2019s Porto Marghera biorefinery is restarting its ecofining and ancillary units that were halted for maintenance Aug. 2, the regional authority in Italy reported Aug. 9. The restart process should last five days, Comune di Venezia said. The work was initially slated to take 15 days, it said. Platts, part of S&P Global Commodity Insights, assessed used cooking oil (UCO) FOB ARA at $1,100\/mt Aug. 8 ","headline":" Eni Porto Marghera restarting ecofining unit","updatedDate":"2024-08-09T10:13:16.000"},{"Unnamed: 0":193,"body":" Idemitsu Kosan, Japan's second-largest refiner, restarted the 61,000-b\/d residue fluid catalytic cracker at its 255,000-b\/d Yokkaichi refinery in central Japan at the end of July, a company official said Aug. 9. The RFCC had been shut since June due to technical issues, but the company did not disclose the specific duration of the shutdown or details of the glitches. \"Due to continued troubles at our refineries, we were forced to take action in June and July to maintain supply. Although the effects of a fire at the Chiba refinery [in early July] still remain, the supply has now been largely stabilized,\" the official said. The Platts-assessed gasoline, kerosene and gasoil prices across the Chiba, Kanagawa, Chukyo and Hanshin regions averaged Yen 79,000\/kiloliter ($85.51\/b), Yen 79,000\/kl and Yen 77,600\/kl, respectively, on Aug. 9, according to S&P Global Commodity Insights data. ","headline":" Japan's Idemitsu restarts Yokkaichi RFCC after glitches","updatedDate":"2024-08-09T09:59:58.000"},{"Unnamed: 0":194,"body":" Azerbaijan increased its gas exports in the first seven months of 2024 by 5.7% year on year to a total of 14.7 Bcm, the country's energy ministry said Aug. 9. In the period January-July, a total of 7.5 Bcm was supplied to Europe, 5.8 Bcm to Turkey and 1.4 Bcm to Georgia. Azerbaijan has been steadily increasing its gas exports to Europe since the start of the Southern Gas Corridor and expects to supply a total of 13 Bcm to Europe this year, up from 11.8 Bcm in 2023. The corridor comprises pipelines through Georgia and Turkey, ending with the TAP pipeline via Greece to Italy and the Greece-Bulgaria interconnector. Of the 5.8 Bcm supplied to Turkey, some 3.3 Bcm was delivered via the TANAP pipeline, the ministry said. It comes as delivered LNG prices to the region continue to rally. Platts, part of S&P Global Commodity Insights, assessed the DES East Mediterranean LNG marker at $12.93\/MMBtu on Aug. 8. Production increase The ministry also said Azerbaijan's total gas production in the first seven months of 2024 had reached 29.5 Bcm, up by 1.3 Bcm year on year. Of the total, 16.5 Bcm came from the BP-operated Shah Deniz field while 7.7 Bcm was associated gas production from the ACG oil field. Output from the Absheron field totaled 0.9 Bcm, while state-owned Socar produced 4.4 Bcm, the ministry said. Azerbaijan is seen as a key partner to Europe for its gas deliveries, particularly since the curtailment of Russian pipeline gas flows since 2022. However, Azeri officials have complained repeatedly that in order to increase exports to Europe, there needs to be substantial investment in expanding the capacity of the pipelines that make up the Southern Gas Corridor. Officials have said this can only happen if European gas buyers commit to buying gas from Azerbaijan over the long term. Baku has also played down expectations for the extent of an expected increase in gas deliveries to Europe. President Ilham Aliyev said last month that the target for gas supplies agreed under a declaration on strategic partnership signed with the European Commission in July 2022 was not a \"formal commitment\". The EC said at the time that the new memorandum of understanding included a commitment to double the capacity of the Southern Gas Corridor to deliver at least 20 Bcm to the EU annually by 2027. However, Aliyev said that with reference to 2027, its target was for European supply of 16 Bcm\/year by the end of 2027. ","headline":"Azerbaijan boosts gas exports by 5.7% on year in first seven months: ministry","updatedDate":"2024-08-09T09:53:46.000"},{"Unnamed: 0":195,"body":" Japan's ENEOS Holdings is considering imports and higher production of jet fuel as part of its response to aviation fuel shortages in the country, Executive Vice President and CFO Tanaka Soichiro said Aug. 9. As part of ENEOS' response to action plans decided at a government-led task force in July, \"we will consider imports as well as production increase of jet fuel,\" Tanaka said in an earnings press conference in Tokyo. \"Then we will also make investments to convert our storage tanks to jet fuel as part of our mid-term response,\" said Tanaka, adding that the company intends to seek support from the government for this. \"We will also work on establishing our system to transport [jet fuel] from [our] refineries to airports,\" he said, referring to shortages of coastal vessels and personnel for refueling. Over April-June, ENEOS reported a 2.7% year-on-year increase in its domestic jet fuel sales to 380,000 kiloliters, or 2.39 million barrels, as a result of the recovery in aviation demand following the pandemic. Meanwhile, Cosmo Energy Holdings also intends to meet incremental jet fuel demand from foreign airlines should it receive supply orders in advance, Senior Executive Officer Tomoki Iwai told a separate earnings press conference in Tokyo on Aug. 9. \"Since we are in a short position, it would be quite difficult to respond to a prompt supply order,\" Iwai said. \"As we intend to meet the request as much as possible, [jet fuel] imports might be increased depending on the situation.\" In the event of gauging incremental jet fuel demand on top of heating demand for kerosene in winter, Cosmo Energy Holdings would consider importing the aviation fuel, Iwai said. Cosmo Energy Holdings expects a 3.9% year-on-year increase in bonded jet fuel sales for international flights to 2 million kl in the current fiscal year to March 2025. Middle East Asked to comment on the fast-deteriorating Middle East situation over a possible retaliatory attack by Iran on Israel, ENEOS' Tanaka said: \"We are monitoring the situations very closely.\" \"We are trying to diversity [our crude procurements] as much as possible,\" Tanaka said. \"In the short term, it would be very difficult to drastically make a shift [in our crude procurements],\" he said, adding that the company would have to tap oil reserves as a short-term contingency if necessary. The Middle East's share of Japan's crude imports dipped to 96.4% in June , from 97.3% a year earlier, marking the second consecutive decrease, as the country boosted imports from Ecuador and the US, preliminary data from the Ministry of Economy, Trade and Industry showed July 31. ENEOS also expects to start sustainable aviation fuel production of 400,000 kl or 300,000 metric tons per year based on hydroprocessed esters and fatty acids from used cooking oil, at Wakayama after January 2027, instead of 2026 as planned earlier, Tanaka said. ENEOS Holdings said it plans to change the name of its upstream arm JX Nippon Oil & Gas Exploration to ENEOS Xplora on Jan. 1, 2025, reflecting its broader business scope, including on environmentally friendly and growth businesses centered on carbon capture and storage and carbon capture utilization and storage. ","headline":"Japan's ENEOS weighs jet fuel imports, boosts output to tackle aviation fuel shortages","updatedDate":"2024-08-09T09:39:41.000"},{"Unnamed: 0":196,"body":" Malaysia\u2019s palm oil stocks at the end of July are seen rising marginally to 1.84 million mt, from 1.83 million mt a month earlier, as a seasonal pickup in production offset higher exports, an S&P Global Commodity Insights survey showed Aug. 9. Production at the world\u2019s second largest palm oil producer is expected to rise 14.6% from the month before to 1.85 million mt, according to a median estimate of 10 traders, analysts and growers. In June, Malaysia produced 1.62 million mt of palm oil, according to the Malaysian Palm Oil Board. The government regulator is set to release official supply and demand data for July on Aug. 12. Palm oil exports are expected to rise to 1.52 million mt in end-July, from 1.21 million mt in end-June, according to the monthly survey. Domestic consumption of palm oil within Malaysia is expected to reach 330,000 mt in end-July, from 345,000 mt in end-June. Commodity Insights palm oil survey July survey median July survey range June data Change (e) Production 1.85 1.81 - 1.85 1.615 14.6% Imports 0.017 0.012 - 0.05 0.01 70% Exports 1.52 1.51 - 1.54 1.207 25.9% Domestic consumption 0.33 0.28 - 0.345 0.345 -4.3% Ending stocks 1.84 1.837 - 1.86 1.829 0.6% All figures in million metric tons Price trend Malaysian palm oil futures rose Aug. 9 buoyed by stronger prices of rival soybean oil on the Dalian and Chicago exchanges but were on track for a third consecutive weekly loss as a strengthening ringgit against the dollar, fears of slowing demand from China, better soybean production in the US and broader macroeconomic worries weighed on vegetable oil prices. The benchmark palm oil contract for December delivery on the Bursa Malaysia Derivatives exchange advanced 0.8% on the session to MR3,737\/mt ($845.29) in afternoon trading Aug. 9. Support for crude palm oil futures was pegged at MR3,682\/mt and resistance at MR3,790\/mt, Kuala Lumpur-based AmInvestment Bank said. Gains in the futures prices have been limited by concerns of raising output in the coming weeks, said David Ng, senior palm oil trader at IcebergX Sdn Bhd. Malaysian CPO futures have declined 4.5% since the start of August. UOB Kay Hian Securities said in July that CPO prices are expected to trade higher in the second half of 2024 due to tighter palm oil supplies and a gradual return of demand as palm oil regains its price advantage against rival oils in international markets. ","headline":"Malaysia palm oil stocks seen rising slightly in end-July on higher production","updatedDate":"2024-08-09T09:18:24.000"},{"Unnamed: 0":197,"body":" The value of Guyana's Liza crude relative to Dated Brent weakened to the lowest differential in over four months on Aug. 8 amid market talk of unsold cargoes. Platts, part of S&P Global Commodity Insights, assessed Liza at a 40-cent\/b discount to the 30- to 60-day forward Dated Brent strip, a decline of 75 cents\/b on the day, and the lowest since March 11. The assessment was based on participation in the Platts Market on Close assessment process. ExxonMobil entered the MOC offering a 1-million-barrel cargo of Liza to load Sept. 12-13 at a premium of 40 cents\/b to Dated Brent. Then, gradually lowered that offer to a discount of 40 cents\/b. Glencore Energy UK marked interest in buying the cargo, and a trade was confirmed at that level. A separate trading source familiar with Guyanese crude said that the falling prices for the crude were due to a surplus of as many as five unsold cargoes, information that Platts could not independently verify. The day's decline comes after Liza reached a yearly high against Dated Brent of plus $1.15\/b in July 2-3. Platts assessed Guyana's Unity Gold at flat to Dated Brent, and Payara Gold at a discount of 5 cents\/b, both also declining 75 cents\/b on the day. ","headline":"Guyana\u2019s Liza crude flips to discount against Dated Brent for first time in four months","updatedDate":"2024-08-08T22:12:10.000"},{"Unnamed: 0":198,"body":" Drilling times are down 20% from 2023 for oil producer Riley Exploration Permian, led by improved efficiencies which resulted in better cost savings over the second quarter, executives said Aug. 8. Total production was at 21.3 million barrels of oil equivalent per day, a quarterly increase of 5%. Oil production accounted for most of the growth, up 4% on the quarter at 14.7 million b\/d. Riley, formed from a late February 2021 merger between Riley Exploration and Tengasco and headquartered in Oklahoma City, closed on its acquisition in Eddy County, New Mexico, for $18.1 million in early May. The bolt-on acquisition contributed to production during the last two months of the quarter as it \"added producing properties and development locations to our existing operating footprint\" in the region, CEO Bobby Riley said during the company's second-quarter earnings call. Vertical production, which are volumes from wells that are typically less expensive to drill and less productive on average than horizontal wells, was up between 40% to 50% from 2023, Riley added. Well costs, as a result, were down by over 20% on average year over year and down over 25% compared to 2022. Drilling efficiencies paired with completion redesigns accounted for just over half of these savings, according to the company. Drilling times were down 20% from 2023 and 40% from 2022, seen largely in the producers' operations in their primary San Andres asset, called Champions, located on the Northwest Shelf of the Permian Basin. Champions consists of two fields, Wasson and Brahaney, mainly sited on the Texas side of the giant legacy oilfield which also extends into southeast New Mexico. The company produces from wells drilled to roughly 5,200 foot depths, in an area of the Permian which has produced since the 1930s and has cumulatively yielded over 2.3 billion barrels of oil. On a macro level, executives noted that increased consolidation by E&P companies was creating a \"favorable\" environment for Riley Exploration. \"We've obviously had a tremendous amount of consolidation,\" CFO Philip Riley said. \"More often than not, that's pulling demand out of the system for these services,\" \"Look at the year-over-year rig count... it's down by 90 or 100.\" Given the consolidation by E&P companies, which drop a rig or two depending on their size while they digest their new assets, there are more rigs not working and are available. As a result, there's less pressure to drive up prices due to the ample amount of idle rigs. \"We're not necessarily competing with those guys for the same rig, but it generally pulls pressure out of the system, same thing with fracking,\" he said. \"It's just a pretty favorable environment for us. Looking ahead, the company forecast midpoint growth at 13% for 2024 hinging on the oil pricing environment, which has been \"volatile\" for most of the year, Philip Riley added. \"Every time we think we're done with volatility, we get something new in the Middle East or a political backdrop or such,\" he said. \"So we'll see where prices are bouncing around and what that affords us frankly, between a $70\/b and $80\/b WTI level is fantastic. We're not holding out for 90 or 100. Our wells are economic far, far below that.\" NYMEX September WTI settled at $76.19\/b and ICE October Brent at $79.16\/b Aug. 8. ","headline":"Riley Exploration Permian sees incremental production growth on quarter","updatedDate":"2024-08-08T21:58:38.000"},{"Unnamed: 0":199,"body":" US-based petrochemical company Koppers expects sales volumes for phthalic anhydride to remain elevated going into the third quarter, CEO Leroy Ball said during the company's Aug. 8 earnings call. \"Phthalic anhydride business had a second consecutive strong quarter as we continue to catch a windfall from other production struggles in the industry,\" CEO Leroy Ball said. \"While we originally thought we could see the benefits subside by the end of Q2, it looks like we might be able to enjoy it for at least another quarter.\" The strong volumes of PA sales partially offset a decline in sales in the company's Carbon Materials and Chemicals segment in the second quarter. Koppers reported the CMC segment's sales dropped 18.22% on the year. For 2024, the company estimated annual sales growth for CMC to decrease by $60 million due primarily to price and volume declines in carbon pitch. Produced using orthoxylene, PA is an intermediate chemical used to make phthalate plasticizers, polyethyer polyols and alkyd resins, which are seen in spray paint. Additionally, PA is used to make PVC more flexible and for applications including spray foam insulation. Feedstock OX contract prices declined 4.27% in the second quarter from 58.50 cents\/lb in March to 56 cents\/lb in June, according to S&P Global Commodity Insights data. In addition to crude oil-based OX for PA production, Koppers uses carbon pitch distilled from coal tar, generated during the steelmaking process. Fellow US PA producer Stepan reported having operational issues throughout the second quarter related to a flooding event at the company's PA plant in Millsdale, Illinois, leading to lower PA volumes in the quarter, CEO Scott Behrens said during the company's July 31 earnings call. Koppers, Stepan and ExxonMobil are the three PA producers in the US. ","headline":"Koppers expects phthalic anhydride sales to remain elevated in third quarter","updatedDate":"2024-08-08T21:56:47.000"},{"Unnamed: 0":200,"body":" Canada's Frontera Energy is currently drilling oil wells in both Ecuador and Colombia as oil and gas output fell for a fourth straight quarter in Q2, CEO Orlando Cabrales said Aug. 8. The Espejo Norte-A1 well in Ecuador's Espejo Block and Hidra-1 well in Colombia's VIM-1 Block, part of the company's $272 million-$335 million 2024 capex, come as quarterly production fell 5% to 39,912 barrels of oil equivalent\/d on the year, Cabrales said on a quarterly conference call. The company produced 37,422 b\/d of crude (-4.6% on the year), while natural gas output dropped 28.6% to 4,019-Mcf\/d and gas liquids slid 2.3% to 1,785 b\/d in the second quarter, Frontera said in a statement. Production rebounded to 40,600 boe\/d in July after the company expanded both water disposal capacity at the CPE-6 and Quifa blocks and gas compression facilities at the VIM-1 block, in addition to well workovers at the Sabanero Block, all in Colombia, Cabrales said. The company remains on track to meet 2024 guidance of 40,000-42,000 boe\/d, he added. Frontera drilled 30 development wells at its Quifa, Cajua and CPE-6 blocks in Q2, according to the company. A total of 62 development wells are planned for Colombia this year. The company, looking to spin-off its Colombian infrastructure division and line up a partner for its Guyana offshore Corentyne Block, plans to start operating the Reficar hydrocarbons connection pipeline at its Puerto Bah\u00eda Caribbean port in December, while a $60 million LPG project at Puerto Bah\u00eda with Chile's Gasco is set for completion in 2027. The company, which sold oil at $72.85\/bbl (+13.7%) in the quarter, exports about 90% of its output. Frontera posted a $2.8 million quarterly loss compared with an $80 million profit a year ago, even as sales were little changed at $209 million. ","headline":"Canada's Frontera Energy currently drilling oil wells in Ecuador, Colombia: CEO says","updatedDate":"2024-08-08T21:55:57.000"},{"Unnamed: 0":201,"body":" California jet inventories slid from a nearly five-month high by 303,000 barrels to 3.163 million barrels in the week ended Aug. 2, marking the first week to week California inventory draw since the Fourth of July holiday, California Energy Commission data shows. Stocks across the US West Coast reached a record-high in the week ended July 26, measuring north of 12 million barrels, according to the Energy Information Administration\u2019s Weekly Petroleum Report released Aug. 7 like the CEC data. The USWC region is comprised of California and Hawaii, Alaska, Washington, Oregon, Nevada and Arizona. Despite California jet stock draws in the week ended Aug. 2, US jet stocks have been near or above their five-year highs since March, but the build has accelerated over the past several weeks, driven by strong imports into the USWC, according to S&P Global Commodity Insights analysts in the latest North America Short-Term Outlook for refined products. Meanwhile, the CEC in its Aug. 7 Weekly Refinery Inputs and Production Report said statewide jet output rose from a four-week low by 43,000 b\/d to 347,000 b\/d in the same week. Imports to the USWC rose to a four-week high by 38,000 b\/d to 93,000 b\/d on the week, up from 55,000 b\/d the prior week, the EIA said. A cargo carrying 327,000 barrels of jet fuel discharged in Anchorage, Alaska, on July 29, according to US Customs data. The jet arbitrage from South Korea to the USWC was estimated shut Aug. 8 at minus $1.59\/b, potentially slowing deliveries, data from S&P Global Commodity Insight\u2019s Refined Product ArbFlow daily report showed. Platts, part of Commodity Insights, assessed the differential for Los Angeles pipeline jet fuel 0.25 cent weaker on Aug. 8 at NYMEX September ULSD futures minus 18.25 cents\/gal, and its outright price dived 0.03 cent to $2.1753\/gal. California ULSD stocks soar to 18-week high as CARB output shrinks California ultra-low sulfur diesel stocks surged 234,000 barrels in the week ended Aug. 2, rising to an 18-week high 1.352 million barrels, the CEC also reported on Aug. 7. California ULSD production rose by 43,000 b\/d in the week ending Aug. 2, helping boost the state\u2019s output to over 100,000 b\/d, while output of CARB diesel, which meets stricter state specifications, slid 65,000 b\/d to 128,000 b\/d. Despite week on week draws for CARB diesel throughputs, statewide inventories rose for the third consecutive week by 57,000 barrels to reach 1.847 million barrels, marking a three-week high. Recent imports in the US West Coast showed that at least two cargoes totaling 240,000 barrels of renewable diesel were discharged in Long Beach, California, in the week ended Aug. 2, US Customs data shows. Growing renewable diesel supply will result in significant inventory builds in on the USWC, increasing diesel available for export through 2025, Commodity Insights analysts have said. USWC exports are filling a growing portion of a shrinking Latin America diesel deficit, they added. \u201cI expect by the end of the year, RD will have roughly an 80% market share of the total makeup of diesel consumption in the state,\u201d Andy Lipow, energy analyst of Lipow Oil Associates, recently told Commodity Insights. Platts assessed Los Angeles diesel differentials lower Aug. 8 at a 9.75 cents\/gal discount to September ULSD futures. San Francisco differentials were assessed unchanged at a minus 10 cents\/gal discount to September ULSD futures. ","headline":" California jet inventories buck six weeks of builds as imports rise: CEC","updatedDate":"2024-08-08T21:45:40.000"},{"Unnamed: 0":202,"body":" SBM Offshore will construct and lease a floating storage and offloading unit to Woodside Energy for the Trion oil field the company is developing in the deepwater Gulf of Mexico, SBM said Aug. 8. Trion is an alliance between Woodside and Mexican state oil and gas company Pemex, where Woodside owns a 60% state and is the operator. The Trion field is located 180 km (112 miles) off the Mexican coastline and 30 km south of the US-Mexico border, and is the first deepwater project being developed in Mexico. When complete, Trion is expected to have a production of 100,000 b\/d at peak. Woodside has said that to handle that production, it will require a 950,0000-barrel capacity floating storage and offloading vessel, or FSO. First oil is expected in 2028. The contract SBM Offshore has signed with Woodside is for a period of 20 years and complements a transportation and installation contract for the FSO and the FPU awarded to SBM in 2023, the company said in the statement. The design of the FSO is based on a Suezmax-type hull and it will be equipped with a disconnectable turret mooring system, or DTM, the company said in the statement. Turret moored FSOs allow the FSO to weathervane about the mooring system in response to the environment, allowing vessels to adapt their orientation to reduce the vessel-environment angles and the resulting load on the mooring, which allows for optimum offloading. The FSO will be moored in water depth of about 2,500 meters and will be able to store around 950,000 barrels of crude oil. According to Woodside Energy, the Trion project will target the development of an estimated 479 MMboe of best estimate contingent resource of oil and natural gas. Two-thirds of the Trion resource are expected to be produced within the first 10 years after start-up, the company has said. The total capital expenditure forecast for Trion is $7.2 billion. ","headline":"SBM Offshore to build, lease FSO unit to Woodside Energy for Mexico's Trion","updatedDate":"2024-08-08T21:37:12.000"},{"Unnamed: 0":203,"body":" US producer Occidental Petroleum hit the company\u2019s highest quarterly onshore production level in four years amid strong performance in the Permian Basin and in the Gulf of Mexico, company executives said Aug. 8. Second-quarter total production was 1.26 million barrels of oil equivalent per day, exceeding the mid-point of its guidance by 6,000 boe\/d, the company said in a statement. \u201cWe\u2019re exceeding our production expectations for onshore new wells across all our basins and are continuing to achieve operational efficiencies as we execute our capital program,\u201d CEO Vicki Hollub said during a call with investors. CrownRock deal Oxy on Aug. 1 closed its acquisition of Permian producer CrownRock. The integration of the Midland Basin assets will unlock efficiencies through infrastructure sharing, resource utilization and best practices from the organizations, Hollub said. \u201cWe absolutely believe that the CrownRock asset as a combined asset is \u2026 one of the best we\u2019ve seen,\u201d Hollub said. CrownRock will produce about 156,000 boe\/d. Oxy is maintaining its expected production levels for the full year, excluding production from CrownRock, even with the expected divestiture of 15,000 boe\/d in the fourth quarter, according to a statement from the company. Oxy had negotiated an agreement for Colombia\u2019s Ecopetrol to buy a 30% working interest of CrownRock, but Colombian President Gustavo Petro did not approve of the deal, Hollub said. \u201cHe\u2019s made it very clear to the world that he\u2019s anti-oil and gas, anti-fracking and anti-US, and with those three strikes, he pretty much dealt Ecopetrol out of the deal,\u201d Hollub said regarding Petro. \u201cUnfortunately, there are others in the world like Petro, and there are some actually in the United States like Petro, who believe that oil and gas should go away and believe that we shouldn\u2019t be an industry anymore,\u201d Hollub said. \u201cBut the reality is that, as you know, oil and gas is going to be needed for many decades to come,\u201d she said. Direct air capture project Hollub also touted progress on the company\u2019s Stratos project in Texas, which will pull carbon dioxide out of the air and put it in assets in the Midland Basin, including CrownRock, to get more oil out of the ground. The project is expected to remove and permanently store up to 500,000 metric tons of CO2e\/year when it is fully operational. Stratos is expected to be commercially operational in mid-2025, according to Oxy\u2019s presentation. In July, Oxy announced a deal with Microsoft for the sale of 500,000 metric tons of carbon dioxide removal, or CDR, credits over six years from the project. \u201cObviously, sales with Microsoft not only will be the largest CDR kind of block sale to date, but really, that counterparty meant a lot to us,\u201d said Richard Jackson, president of US onshore resources and carbon management. \u201cWe know they\u2019re very diligent in the way they think about what the product of a CDR can mean to the business,\u201d he said. ","headline":"Occidental production hits four-year high thanks to Permian, Gulf of Mexico output","updatedDate":"2024-08-08T20:40:14.000"},{"Unnamed: 0":204,"body":" Argentinian crude oil runs fell 1.2% year on year in June as a surge in fuel oil production failed to offset declines in most other products, state-run statistics department Indec reported Aug. 8. Fuel oil output increased 28% on the year in June, while gasoline output fell 5.4% and diesel output tumbled 6.8% in the same period, Indec reported. The Indec data did not provide raw data nor reasons for the changes. The country's asphalt production decreased 47% in the same period, Indec said. Crude oil run rates fell 1.4% in the first half of 2024 compared to the first half of 2023, led by a 3% decline in diesel production and a 2.7% decline in gasoline production, the data showed. Crude runs slowed in 2023 after a post-pandemic surge in 2021 and 2022, as rising inflation depressed demand. Annual inflation nearly hit 290% in April 2024 -- marking the highest inflation since a bout of hyperinflation in 1989 and 1990 -- but declined to 272% in June. The cost of living is expected to ease to 127% at the end of 2024 and 41% at the end of 2025, according to a survey of economists by the Argentinian central bank. The economy is expected to shrink 3.7% in 2024, depressing demand for petroleum products, before recovering with 3.2% growth in 2025 and 3% growth in 2026, according to the survey. State-run oil company YPF has a 55% share of diesel and gasoline sales, trailed by Shell-backed Raizen, BP-backed Pan American Energy and Trafigura. Argentina has about 560,000 b\/d of installed refining capacity, but demand generally runs at 525,000 b\/d. All of the crude is supplied domestically from fields that produced an average of 660,000 b\/d in June. However, refiners must import additional supplies of higher-grade products because of the lack of capacity to make them. ","headline":" June oil refining falls 1.2% on year, government says","updatedDate":"2024-08-08T20:20:22.000"},{"Unnamed: 0":205,"body":" The price differential for the UK's Forties crude gained over $1\/b Aug. 8, as concerns over lackluster Eastern demand subside to rapid tightening of physical crude in the wake of a force majeure at Libya's Sharara Field , which has spurred a recent uptick in demand for prompt barrels, sources said. Platts, a part of S&P Global Commodity Insights, last assessed the differential for Forties basis FOB Hound Point at a $1.39\/b premium to Dated Brent, up $1.09\/b on the day and its highest level since July 8, when the differential was assessed at $1.62\/b. The increase follows a return of buying interest for the crude as contracts across the Brent complex rebound from lows reached in recent sessions. In the Aug. 8 Platts Market on Close assessment process, five bids for cargoes of Forties were published by both Unipec and BP. UK major BP initially bid on an OCO (Order cancels order) basis for two cargoes of Forties, FOB Hound Point, loading Sept. 4-6 and Aug. 28-30, respectively. The bids both reached a $1.10\/b premium to Dated Brent and were withdrawn before the 1630 London close. Unipec initially bid for three FOB Forties cargoes, loading Aug. 24-30, Sept. 4-6, and Sept. 8-10, respectively, with the two bids for September loading crude bid for on an OCO basis. At 16:24 London time, Shell sold into Unipec's Sept. 4-6 bid at a $1.35\/b premium to Dated Brent, automatically causing the Sept. 8-10 bid to be withdrawn. Unipec's bid for an Aug. 24-20 loading cargo was reached a $1.35\/b premium to Dated Brent and was left outstanding at the London close. Around 70 fields contribute to Forties Blend, a sour crude with a sulfur content and API gravity that vary according to the percentage of Buzzard crude within the blend. Forties is one of the six crude grades that can demonstrate value for the global crude oil benchmark Dated Brent. ","headline":"Forties Differential gains more than $1\/b on the day","updatedDate":"2024-08-08T20:19:14.000"},{"Unnamed: 0":206,"body":" Crude oil futures settled higher Aug. 8 against a backdrop of continued recovery in global financial markets and tighter supply outlooks. NYMEX September WTI settled 96 cents higher at $76.19\/b and ICE October Brent climbed 83 cents to $79.16\/b. \"US crude oil inventories are at their lowest level since February, this suggests demand for physical barrels remains robust, despite concerns about weak economic activity,\" said ANZ commodity strategists. US commercial crude stocks fell 3.73 million barrels to 429.32 million barrels in the week ended Aug. 2, data from the Energy Information Administration showed Aug. 7. The draw put stocks about 6% below the five-year average for this time of year. \u201cOne of the concerns that we should have, and I think the market is starting to realize that, is that we are heading into a supply deficit with crude oil inventories falling for the 7th week in a row,\u201d Price Futures Group analyst Phil Flynn said. Meanwhile recession fears and broader demand growth concerns eased amid signs of continued stabilization in global financial markets. US equity indexes were up around 2% in afternoon trading following a stronger-than-employment report showing initial jobless claims declined by 17,000 in the week ended Aug. 3 to 233,000. NYMEX September RBOB settled up 4.19 cents at $2.3992\/gal and September ULSD climbed 22 points to $2.3578\/gal. OPEC+ output climbs in July OPEC+ crude production in July made its biggest jump in almost a year, as Iraq and Kazakhstan raised their output despite committing to deeper cuts, while Russia also remained well over its quota. The group's overall production was up 160,000 b\/d compared with June, totaling 41.03 million b\/d, the Platts OPEC+ survey from S&P Global Commodity Insights showed Aug. 8. July was the first month of compensation plans introduced by three countries that overproduced in the first half of 2024. Iraq pledged to cut an additional 70,000 b\/d in July and Kazakhstan pledged to cut a further 18,000 b\/d. Russia's compensation plan does not include additional cuts until October 2024. The survey found that Iraq produced 4.33 million b\/d in July - 400,000 b\/d above its quota. This contributed to growth in OPEC production of 130,000 b\/d to 26.89 million b\/d. The rise in output in July came despite the poor performance of the alliance's African contingent, with production in Nigeria, South Sudan, Gabon and Libya falling by a collective 80,000 b\/d. ","headline":" Crude climbs on tighter US supply, easing recession fears","updatedDate":"2024-08-08T20:08:11.000"},{"Unnamed: 0":207,"body":" The US oil and gas drilling rig count dipped 4 to 632 in the week ended July 31, S&P Global Commodity Insights data showed Aug. 8, as oil drilling activity retreated from a 12-week high. The number of active oil-focused drilling rigs declined 6 to 534, while the gas-focused rig count climbed 2 to 98. Changes in drilling activity varied across the major named oil-focused basins. The Permian Basin rig count climbed 5 to 298, a four-week high, and the number of rigs active in the Eagle Ford climbed 1 to 53. The SCOOP-STACK and Denver-Julesburg each shed a single rig, putting the total number of rigs active in those basins to 22 and 10, respectively. The number of active rigs in the Bakken held at 40 for a third straight week \u2013 the highest level since April 2023. Among the major oil plays, only the Bakken shows an annual increase in drilling activity, with rig counts up 4 from year-ago levels. Hess Midstream reported strong growth in natural gas processing volumes in the Bakken Shale in the second quarter amid strong production from its primary customer Hess Corp, and expects volumes in the basin to increase in coming years as pipeline expansions begin service. Gas processing volumes rose 17% year on year to 419 MMcf\/d in the second quarter, up from 393 MMcf\/d in the first quarter, the company reported July 31. It is guiding gas processing volumes of 405-415 MMcf\/d for 2024, and it reiterated expected annualized growth in gas throughput volumes of 10% from 2024 through 2026. Among the top gas-focused plays, Haynesville and Marcellus operators added a single rig each, putting rig counts in those basins up to 19 and 41, respectively. Utica basin operators idled a single rig, putting the total count there down to 10. A lack of sufficient pipeline takeaway capacity has weighed heavily on Permian Basin gas prices this year, with cash prices at the Waha Hub in West Texas averaging minus 53 cents\/MMBtu since March 1, Platts data showed Aug. 7. Platts is part of S&P Global Commodity Insights. Houston Ship Channel averaged $1.59\/MMBtu in the same period, while Henry Hub averaged $1.93\/MMBtu, according to Platts data. Matterhorn will send gas east toward Houston, potentially adding pressure on the Houston Ship Channel basis. The 2.5 Bcf\/d Matterhorn natural gas pipeline out of the US' Permian Basin is expected to begin service in September, EnLink Midstream CFO Benjamin Lamb said Aug. 7 . \"We expect the pipeline to be in service in the month of September,\" Lamb said during the company's second-quarter earnings call. \"That's maybe a two-week difference to what the original plan was -- toward the very end of August.\" Lamb attributed the delay to weather-related effects of Hurricane Beryl. Further exit capacity from the Permian Basin is planned for late 2026 in the form of the Blackcomb Pipeline, which reached FID on July 31 . The pipeline will be able to transport up to 2.5 Bcf\/d toward Agua Dulce in South Texas. Meanwhile, Energy Transfer hopes to announce a final investment decision on the Warrior natural gas pipeline out of the Permian Basin later this year, co-CEO Marshall McCrea said Aug. 7. ","headline":"US oil, gas rig count falls 4 to 632 as oil-focused drilling slows","updatedDate":"2024-08-08T20:04:04.000"},{"Unnamed: 0":208,"body":" Pampa Energ\u00eda, the fifth-biggest natural gas producer in Argentina, plans to increase its oil production to 50,000 b\/d by the end of 2027 from 5,000 b\/d in the second half of this year as export opportunities grow with new pipeline projects, E&P head Horacio Turri said Aug. 8. \u201cOur aim is to reach a plateau of 45,000 to 50,000 barrels per day,\u201d Turri said on a conference call with investors. To achieve this growth, Pampa is betting on Vaca Muerta, a huge shale play in the country\u2019s southwest where it has found promising results in its Rinc\u00f3n de Aranda Block. The first two wells have been put into production there, while another three pads of wells will be drilled and completed between this year and 2025 to boost the block\u2019s oil output to 10,000 b\/d to 12,000 b\/d in 2025, Turri said. This production is more than the company\u2019s existing takeaway capacity from Vaca Muerta, meaning it will have to acquire idle capacity from other companies, he added. The next jump in growth will come when YPF, Argentina's state-run energy company, completes the construction of Vaca Muerta Sur, a pipeline and export terminal designed to begin shipping 250,000 b\/d in mid-2026 via an Atlantic port and increase to 800,000 b\/d by as soon as 2030. Pampa has 48,000 b\/d of contracted capacity on Vaca Muerta Sur, Turri said. A series of midstream projects including Vaca Muerta Sur are underway or in the planning phase to increase Vaca Muerta\u2019s takeaway capacity \u2014 now at around 300,000 b\/d \u2014 to 1.4 million by 2030 or soon thereafter, with most of it going to the Atlantic and some 100,000 b\/d to the Pacific via Chile. This takeaway capacity is boosting Argentina\u2019s oil exports, which shot up 45% to 168,000 b\/d in the first half of this year from 116,000 b\/d in the year-earlier period, according to data from Econom\u00eda y Energ\u00eda, a consulting firm. The exports in the first half of this year were the highest since the 175,000 b\/d in 2005, the data showed. Argentina\u2019s oil production rose 6.5% to 660,414 b\/d in June from the year-earlier month, led by Vaca Muerta, taking the level above the 525,000 b\/d of average demand, according to Energy Secretariat data. ","headline":"Argentina's Pampa Energia to boost Vaca Muerta oil output to 50,000 b\/d by end-2027","updatedDate":"2024-08-08T19:55:10.000"},{"Unnamed: 0":209,"body":" Murphy Oil is ramping up its activity offshore Vietnam, with two exploration wells planned to be spudded during the next few months, company executives said Aug. 8. Late in the third quarter, Murphy will drill the Hai Su Vang exploration well on Block 15-2\/17, targeting a gross resource potential of 170 million to 430 million barrels of oil equivalent, President and Chief Operating Officer Eric Hambly said during a second-quarter earnings conference call. \"It's a very nice-looking prospect, a sizable prospect that will test the same type of geology as our Lac Da Vang development,\" Hambly said. At the same time, Murphy is advancing plans to drill the Lac Da Hong exploration well on Block 15-105 in the fourth quarter, he said. That \"other exciting\" well contains estimated gross resource potential of 65 million to 135 million boe, he said. Both wells are sited in the Cuu Long Basin. \"We forecast approximately $30 million in total net drilling costs for the wells,\" he added. The wells could \"create a more sizable business for us in Vietnam.\" Concurrently, Murphy is developing the Lac Da Vang project offshore Vietnam, which the company operates. Award of major contracts are currently in progress, according to Murphy's Q2 slide presentation, while facilities and pipeline contracts have already been awarded. The field contains estimated gross recoverable resources of 100 million boe, and its net peak production will be around 10,000-15,000 b\/d of oil equivalent when it comes online in 2026. Vietnam brought Murphy in-country Murphy CEO Roger Jenkins said the government of Vietnam persuaded the company to operate in its offshore based on Murphy's previous long, successful operation offshore Malaysia. In 2019, Murphy sold that business to Thailand's national oil company PTTEP for $2.1 billion, 20 years after entering the country. Wood Mackenzie said in a 2019 report the Malaysia operation, which featured both shallow- and deepwater fields, \"would come to define [Murphy's] international portfolio.\" The sale allowed Murphy to \"focus on its core positions in the US Gulf of Mexico [and] North American onshore,\" Wood Mac said at the time. Today, Jenkins said, the company has \"lots of prospects in Vietnam [and we] chose to drill a couple of big ones in a row that are very exciting in a lower-risk basin to help build up possibly a big business\" in that country. Meanwhile, in the US Gulf of Mexico Murphy, Occidental Petroleum and Chevron drilled a deepwater discovery in Q2, Ocotillo-1, unearthing about 100 feet of net pay across two zones, Hambly said. May be tied back to Oxy facility \"The partner group is currently evaluating results to determine the next steps, and we look forward to advancing this project,\" he said. \"I anticipate that it will be tied back to a nearby facility operated by Oxy.\" Another US Gulf well, named Orange \u2013 a 50-50 venture between Murphy and Oxy, 12 miles south of Ocotillo \u2013 was found to have non-commercial hydrocarbons, and has been plugged and abandoned, he added. Ocotillo and Orange complete the company's US Gulf exploration program for 2024, he added. Oxy operates both wells, which are located in upper Mississippi Canyon, about 75 miles southeast of Louisiana's \"toe.\" Murphy and Oxy both hold 33% of Ocotillo, while Chevron has 34%. Also in the US Gulf, the company is \"putting [online] a lot of nice wells\" at its operated Samurai field, which first came online in April 2022, Jenkins said. \"There are over 60 million barrels remaining in Samurai today.\" Murphy, in partnership with the former Anadarko Petroleum, paid a bonus of $105 million-plus to the US government in 2008 to lease the Green Canyon tract offshore Louisiana on which they made the discovery, in 2009. But low oil prices at the time tamped down large US Gulf oil developments. Murphy didn't resume work at the field for about a decade. Anadarko opted out of the development, and was acquired by Oxy in 2019. Drilling wells around King's Quay hub Samurai produces into the King's Quay production hub with two other fields, Khaleesi and Mormont. Jenkins said the company is currently drilling two wells around those two other fields. The Khaleesi well came online in Q2, the Mormont well in Q3. \"We have a full year [ahead] of those very high-rate wells,\" he said. In Q2, Murphy produced about 180,600 b\/d of oil equivalent, up 6.5% from Q1 but down about 2% year on year. Oil production was 91,000 b\/d in Q2, down 8% from the same period a year ago, while natural gas output was 486,000 Mcf\/d in Q2, up 9% from Q2 2023. During Q2, Murphy's Eagle Ford operation produced 28,000 boe\/d, the Tupper Montney produced around 400,000 Mcf\/d, the Kaybob Duvernay 4,000 boe\/d, the US Gulf 74,000 boe\/d and Canadian offshore, 8,000 boe\/d. Those average outputs were all roughly flattish with Q1, except for the Tupper Montney where gas volumes were up 15%. \"We have hellacious wells\" in that Canadian British Columbia play, Jenkins said. \"We continue to improve our fracking and our execution.\" Murphy's third-quarter 2024 total volumes are projected at 181,500 boe\/d to 189,500 boe\/d, up 3% at midpoint. ","headline":"Murphy Oil to drill two exploration wells offshore Vietnam in H2","updatedDate":"2024-08-08T19:53:52.000"},{"Unnamed: 0":210,"body":" Prompt Brent CFDs surged to four-month highs Aug. 8 amid a reversal of fortunes for the North Sea crude complex, rebounding sharply from notable bearishness seen during Aug. 6 trading. Brent CFDs are crude oil derivative contracts that underpin global crude oil benchmark Dated Brent, representing the perceived value difference between Dated Bent and Cash BFOE. Platts, part of S&P Global Commodity Insights, assessed the Aug. 12-16 Brent CFD at $2.61\/b, up 60 cents on the day and the highest level since April 9, when it was assessed at $2.71\/b. Similarly, the Aug. 19-23 Brent CFD was assessed at $2.16\/b, up 34 cents on the day and the highest level since April 11, when it was assessed at $2.27\/b. In contrast to the first and second week CFDs, later contracts relaxed on the day, widening the backwardated structure across late August and early September. The strength seen in prompt CFDs tracked similar movements in the DFL market, where balance month contracts also reached their highest levels since April . ","headline":"Prompt Brent CFDs reach four month highs","updatedDate":"2024-08-08T19:48:38.000"},{"Unnamed: 0":211,"body":" Canadian oil company PetroTal, Peru\u2019s largest crude producer, aims to drill three oil wells in the northern Amazon rainforest in the first quarter of 2025 as the firm accelerates expansion plans, CEO Manolo Zuniga said Aug. 8. The company, which is currently drilling the $15 million 20-H well at its Block 95 oilfields in the Maranon Basin, its fourth this year, plans $150 million-$175 million in 2025 capex as it seeks to nearly triple production capacity in the medium term, Zuniga said on a quarterly conference call. Calgary-based PetroTal, which secured $40 million in credit lines from JP Morgan and Peru\u2019s Banco de Credito, is working on a $70 million erosion prevention project at Block 95, in addition to additional water disposal capacity at the 26,000 b\/d CPF-2 processing plant and drilling at recently-acquired Block 131 in the Ucayali Basin, Zuniga added. PetroTal is holding talks with Petroperu about pumping crude through the state oil company\u2019s 200,000 b\/d North Peruvian Oil Pipeline (ONP), but does not expect to use the ONP either this year or 2025 due to high tariffs and delays in getting crude to the coastal Bayovar terminal, he said \u201cWe\u2019re looking to expand capacity to 50,000 b\/d and eventually 70,000 b\/d, so we will need to use the ONP,\u201d Zuniga said. \u201cBlock 131 could also add 5,500 b\/d.\u201d The company, which exports 600,000 b\/month to Brazil and supplies Petroperu\u2019s 12,000 b\/d Iquitos oil refinery, began loading 100,000 barrels of crude onto river barges for shipment through neighboring Ecuador\u2019s 450,000 b\/d OCP pipeline for sale in October, and may increase exports to 150,000 b\/month through Ecuador, Zuniga said. PetroTal, which averaged 20,034 b\/d in July, remains on track to meet annual production guidance of 16,500-17,500 b\/d as it navigates the upcoming dry season, where low river levels limit export barge shipments, according to a statement. Peru, whose crude production hit a 10-year high in 2019, has yet to recover to prepandemic levels as companies including Frontera Energy and Pluspetrol pulled out of northern rainforest blocks. Peru was producing 41,878 b\/d through June, according to state oil contracting agency Perupetro. ","headline":"PetroTal to drill 3 Peru oil wells in Q1 2025: company","updatedDate":"2024-08-08T19:45:46.000"},{"Unnamed: 0":212,"body":" Venezuela's 955,000 b\/d Paraguan\u00e1 Refining Center was operating at 186,000 b\/d, or 19.5% of its capacity, as of Aug. 8, over from the 18.5% reported on Aug. 1, according to a PDVSA technical report reviewed by S&P Global Commodity Insights. Located in northwestern Venezuela, Paraguan\u00e1 Refining Center, or CRP, includes the 310,000 b\/d Card\u00f3n and the 645,000 b\/d Amuay, Venezuela's largest refineries. It also includes the 16,000 b\/d Bajo Grande asphalt plant, which has been out of service for several years. According to the report, the processing rate continues to be affected by low stocks of crude oil with the specifications required by distillers. Crude oil inventories at Amuay rose to 110,000 barrels as of Aug. 8 from 70,000 barrels reported on Aug.1. Crude oil inventories at Card\u00f3n were at 650,000 barrels as of Aug. 8, according to the report. Amuay The Amuay refinery was operating at a rate of 130,000 b\/d of crude as of Aug. 8, or 20.2% of its capacity, over from the 19% reported on Aug. 1, according to the PDVSA technical report. Of the five distillers, only two are in service. The 108,000 b\/d catalytic disintegrator plant (DCAY) at its Amuay refinery remained operating at 60,000 b\/d, or 55.6% of its capacity on Aug. 8, according to the report. DCAY is a key fuel production unit to the supply of gasoline to the local market. Card\u00f3n The Card\u00f3n refinery was operating at a rate of 56,000 b\/d of crude, or 18% of its capacity, as of Aug. 8, over 17.5% reported on Aug. 1, according to the PDVSA technical report. At Card\u00f3n, three of the four distillers are out of service. The 105,000 b\/d catalytic cracking (FCC) unit at the Card\u00f3n refinery remained halted due to low vacuum gasoil inventories, the report said. At Card\u00f3n, the 55,000 b\/d naphtha hydrotreating unit was operating at 30,000 b\/d, or 54.5% of its capacity, and the 45,000 b\/d Card\u00f3n's naphtha reformer was operating at 25,000 b\/d, or 55.6% of its capacity, as of Aug. 8. These units combined are producing 20,000 b\/d of reformed, a product that is used for the production of gasoline. Gasoline supply normalized PDVSA has normalized the supply of gasoline to the local market from the CRP, which was affected by protests following the presidential elections held on July 28, according to previous reports. According to the report, 52 trucks of gasoline, 52,000 liters of capacity each, were dispatched from the Card\u00f3n refinery for overland supply, and at the Amuay refinery there were 200,000 barrels of gasoline to be sent to the Carenero, Bajo Grande and El Palito terminals as of Aug. 8. No further details were available regarding the supply of gasoline to the local market. Venezuela regularly imports gasoline and blending components as its refineries are operating well below capacity. The report did not give details of imports of gasoline manufacturing components. Venezuela's National Electoral Council declared current president Nicol\u00e1s Maduro the winner of the election, with 51.2% of 80% of the votes counted. However, Venezuela's opposition party claimed that Edmundo Gonz\u00e1lez had won the July 28 election, with 67% of votes, with 83.5% of the ballots counted, according to the most recent electoral bulletin published on Aug. 6 by the political opposition to the government of Maduro. Other refineries Venezuela's refining system nationwide consists of four large refineries: Amuay, Card\u00f3n, Puerto La Cruz and El Palito; together, have a capacity of 1.3 million b\/d, but they are currently operating at 25.9 % of capacity. The Puerto La Cruz refinery was operating at 80,000 b\/d, or 47.8% of its capacity, as of Aug. 8, according to the report . The El Palito refinery was operating at 70,000 b\/d, or 50% of its capacity, as of Aug. 8, according to the report. The 62,000 b\/d FFC information was not available. PDVSA did not respond immediately to a request for comment. ","headline":" PDVSA operates CRP complex at 19.5% of capacity","updatedDate":"2024-08-08T18:48:27.000"},{"Unnamed: 0":213,"body":" Keyera is proceeding with a planned increase in NGL and condensate processing and fractionation capacity at its Fort Saskatchewan plant in Central Alberta, as new market access is resulting in enhanced producer activity, senior company officials said Aug. 8. \u201cWe are proceeding with ordering long-lead items for a debottleneck of KFS-II and also FEED [front-end engineering and design] work for KFS-III expansion,\u201d Chief Commercial Officer James Urquhart said during a webcast of the midstream service provider\u2019s second-quarter 2024 earnings. \u201cIn early 2025, we will fully understand the cost of expansion, while in the meanwhile we continue talks with customers to underpin the expansion by offtake contracts and processing fees.\u201d The Keyera Frst Saskatchewan three-unit complex is in the company\u2019s legacy asset near the Alberta Heartland Industrial Area, with each facility having a nameplate capacity of 30,000 b\/d to 35,000 b\/d. The KFS II debottleneck and KFS-III expansion are targeted to come online in 2026 and 2028, respectively, Urquhart said. The Montney and Duvernay plays in the Western Canadian Sedimentary Basin and the heavy oil and bitumen producing areas in Northern Alberta are the prime focus areas of Keyera\u2019s well-head-to-market midstream services, CEO Dean Setoguchi said during the same webcast. Startup of the 590,000-b\/d Trans Mountain Expansion pipeline May 1 has resulted in an additional demand for condensate for oil sands and heavy oil producers, which use pentane as a diluent to move their raw bitumen through pipelines, Setoguchi said. As a rule of thumb, a single barrel of diluent, primarily pentane, is needed to reduce the viscosity of three barrels of bitumen. Rising condensate, NGLs output Keyera estimates an estimated 200,000 b\/d increase in WCSB condensate and NGLs output by 2027, compared with now, according to information on its website. S&P Global Commodity Insights data shows heavy oil production is estimated to grow by another 500,000 b\/d by 2025-26. \u201cWe will see robust demand in diluents even as TMX is being ramped up to full capacity,\u201d Setoguchi said, adding that demand and supply dynamics for liquids-rich WCSB producers will change further in the WCSB with the impending startup of the Shell-led 12 million mt\/year LNG Canada phase 1 project. Some natural gas producers have shut in production in response to low prices. However, that will change in the late fall as prices rise with the steaming of the first LNG Canada train, Urquhart said. ARC Resources has elected to curtail some 250 MMcf\/d of natural gas production in response to weak natural gas prices, the company said last week. The shut-in volumes are at its Sunrise facility in British Columbia, output from which is committed to LNG Canada. Q2 output, growth projects Keyera\u2019s gross liquids throughput last quarter was 1.487 Bcf\/d, compared with 1.456 Bcf\/d in the same quarter the prior year, the company said in its earnings release. In the last quarter, Keyera saw record throughput volumes in the North East region of British Columbia where incremental producer activity has resulted in more NGLs and condensate molecules seeking a combination of markets, fractionation and processing capacity and storage, Setoguchi said. \u201cWe also saw a continued ramp-up in the KAPS system, with the company carrying on talks for the Zone 4 expansion,\" Setoguchi said. \"A combination of TMX for crude oil, LNG Canada and other West Coast export projects for natural gas and Dow\u2019s new petrochemical expansion is creating a growing demand for G&P business.\u201d The liquids volumes will seek access on Keyera\u2019s 360-mile KAPS pipeline which is designed to handle 350,000 b\/d of condensate and 2.25 Bcf\/d of natural gas processing in the WCSB and has been developed by Keyera and SemCams Midstream under a 50:50 joint venture that is anchored by multiple long-term agreements averaging 12 years to 14 years. KAPS connects to Keyera\u2019s gas processing plants at Pipestone, Wapiti and Simonette, providing producers with options to deliver their NGLs and condensate to new markets. Keyera is working on an expansion of KAPS, to be called Zone 4 extension or NorthEast Connector, which will run from Pipestone to Gordondale in the Montney. \u201cWe will likely take a decision on Zone 4 extension by end-2024,\u201d Setoguchi said. By year-end, details will also be unveiled of Keyera\u2019s all growth projects that include KFS, KAPS and continued ramp up of KAPS, besides a low carbon hub in Alberta, CFO Aileen Marikar said during the same webcast. Meanwhile, Keyera has planned maintenance activities in the third quarter that include: a five-day outage for KFS unit 1; two weeks for work at the company\u2019s Strachan gas plant; and three weeks for the Wapiti gas plant, it said in its release. ","headline":"Canada's Keyera moves ahead with debottleneck of NGLs fractionation plant in WCSB","updatedDate":"2024-08-08T18:28:54.000"},{"Unnamed: 0":214,"body":" The differential for Kazakhstan\u2019s flagship CPC Blend crude fell to a four-week low Aug. 8, with the market currently stuck between August and September trading cycles and sellers struggling to shift remaining August-loading cargoes. Platts, part of S&P Global Commodity Insights, assessed CPC Blend at a $1.79\/b discount to Dated Brent Aug. 8, 26 cents\/b lower on the day and the steepest discount to the benchmark since July 9. This comes at a time of a broad weakening across the Mediterranean sweet crude complex amid softer local demand ahead of a heavy maintenance season in September, according to sources. Remaining August-loading barrels of CPC Blend and Azeri Light are struggling to find homes, traders said, as buyers are now looking ahead to the September trading cycle. This has been demonstrated during the Platts Market on Close assessment process with PetroIneos offering a 90,000 mt CPC Blend cargo across six separate sessions and remaining unable to find a buyer. During the Aug. 8 Platts MOC, PetroIneos offered a CPC Blend cargo loading Aug. 28- Sept. 1 which was left outstanding at a $2.15\/b discount to Dated Brent at the 1630 London close. In previous sessions across July 29, July 30, Aug. 1, Aug. 2 and Aug. 7, PetroIneos offered CPC Blend across various loading dates between Aug. 19 to Aug. 31. The offers were left outstanding between a $1.20\/b to a $2\/b discount to Dated Brent. \u201cMarket has been super slow,\u201d one trader said. \u201cCPC is down day after day.\u201d ","headline":"CPC Blend differential falls to four-week low with market stuck between trading cycles","updatedDate":"2024-08-08T18:05:54.000"},{"Unnamed: 0":215,"body":" The balance-month -- currently August -- Dated to Frontline contract gained 40 cents\/b Aug. 8 from the previous close and was assessed at the highest level since April despite a weak backdrop for European sweet crudes. The DFL represents the difference between ICE Brent futures and Dated Brent. Platts, part of S&P Global Commodity Insights, assessed the balance-month DFL contract at $1.50\/b Aug. 8, the highest since April 9. The four-month high for the balance-month DFL contract comes just two days after Platts assessed the contract at minus 25 cents\/b Aug. 6, which marked a two-month low. The backwardation between the balance month and month 1 DFL contracts has widened further Aug. 8, after the contracts briefly flipped into contango Aug. 5 and Aug. 6. Platts assessed the month 1 -- currently September -- DFL contract at 54 cents\/b Aug. 8. The strengthening in the balance-month DFL contract is typically a bullish signal for the physical crude market. However, Platts has assessed the global Dated Brent benchmark below $80\/b since Aug. 2, the first time Dated Brent has dipped below $80\/b since June 7. Market participants have pointed towards European refinery maintenance season in September as a key factor behind the recent softening in the sweet crude market. ","headline":"Balance-month DFL contract rebounds to 4-month high two days after 2-month low","updatedDate":"2024-08-08T17:39:28.000"},{"Unnamed: 0":216,"body":" Loadings of Azeri Light crude at the Turkish port of Ceyhan in September are set to total 597,667 b\/d, 25,248 b\/d below August, according to a copy of the loading program seen by S&P Global Commodity Insights Aug. 8. September\u2019s loadings are set to be above the 12-month average of 586,897 b\/d, rebounding from August\u2019s volume which marked a three-month low. Overall, 17.930 million barrels are scheduled, up from 17.745 million barrels in August, with the number of cargoes set to decrease by one, to 26. State oil company Socar is scheduled to load 81% of the program, 11 percentage points higher on the month. Throughout the week starting Aug. 5, value for Azeri Light was heard at a $3-$3.50\/b premium to Dated Brent. Platts, part of Commodity Insights, last assessed Azeri Light at a $3.35\/b premium to Dated Brent Aug. 7, marking a four-week low. A broad weakening has emerged across the Mediterranean sweet crude complex amid a softer local demand ahead of a heavy maintenance season in September, according to sources. The Mediterranean sweet crude market has so far shown minimal reaction to the total shutdown of the 300,000 b\/d Sharara oil field in Libya, market participants said. There was some concern that sweet crude prices in the Mediterranean could spike in a similar manner to what was seen in January during a two-week shutdown of the field. However, traders have mostly downplayed these concerns and pointed to a healthy supply of alternative sweet crudes. \u201cNo panic due to Sharara so far,\u201d one trader said. \u201cWTI [Midland] is still everywhere.\u201d \u201cI don\u2019t have buyers knocking on my door to replace Sharara,\u201d agreed a second trader. \u201cSome prompt WTI [Midland] around, there\u2019s ample supply.\u201d WTI Midland, imported from the US Gulf Coast, is a natural competitor to light sweet crudes in the Mediterranean such as El Sharara. According to the Platts Periodic Table of Oil, WTI Midland has a 0.2% sulfur content and API gravity of 42. Libya\u2019s El Sharara crude has a 0.08% sulfur content and API gravity of 42.6. ","headline":"Azerbaijan\u2019s Azeri Light crude September loadings set to total 597,667 b\/d","updatedDate":"2024-08-08T17:34:10.000"},{"Unnamed: 0":217,"body":" Vertex Energy will reduce third-quarter crude throughput at its Mobile, Alabama, refinery as it works to return the plant\u2019s hydrocracker to processing oil instead of renewables, its CEO Ben Cowart said on Aug. 8. \u201cIn the third quarter, we have a planned turnaround schedule in conjunction with the hydrocracker conversion that is currently in progress,\" he said on the second-quarter results call. \"This will reduce our overall throughput for Q3, but we do expect to return to our typical run rates for Q4.\" Expectations are that hydrocracker conversion will be complete and the unit will return online in Q4. Q3 crude throughput will range from 55,000 b\/d to 60,000 b\/d, with capacity utilization between 73% and 80%, lagging Q2 throughput of 68,000 b\/d or 90% utilization as planned work on the crude unit was completed ahead of schedule. Vertex\u2019s Q2 fuel margins deteriorated to $5.67\/b from $12.63\/b in Q1, due to a 28% drop on cracks. US Gulf Coast cracking margins for Light Louisiana Sweet averaged $12.32\/b in Q2, down from Q1's $18.55\/b, according to S&P Global Commodity Insights margin data. As of Aug. 8, Q3 margins are averaging $11.93\/b. Earlier this year, Vertex announced a \u201cpivot\u201d from renewables back to pure play petroleum processing, driven by weak economics for renewable diesel, as US RD supply tripled between 2021 and 2023, reaching 3 billion gal\/year, according to the US Energy Information Administration. According to Platts assessments, 100% RD delivered into Los Angeles averaged $5.048 cents\/gal so far for the week ending Aug. 9, down from the $5.138 cents\/gal for the week earlier. Platts is part of S&P Global Commodity Insights. Vertex finished depleting its renewable feedstock inventory, with Q2 throughput volumes averaging 3,092 b\/d in the quarter as it returns to conventional oil processing. ","headline":" Vertex Energy to cut Q3 crude throughput rates as Mobile returns to pure play oil","updatedDate":"2024-08-08T17:08:17.000"},{"Unnamed: 0":218,"body":" Algeria's national oil company Sonatrach is set to resume exploration activities in neighboring Niger, five years after drilling its last well there and a year on from a coup in the oil-rich country. In a statement released Aug. 7, Sonatrach said its subsidiary Sipex would \u201cresume work on the Kafra block with a mutually agreed implementation schedule.\u201d It did not elaborate on a timeline for or details of a potential drilling campaign. The announcement followed a \u201cworking visit\u201d to Niamey on Aug. 6 and 7 by Algeria\u2019s minister of energy and mines, Mohamed Arkab, and Sonatrach CEO Rachid Hachichi, the NOC said. The delegation also discussed cooperation opportunities for Sonatrach and the Nigerien NOC Sonidep, including reviving large-scale projects such as the ambitious trans-Sahara pipeline, designed to carry oil from regional oil heavyweight Nigeria to Europe via Niger and Algeria. Sonatrach has built an impressive global portfolio of upstream and downstream assets in recent years, including in South America and across West and North Africa. Niger holds 1 billion barrels of 2P oil reserves, according to the African Petroleum Producers Organization, of which it is a member. Kafra license In February 2022, Sonatrach extended its production sharing contract on the Kafra block in Niger, which sits near the Algerian border in the Chad Basin, not far from the country\u2019s Chinese-operated Agadem Rift projects. The contract on the 23,000 sq km license was first signed in 2015. The Algerian company drilled two wildcats on the project in 2018 and 2019, with the first, KFR-1, discovering some 168 million barrels of heavy oil in place, and the second, KFRN-1, finding a further 100 million barrels. Since the discoveries, Niger has experienced a military coup , in July 2023, and has emerged as a significant oil producer -- at up to 110,000 b\/d -- thanks to a Chinese-built export pipeline to Benin\u2019s Seme port, which allowed the country to briefly hike its oil output from some 20,000 b\/d. The pipeline loaded its first 1 million barrel cargo of heavy sweet Meleck crude in May, but an ongoing feud between Niger and Benin -- dating back to sanctions imposed on Niger last year by regional bloc Ecowas -- has prevented the lifting of a second cargo. Sources said the pipeline, which is also facing attacks by anti-government groups in Niger, is currently idled. It is currently the landlocked country's sole oil export option. Meleck has a 24.4 API gravity and sulfur content of 0.354%, according to China's CNPC, making it comparable to Angola\u2019s Pazflor and Dalia grades, which are sold primarily into China. The first cargo headed to France. London-listed Savannah Energy is the sole Western energy company operating in Niger and hopes to bring a 1,500 b\/d oil project at its R3 East fields online in 2025, before ramping up to 5,000 b\/d. Niger\u2019s President Abdourahmane Tchiani has also flipped his country\u2019s traditional alliances, ejecting US and French troops, rescinding permits of French uranium miners, severing diplomatic ties with Ukraine on Aug. 7 and signing a security pact with Russia. Meanwhile, on July 17 Niger signed an agreement with Turkey to strengthen oil and gas cooperation and entice Turkish companies into its oil patch. Last year, Algeria offered to mediate and publicly opposed potential Western intervention following the removal of Niger\u2019s elected president Mohamed Bazoum, a close Western security partner. ","headline":"Algeria's Sonatrach to resume oil exploration in Niger after 5-year hiatus","updatedDate":"2024-08-08T16:58:29.000"},{"Unnamed: 0":219,"body":" The Platts FOB New Orleans SOYBEX assessment for one calendar month forward set a new record-low outright price on Aug. 7 amid high old-crop soybeans stocks. Platts, part of S&P Global Commodity Insights, assessed FOB New Orleans SOYBEX for one calendar month forward -- September shipment -- at $409.97\/mt on Aug. 7. The previous record low was set Sept. 15, 2020, at $409.88\/mt. \u201cFarmers had held on to a larger percentage of stocks and a larger outright total of soybean bushels than in the past,\u201d Jack Larimer, Commodity Insights analyst, said. \u201cThis was likely due to farmers waiting for a weather rally.\u201d US farmers held 466 million bushels, or 12.682 million metric tons, of old-crop soybeans on June 1, according to the US Department of Agriculture's last Grains Stock report. On-farm old crop stocks rose 44% from a year ago. US farmers have been waiting for a weather rally to release their old-crop stocks, as prices have been weaker on the previous year. Additionally, the expected weather rally never materialized, and with the growing season almost over, farmers have been selling their old crop since the new-crop is coming soon, sources said. In addition to farmers' high old-crop stocks, new-crop conditions have been better than the previous year, and thus have been pressuring US soybean values. The USDA said in its last Crop Progress report Aug. 5 that 68% of the intended US soybean acreage was rated in good-to-excellent condition on Aug. 4. The figure was 14 percentage points above year-ago crop ratings and was the highest US soybean crop rating for that week since 2020, according to USDA data. In addition to the ample supplies, export demand for US soybeans as been weak, as crush margins were worsening in China, the main US soybean buyer. Additionally, US soybeans have not been competing yet against the Brazilian origin in China, sources added. According to USDA projections, 41% of the total US soybeans production estimated for MY 2024-25 was to be exported, with US supplies expected to account for 28% of global exports. Soybeans are crushed to produce soybean oil -- which can be blended with fuels -- and to produce soybean meal, a source of protein in feed rations. ","headline":"FOB New Orleans SOYBEX hits four-year low amid high old-crop stocks","updatedDate":"2024-08-08T16:38:24.000"},{"Unnamed: 0":220,"body":" Product tanker markets are experiencing short-term downward pressure with more dirty tankers being used to transport refined products in recent weeks, while dry bulk freight rates remain well supported by healthy tonnage demand, Danish ship operator Norden said Aug. 8. Since last month, dirty tankers up to VLCCs have been cleaned and used to ship diesel from the Middle East to Northwest Europe, with market participants seeking to take advantage of their lower unit freight cost. The pivot has undercut demand for product tankers and led to weaker freight. Based on Platts data from S&P Global Commodity Insights, the LR2 rate for transporting 75,000 metric tons of refined products from the Persian Gulf to UK Continent fell to $53.47 per metric ton Aug. 8 from $74.20\/t July 1. While the sector remains supported by incremental ton-mile demand due to disruptions to Russian oil flows since the Ukraine war and Red Sea shipping crisis, Norden said in its quarterly report that \"short-term headwinds from weak crude led to larger tankers switching from crude to clean trades.\" But the Copenhagen-listed company added the negative effect should diminish, with dirty tankers' fundamentals supported by a small order book by historical standards and expected higher OPEC exports. Despite a brief spike to $13.34\/t on July 24, the Arab Gulf-China VLCC rate fell to $10.11\/t Aug. 8 from $10.95\/t July 1 amid seasonal demand weakness, according to Platts. VLCC rates tend to increase from early autumn. Norden remains bullish on its freight outlook for dry bulk carriers, saying rates are supported by geopolitical disruptions, cargo growth and less competition from containerships. \"The dry cargo market continued the positive trend from the past quarters \u2026 driven by solid demand growth, longer distances for iron import to China, diversions related to the situation around the Red Sea, and positive impact from the increase in container freight rates,\" the company said. The Platts Global Dry Bulk Index time charter equivalent for non-scrubber ships was assessed at $18,962\/d on Aug. 7, up from $11,189\/d when the assessment started in November 2023. Weaker margins Norden, which operates 542 tankers and dry bulk carriers, reported its second-quarter revenue increased to $1.03 billion from $953 million in the year-ago period. But its net profit more than halved to $46 million from $108 million due to negative margins of its freight trading unit. This resulted from \"higher [dry bulk] charter costs from covering the short position from the first quarter, combined with higher voyage costs related to weather and ballast,\" the company said. \"Margins were further impacted by costs related to new vessel charters and repositioning of tonnage on lower-paying back-haul voyages with expected future benefits.\" Norden has narrowed its full-year guidance to a net profit between $160 million and $240 million from $150 million-$250 million previously. ","headline":"Product tankers face short-term headwinds from dirty tanker competition: Norden","updatedDate":"2024-08-08T15:29:48.000"},{"Unnamed: 0":221,"body":" Japan Organization for Metals and Energy Security said Aug. 8 that it will invest together with Idemitsu Kosan up to $36 million in synthetic fuels producer HIF Global, marking JOGMEC's first equity investment for e-fuels projects. In its first move following the amendments to the JOGMEC Act in 2022 to be allowed to invest in hydrogen-related production and storage businesses, JOGMEC said it will invest with Idemitsu through its subsidiary to HIF Global, following the Japanese company's $114 million investment announced in May. JOGMEC said e-fuels\u2014 being produced by synthesizing hydrogen from renewable energy sources and CO2 \u2014can be utilized in existing infrastructures as well as being able to drop in to existing engines without any modifications, which will play a key role as an early decarbonization step. HIF Global has been producing e-Fuels since December 2022 at the Haru Oni demonstration plant in Magallanes, Chile, and the company is now developing commercial-scale e-fuels projects in the US, Australia, Chile, and Uruguay, with an aim to produce 4 million mt\/year of e-methanol equivalent, JOGMEC said. Through this investment, JOGMEC said Idemitsu plans to source e-methanol from HIF Global's facilities and is committed to building up an e-fuels supply chain around Japan. JOGMEC added it also intends to accelerate support for the development of hydrogen including e-fuels as part of its efforts to drive Japan's decarbonization and energy transition. Idemitsu, meanwhile, plans to develop 500,000 mt\/year e-methanol supply by 2035 through its acquisition of a minority stake in HIF Global announced in May. Through its investment in HIF Global, Idemitsu has said it aims to develop the e-methanol supply chain in Japan and abroad with its high multiplicity of use not only as a bunker fuel but also as feedstocks to produce other e-fuels and synthetic chemicals. Idemitsu Kosan said in April 2023 it had signed a strategic partnership with HIF, under which Idemitsu aims to develop e-fuel supply chains of several hundreds of thousands kiloliters per year in Japan by the second half of the 2020s. ","headline":"JOGMEC to make first investment for e-fuels with Idemitsu in HIF Global","updatedDate":"2024-08-08T13:50:36.000"},{"Unnamed: 0":222,"body":" European LNG prices surged to their highest levels in 2024 as market participants prepare for winter amid multiple ongoing and upcoming supply concerns, exacerbated lately by geopolitical concerns. On Aug. 7, Platts, part of S&P Global Commodity Insights, assessed DES Northwest Europe LNG marker at $12.216\/MMBtu, DES Mediterranean at $12.271\/MMBtu and DES East Mediterranean at $12.466\/MMBtu. These prices were the highest since Dec. 1 for NWE and Mediterranean, which were then at $12.981\/MMBtu and $12.881\/MMBtu, respectively, and the highest for East Mediterranean since its inception on Dec. 20. Bullish sentiment has also spread into the region across the Atlantic. Platts assessed DES Brazil and FOB GCM values at $12.151\/MMBtu and $11.49\/MMBtu, respectively, the highest since Dec. 1 for Brazil and Nov. 24 for GCM, Commodity Insights data showed. Prices have increased by approximately 19%-26% since July 25, with the average price between July 25 and Aug. 7 around 15%-33% higher than the same period last year. Several supply-side issues shifted market sentiment from bearish to bullish, contributing to the price rise. In the most recent move, Ukrainian troops approached the Russian border near the Sudzha interconnection point, intensifying an already bullish market. This movement has unsettled the market, with concerns that any conflict near the interconnection point could damage pipeline infrastructure, potentially reducing Russian gas flows to Europe via Ukraine. Sudzha is currently the sole entry point for Russian gas into Europe through Ukraine. Despite these concerns, Ukrainian grid operator GTSOU reported on Aug. 7 that Russian gas flows through Ukraine were continuing as expected. Additionally, the extension of planned maintenance at several Norwegian facilities is sustaining the bullish market outlook. Maintenance at the K\u00e5rst\u00f8 facility, which began late June, has been extended to Aug. 9, affecting 9.6 million cu m\/d of capacity. Maintenance at the St. Fergus exit terminal has also been extended by 19 days, impacting 16.8 million cu m\/d of capacity. This, along with the upcoming planned maintenances at Norwegian facilities starting September, has made market participants uneasy. Traders warn that these risks, if prolonged into winter, could significantly impact Europe\u2019s gas supply. Middle East tensions have escalated, notably the Israel-Lebanon and Israel-Iran conflicts, while Suez Canal restrictions have kept Mediterranean prices high for much of the year. This continues to make the market nervous, as further escalation could directly impact Israeli gas supply, Middle Eastern oil supply and shipping routes, thereby exerting pressure on the global energy complex. While the outlook for coming months remains bullish, immediate demand in Europe, especially in Northwest Europe, is still weak. The Mediterranean region has seen some demand support due to hot weather, but NWE countries have not followed this trend. Despite the current supply issues, European gas inventories are at healthy levels, 86.48% full on Aug. 6, according to Gas Infrastructure Europe, with nearly two months left to build inventories before winter. Asian demand for cargoes is also keeping prices elevated in the region. As the fourth quarter approaches, the market expects a return to seasonal norms. However, anticipated heatwaves in Asia in September could delay this adjustment. ","headline":"European LNG prices hit 8-month high amid geopolitical tensions","updatedDate":"2024-08-08T13:47:51.000"},{"Unnamed: 0":223,"body":" Asia-Pacific Long Range tankers hit their lowest freight levels so far this year Aug. 8 as refiners reduced their output and shipments due to poor earnings at a time when several dirty tankers have turned clean in their quest for better returns. Rates were lower day on day on 19 of the 22 trading days in July and four of the six trading days so far in August, according to S&P Global Commodity Insights data. The general refrain among traders was that every time it seemed freight was close to bottoming out, it hit fresh lows due to fewer cargoes seeking tonnage in the Persian Gulf spot market. Weak refinery margins and the switchover of Aframax tankers from dirty to the clean segment has added to the woes of owners, several sources said. Freight on the LR1 benchmark Persian Gulf-Japan route has declined w86 since the start of July and more than halved in the last 10 weeks, Commodity Insights data showed. Several LR1s are doing short voyages within the Persian Gulf while waiting for freight levels to improve. According to the estimates of brokers, at least 60 dirty tankers, of all sizes combined, have turned clean so far this year, adding to supply and dragging down freight in the process. Only two LR2 cargoes were quoted in the market Aug. 6 for loading in the Persian Gulf, after which owners hurried to finalize deals on expectations of a further drop in freight, said a clean oil tankers broker in Singapore. He said there is hardly any demand to move gasoil and jet fuel from the Persian Gulf and India to Europe. \"Weak LR1s and going forward the narrow spread with LR2s implies there is still downside potential,\" the broker said. Due to the economies of scale, the LR2s typically enjoy a discount of 20-30 Worldscale points to LR1s on the Persian Gulf-North Asia routes but amid falling freight it has whittled to just over w5, Commodity Insights data showed. Despite the significant decline in rates, LR1 owners can still earn close to $18,500\/day on round trip basis on the benchmark Persian Gulf-Japan route, assuming bunker prices of around $588\/mt, brokers said. The corresponding earnings on the same route for LR2s is just over $26,000\/day, brokers added. The recent fall in bunker prices has prevented a bigger erosion in earnings. In the second half of March, these LR1 and LR2 earnings had peaked for this year around $65,000\/day and $90,000\/day, respectively, despite the bunker prices being $60\/mt above current levels, according to the estimates of brokers. ","headline":"Asia Pacific clean LR tankers' freight hits 2024 lows on slowdown in Persian Gulf shipments","updatedDate":"2024-08-08T13:08:37.000"},{"Unnamed: 0":224,"body":" China's overall crude throughput is set to recover in July and August after reaching a six-month low in June, as scheduled refinery maintenance winds down, but throughput levels will remain lower on the year amid weak domestic demand, according to sources and analysts. China processed 14.25 million b\/d (58.32 million mt) of crude in June, down 3.7% year on year and 0.4% from May on a barrel-per-day basis to the lowest since 14.21 million b\/d in December 2023. The average utilization rate at the 50 state-owned refineries fell to a 22-month low of 78.4% in June, from a 12-month low of 78.7% in May. The average utilization rate for independent refineries in Shandong was 52% in June, the lowest since the pandemic first struck the country, according to local information provider JLC. Meanwhile, in July, China's combined throughput -- which includes state-run refineries and mega private plants -- reached 10.23 million b\/d with an 83% utilization rate, lower than the 10.41 million b\/d and 85.6% capacity a year ago. The operating rate at China's small independent refineries edged up to 53% in July from a four-year low of 52% in June, although this was still significantly below the 62% in July 2023, according to local information provider JLC. The average utilization rate at 50 state-owned refineries grew to 80% in July, compared with a 22-month low of 78.4% in June and a 12-month low of 78.7% in May. PetroChina kept its run rates largely stable at around 74.3% in July, compared with 74.2% in June, as its Ningxia Petrochemical was shut for maintenance in early July, offsetting the throughput uptick from Dushanzi Petrochemical's restart. Sinopec lifted its utilization rate to around 81.9% in July from a 22-month low of 78.9% in June. The other two state refiners, CNOOC's Huizhou Petrochemical and Sinochem's Quanzhou Petrochemical, were operating at relatively higher run rates in July, at 102% and 94%, respectively. The utilization rate at private refineries was kept relatively higher compared with their state-owned peers. Hengli Petrochemical (Dalian) Refinery was operating at around 98% of capacity in July, up from around 71% in June, when the refinery completed overall maintenance, while the 800,000-b\/d ZPC upped its run rate to around 108% in July, from 105% in June. The 320,000-b\/d Shenghong Petrochemical lowered its operating rate to around 103% in July, compared with 106% in June. The utilization rate at smaller independent refineries in China's eastern Shandong province was also marginally higher in July, amid slightly improved refining margins. Throughput in August is expected to increase further from July levels as Dushanzi Petrochemical, Qilu Petrochemical, Maoming Petrochemical and Dalian Wepec resume normal operations, sources said. In other news, China's Zhejiang Petrochemicals has started commissioning activities at its phase 2 of 1.6 million mt\/year acrylonitrile-butadiene-styrene project, market sources said. The phase 2 of the plant's commissioning will take place over four stages, bringing in 300,000 mt\/year of capacity each time or a total of 1.2 million mt\/year. Market sources estimate that the commissioning activity of the two stages will be completed by the end of 2024. Nanjing Jinling Huntsman New Material's MTBE refinery in Nanjing, China, is scheduled for a turnaround from mid-August, a source close to the company said July 23. Separately, China\u2019s Shandong provincial government could allow independent refineries in the region to share Yulong Petrochemical\u2019s crude oil quota for 2024, as the commissioning of its new 400,000 b\/d refinery has been delayed, local refiners said. Meanwhile in Japan refinery run rates rose to 66.6% in the week to Aug. 3, from 63.6% the previous week, on higher crude throughput, the Petroleum Association of Japan said Aug. 7. The country's crude throughput was up 4.7% over the same period at 2.07 million b\/d. Seven refining units, with a total production capacity of 790,200 b\/d, were offline across Japan as of Aug. 3 -- four on planned maintenance, two following technical issues and another due to operational adjustments -- based on information compiled by S&P Global Commodity Insights. Separately, as part of its response to jet fuel shortages and to make up its production loss from scheduled maintenance at Hokkaido, Idemitsu Kosan, the second-largest refiner in Japan, plans to boost its jet fuel imports as well as refinery capacities at the Chiba, Aichi and Yokkaichi refineries, an Idemitsu spokesperson said July 22. Some incidents were reported at refineries in Japan. Japan's Idemitsu Kosan said July 12 that its rack asphalt shipping facility at the Yokkaichi refinery in central Japan was hit by fire around 9:18 am local time (0018 GMT), and rack shipments of oil products were suspended. The fire was extinguished by the public fire department around 10:23 am and no one was injured, a company spokesperson said July 12. The 100,000 b\/d No. 1 crude distillation unit and 155,000 b\/d No. 2 CDU were operating normally, and waterborne shipments from the refinery are continuing. The Chiba refinery run by ENEOS in Tokyo Bay caught fire July 29, though there was no impact on the sole 129,000 b\/d crude distillation unit. The fire was confirmed on the heating unit at around 2:10 am local time (1710 GMT, June 28) and was put out at around 3:11 am without any injuries, according to a spokesperson of the local fire department. The Hokkaido refinery in northern Japan run by Idemitsu Kosan caught fire July 30, though there was no impact on the sole 150,000 b\/d crude distillation unit as all units including the CDU were already shut for planned maintenance June 22, a company spokesperson said July 30. The fire was confirmed on a sulfur tank at around 9:44 am local time (0044 GMT) and was put out at around 10:41 am without any injuries, according to the spokesperson. The CDU will restart its operation in the fall after the maintenance, the spokesperson added. NEW AND ONGOING MAINTENANCE Refinery Capacity b\/d Country Owner Unit Duration Negishi 153,000 Japan ENEOS Part Closure'22 Wakayama 127,500 Japan ENEOS Full Closure'23 Yamaguchi 120,000 Japan Idemitsu Full Closure'24 Chiba 177,000 Japan Cosmo Part May Kikuma 138,000 Japan Taiyo Oil Full Jun, Nov Kawasaki 249,100 Japan ENEOS Part March Yokkaichi 86,000 Japan Idemitsu Full Sep Oita 136,000 Japan ENEOS Full May Hokkaido 150,000 Japan Idemitsu Full June Tianjin 276,000 China Sinopec Part Deferred Shandong 52,000 China Shenchi Full Jan 240,000 China PetroChina Full Oct Ningxia 100,000 China PetroChina Full July Jilin 200,000 China PetroChina Full Aug Lianhe 114,000 China Joint Full April Hengli Dalian 400,000 China Hengli Part April ZPC 800,000 China Joint Part April North Huajin 126,000 China Norinco Full July UPGRADES Zhenhai 230,000 China Sinopec Expansion 2030 Jinling 420,000 China Sinopec Upgrade NA Haiyou 70,000 China Haiyou Upgrade On hold Huizhou 440,000 China CNOOC Upgrade NA Changling 230,000 China Sinopec Upgrade NA Qinzhou 240,000 China Guanxi Upgrade 2023 Fujian 280,000 China Sinopec Upgrade NA Guangxi 240,000 China Petrochina Upgrade 2025 LAUNCHES Tangshang 300,000 China Xuyang Group Launch NA Huajin Aramco 300,000 China Joint Launch 2026 Yulong 400,000 China Yulong Launch 2024 Gulei 320,000 China Joint Launch 2025 Near-term maintenance New and revised entries Japan ** ENEOS shut the sole 145,000-b\/d crude distillation unit at its Sendai refinery in northeast Japan on Aug. 1 due to technical issues, a company spokesperson said Aug. 2. The refinery continues to ship oil products to both the rack and seaborne markets, although no date has been set for the restart of the CDU, the spokesperson said. ** ENEOS restarted the sole 129,000-b\/d CDU at its Chiba refinery in Tokyo Bay on July 28 after it was shut July 23 due to technical issues. The Chiba refinery caught fire July 29, though there was no impact on the CDU, the spokesperson added. ** Japan's ENEOS restarted the sole 168,000-b\/d crude distillation unit at its 203,100-b\/d Kashima refinery on the east coast July 11 after completing unplanned works, a spokesperson said July 18. The company stopped operating the CDU on June 29, citing technical issues, but did not provide further details. At the Kashima refinery, the 35,100 b\/d condensate splitter has also been shut since June 2021 due to operational adjustments. There is currently no prospect of restarting this unit, the spokesperson added. ** Japan's Cosmo Oil restarted the 75,000 b\/d No. 1 CDU at its 177,000 b\/d Chiba refinery in Tokyo Bay Aug. 4 after technical issues, a company spokesperson said Aug. 5. The crude distillation unit had been shut June 6-July 16 due to planned maintenance to update power-related equipment. It was shut again July 17 due to technical issues. ** Japanese refiner Taiyo Oil restarted its 106,000 b\/d No. 1 CDU on July 13 and 32,000 b\/d No. 2 CDU on July 19 at its sole Shikoku refinery in Ehime, also known as Kikuma, after regular maintenance, a company spokesperson said July 23. The company had shut the No.1 CDU on June 25 and No.2 CDU on June 26. The spokesperson added that the CDUs will be shut again for about three months in the winter starting end-2024, with restart expected in early 2025. ** The Hokkaido refinery in northern Japan run by Idemitsu Kosan caught fire July 30, though there was no impact on the sole 150,000 b\/d crude distillation unit as all units including the CDU were already shut for planned maintenance June 22, a company spokesperson said July 30. The maintenance is expected to run until mid-September. China ** PetroChina\u2019s Dushanzi Petrochemical restarted July 6 form maintenance that started May 15. ** Sinopec Qilu Petrochemical in eastern Shandong province restarted July 11 from maintenance on a CDU Unit, which started May 19. ** Maoming Petrochemical has been carrying out works on a 100,000 b\/d CDU since May 25 until July 19. ** Jinling Petrochemical will carry out works between Nov. 15-Dec. 31. ** China's North Huajin refinery in the northeastern Liaoning province has shut for scheduled maintenance from July 10, which will last for about two months till early September, a source with knowledge of the matter said July 15. Huajin last carried out a scheduled maintenance over July-August 2021 for about two months. Existing entries Japan ** Idemitsu Kosan shut the 61,000 b\/d RFCC at its 260,000 b\/d Yokkaichi refinery in central Japan due to technical issues, a company official said June 18, but declined to mention a specific date. Idemitsu Kosan plans to shut the sole 86,000-b\/d CDU at its Yokkaichi refinery in central Japan between late September and mid-November for planned maintenance. ** Japan's ENEOS shut its 172,100 b\/d No. 2 crude distillation unit at its 249,100 b\/d Kawasaki refinery in Tokyo Bay from May 13 to mid-August for a planned maintenance, a company spokesperson said May 14. ENEOS is now carrying out a large-scale maintenance at the 77,000 b\/d No. 3 CDU at its Kawasaki refinery, which has been suspended since March 22. The No. 3 CDU will restart the operations in end-August. ** Japan's ENEOS shut the sole 136,000 b\/d CDU at its Oita refinery in the southwest from May 13 to end-August for a scheduled maintenance. ** Idemitsu Kosan decommissioned the sole 120,000 b\/d crude distillation unit at its Yamaguchi refinery in western Japan March 1, 2024 as initially planned. In June 2022, the company had announced its plan to shut the refining functions at its Yamaguchi refinery in March 2024 as part of its restructuring. The refinery site will be converted into an oil terminal. ** ENEOS decommissioned the sole 120,400 b\/d CDU at its Wakayama refinery in western Japan in October 2023 as initially planned, a spokesperson said. ** ENEOS decommissioned the 120,000 b\/d No. 1 CDU at its 270,000 b\/d Negishi refinery in Tokyo Bay by early October 2022 as planned, a company spokesperson said. China ** PetroChina's Dalian Wepec shut for full maintenance over June 5-July 24. ** Sinopec's Tianjin Petrochemical, which had initially planned to shut one 50,000 b\/d CDU for maintenance in October 2023, postponed maintenance to 2024, sources said. Tianjin Petrochemical will shut its 50,000 b\/d CDU for maintenance over July 16-Sep. 30. ** Sinopec's Fujian will have full maintenance Nov. 1-Dec. 20. ** Sinopec's Wuhan Petrochemical will carry out full maintenance between Oct. 13-Dec.13. ** PetroChina's Guangxi Petrochemical will shut for overall maintenance over Oct. 11-Nov. 30. ** PetroChina's Ningxia Petrochemical will shut for overall maintenance over July 3-Aug. 31 ** PetroChina's Jilin Petrochemical to shut for overall maintenance over Aug. 24-Oct. 14. Upgrades Existing entries ** PetroChina's Dalian Petrochemical is phasing out its No. 1 crude distillation unit (120,000 b\/d), which has been idled since October 2023. Along with this CDU, an 800,000 mt\/year FCC, a 600,000 mt\/year reformer unit and a few other units will also be shut. The company also plans to move Dalian Petrochemical to the Changxing Island in the same city of Dalian to consolidate its overall capacity to 400,000 b\/d from the current 410,000 b\/d with a new 1.2 million mt\/year ethylene plant. ** Sinopec Zhenhai's expansion and upgrading project with a new 1.5 million mt\/year ethylene plant is scheduled to complete by year-end. Zhenhai aims to grow its refining capacity to 60 million mt\/year and 7 million mt\/year of ethylene by 2030. Expansion and an upgrading project with a new 1.5 million mt\/year ethylene plant is scheduled to complete by year-end. ** China's Hengli has been upgrading two of its 3.2 million mt\/year reformers to 3.8 million mt\/year each, with work on the first one already completed. Although the first reformer has been upgraded, it is yet to fully integrate at higher levels, as this depends on aromatics demand. Both reformers have been running at 92%-95%. ** Sinopec's new Hunan Petrochemical has been running about 60 units consolidated from Changling Refining & Chemical and Baling Petrochemical in Hunan province since Jan. 1, the company said on its official Wechat platform Jan. 30. The 300,000 b\/d Hunan Petrochemical was set up June 2023 as a key Sinopec project to consolidate its 230,000 b\/d Changling Refining & Chemical and 70,000 b\/d Baling Petrochemical in Hunan province. According to the project planning, the 160,000 b\/d CDU at Changling will be upgraded to 200,000 b\/d while the other 70,000 b\/d CDU will be mothballed. The sole 70,000 b\/d CDU at Baling will shut. The upgrade of the refining projects will include constructing a 3 million mt\/year hydrocracking unit, a 60,000 mt\/year sulfur recovery unit, a 1 million mt\/year solvent deasphalting unit and public utilities. Meanwhile, Hunan Petrochemical will have a new 1 million mt\/year ethylene plant, along with a 500,000 mt\/year gasoline hydrocracker and another 12 units in addition to public utilities at the Yueyang Green Chemical High-tech Industrial Development Zone in central Hunan province. ** PetroChina's Guangxi Petrochemical has started construction work on an upgrading project that will increase its petrochemical output by 2.76 million mt\/year, following a groundbreaking ceremony held a day earlier, it said on its official WeChat account in March 2023. The upgrading project is due to be completed in 2025. As part of the project, 14 new petrochemical units will be set up, including a 1.2 million mt\/year ethylene unit, a 350,000 mt\/year aromatics extraction unit, a 400,000 mt\/year HDPE unit, a 300,000 mt\/year HDPE unit, a 300,000 mt\/year EVA unit, a 100,000 mt\/year H-EVA unit and a 400,000 mt\/year PP unit. Two units will also be set up in the refining zone, including a 2 million mt\/year gasoil adsorption de-aromatization unit and a 400,000 mt\/year C2 recovery unit. Upon completion, the refinery's gasoline and gasoil output will be reduced to maximize feedstock for the downstream ethylene plant. Guangxi Petrochemical was set up in 2010 with an initial capacity of 10 million mt\/year and was upgraded to 12 million mt\/year in 2014 by adding a 4 million mt\/year residual oil hydrodesulfurization unit, which enabled the refinery to process crudes with higher sulfur content. ** A 1.2 million mt\/year ethylene project by the Jilin Petrochemical in northeastern China's Jilin province began early 2022. ** Sinopec plans to add a petrochemical plant to its Fujian refining complex as part of its phase two expansion plans, according to a company source. \"An ethylene plant will likely be added,\" said the source, without giving more details as the plans are still in the early stages. Saudi Aramco and Sinopec said they would undertake a feasibility study looking into \"optimization and expansion of capacity\" at Fujian. ** Sinopec's Changling Petrochemical in central Hunan province plans to start construction for its newly approved 1 million mt\/year reformer. ** Axens said its Paramax technology has been selected by state-owned China National Offshore Oil Corp. for the petrochemical expansion at the plant. The project aims at increasing the high-purity aromatics production capacity to 3 million mt\/year. The new aromatics complex will produce 1.5 million mt\/year of paraxylene in a single train. ** Construction of a new 1 million mt\/year coker at Chinese independent refinery Haiyou Petrochemical, in eastern Shandong, has been put on hold. ** Sinopec's Jinling Petrochemical refinery in eastern China will build a new 600,000 mt\/year VDU. Launches New and revised entries ** The start up of China\u2019s new Yulong Petrochemical refinery has been delayed with the refinery expected to start trial runs most likely in Q4. Yulong has been expected to start trial runs in June at the earliest. However, the trial run has now been delayed to Q3 though sources expect it to be rescheduled again to October-November mostly due to sluggish domestic demand. Phase I of the Yulong project includes two CDUs with a capacity of 10 million mt\/year each, two 1.5 million mt\/year ethylene units and one 500,000 mt\/year styrene unit. Yulong also expects to have a second phase for the project with a designed capacity of 400,000 b\/d, which is yet to be approved by the government. Existing entries ** Huajin Aramco Petrochemical Company's 300,000 b\/d integrated refinery and petrochemical complex in Panjin city, Liaoning province, in China, started the construction work at two key units Jan. 18, 2024, the company said on its official WeChat account late Jan. 19. A ground-breaking ceremony for the start of construction at its 1.65 million mt\/year ethylene cracker and the 5 million mt\/year residue hydrogenation unit took place Jan. 18. The ethylene cracker -- which has been expanded from the originally designed 1.5 million mt\/year capacity -- and the residue hydrogenation unit are core units of the whole project. The ethylene unit, which is the leading chemical unit, will produce polyethylene, propylene and byproducts such as gasoline, hydrogen and cracked fuel oil. Meanwhile, the residue hydrogenation unit will produce feedstock for fluid catalytic cracker units, as well as byproducts of naphtha, diesel and bunker fuel oil. The construction work at the 2.5 million mt\/year dewaxing hydrocracker started Nov. 8, 2023. A total of 32 units will be constructed, with the units expected to be ready in 2025 at the earliest. The greenfield HAPCO has been under construction since the second quarter of 2023. HAPCO is a joint venture between Saudi Aramco, Norinco Group and Panjin Xincheng Industrial Group, with stakes of 30%, 51% and 19%, respectively. The complex, which will receive 210,000 b\/d of crude from Saudi Aramco, is expected to be fully operational by 2026. ** Saudi Aramco and Sinopec have signed an agreement for a new greenfield project in Gulei, Fujian, which involves building a 320,000 b\/d refinery and a 1.5 million mt\/year petrochemical cracker. The new complex is expected to commence operations by the end of 2025. ** Saudi Aramco signed an agreement with Chinese company Shandong Energy Group to explore cooperation on integrated refining and petrochemicals opportunities in China. The Saudi company will explore a potential crude supply agreement and chemical products offtake agreement. The two sides have an \"expansive scope for cooperation, especially in oil and gas resources development and integrated refining and petrochemicals development along the whole industrial chain,\" Li Wei, chair of Shandong Energy Group, said. The agreement also extends to \"cooperation across technologies related to hydrogen, renewables and carbon capture and storage,\" Aramco said in a statement. ** China's coal chemical producer Xuyang Group has announced plans to build a greenfield 15 million mt\/year refining and petrochemical complex in Tangshang in central Hebei province. ","headline":" Higher runs expected in China in August","updatedDate":"2024-08-08T13:05:53.000"},{"Unnamed: 0":225,"body":" Freight environments for oil, dry bulk and container shipping remain strong due to high ship requirements, but future outlook is uncertain amid the coming change of the US presidency, diversified shipowner Euronav said Aug. 8. In its latest quarterly report, the Belgium-based, New York-listed company said healthy cargo volume growth combined with additional ton-mile demand amid Red Sea shipping disruptions had resulted in tighter balances across the main shipping sectors. Global seaborne volume is expected to grow by an \u201cabove-trend\u201d rate of 2.3% to 12.6 billion mt in 2024, while ton-mile will expand even more by 5.1%, Euronav said citing Clarksons figures. Yemen-based Houthi rebels have attacked more than 100 ships in the Red Sea and Gulf of Aden since the Israel-Hamas war broke out Oct. 7, forcing many ship operators to take longer routes and sail around Africa. However, the US is set to elect a new president in November\u2019s elections after President Joe Biden withdrew his candidacy, which Euronav said \u201ccould impact global geopolitics...with ocean shipping at the forefront of any shifts in the current status quo.\u201d While the shipping industry is expected to enjoy an up-cycle in the coming years, \u201ccaution prevails as any easing of sanctions that reinstates pre-war trading patterns...poses a downside risk to ton-mile demand,\u201d the company added. \u201cFurthermore, a more aggressive stance against China and the potential increase in trade tariffs would negatively affect global trade and, consequently, shipping. Tankers Having been supported by disruptions to Russian oil flows since the start of Ukraine war in February 2022, tanker rates have stayed at historically high levels also because of Red Sea rerouting despite seasonal demand softness, according to Euronav. Platts, part of S&P Global Commodity Insights, assessed the Arab Gulf-UK Continent Suezmax rate for transporting 140,000 mt of crude or dirty products at $20.81\/mt on Aug. 8, down from $23.27\/mt July 1. The Arab Gulf-China VLCC rate fell to $10.11\/mt from $10.95\/mt in the same period, despite a brief spike to $13.34\/mt on July 24. Aside from seasonality, Euronav said: \u201cChina's economic landscape presents a mixed outlook\u201d due to weak consumer spending and high unemployment rates in the world\u2019s largest oil importing nation. \u201cThese issues could further reduce China's overall energy consumption, a vital factor in global oil demand,\u201d the company added. Dry bulk, container shipping In the dry bulk sector, Euronav also holds a bullish market view as Capesize rates have been supported by strong iron ore exports and long-haul bauxite shipments from Guinea to China. The Platts Global Dry Bulk Index 0.5%S time charter equivalent from S&P Global Commodity Insights was assessed at $18,962\/d on Aug. 7, up from $11,189\/d when the assessment started in November 2023. \u201cJuly to September is typically a seasonally strong period for iron ore prices and Chinese steel production has recently ticked up,\u201d Euronav said. \u201cBauxite exports out of West Africa will soon decrease due to seasonal factors as the rainy season affects inland logistics, but longer-term trends are positive.\u201d Meanwhile, the company said container freight rates are surging due to ton-mile demand, a ramp-up of early peak season volumes, and increased port congestion. The Platts Container Index, a weighted average of spot rate assessments on key routes, hit a 21-month high of $4,159.27\/FEU in late June, up from $781.20\/FEU on Nov. 22, 2023. It was last assessed at $3,734.24\/FEU Aug. 7. But Euronav also warned large newbuild deliveries and the possible resolution of the Red Sea crisis could be \u201cclear negatives\u201d and \u201cpredicting the near-term future of the container markets is very difficult.\u201d Q2 results Following recent restructuring, Euronav -- ultimately controlled by the Saverys family\u2019s Compagnie Maritime Belge -- now owns more than 160 ocean-going vessels in dry bulk, container shipping, chemical tankers, offshore wind and oil tankers. The company has recently ordered three offshore wind vessels and four tugs capable of running on hydrogen, vowing to position itself for the shipping industry\u2019s energy transition. It will be renamed as CMB.TCH from October. Euronav posted a net profit of $680 million in January-June, up from $337 million in the same period of last year. Shipping revenue rose to $1.03 billion from $725 million. ","headline":"Shipping markets bullish, but US elections pose downside risks: Euronav","updatedDate":"2024-08-08T13:01:37.000"},{"Unnamed: 0":226,"body":" Spanish crude import volumes increased 11% year on year in the first half of 2024 to 1.4 million b\/d (33.5 million mt) as imports from the Americas and Africa ousted the Middle East and Eurasian volumes, data published Aug. 8 by reserve corporation CORES showed. The incoming volume for the first half was the highest since 2019, according to CORES data. Spain has a refining capacity of 1.6 million b\/d, making it Europe's third-largest market by refining capacity. The US, with 5.7 million mt, and Brazil, with 4.6 million mt, were the two largest suppliers to Spain in the period, followed by Nigeria, with 4.2 million mt and Mexico, with 4.0 million mt. US volume was at a record high, reflecting a pivot in upstream operations of Spain\u2019s principal integrated player Repsol towards the region. Brazilian volume in H1 was also at a record high, beating its previous record of 2.8 million mt from H1 2022, while South American volume overall was also boosted by increased flows from Venezuela after Repsol lifted an increasing number of cargoes as the result of a production agreement with PDVSA signed in Q2. African volume was boosted by steady output from Libya and Nigeria, but both Eurasian and Middle East volumes declined amid lower volumes from Kazakhstan and Iraq, among others. Middle East volume to Spain in H1 was at its lowest on records since 1996 and 62% down from its pre-pandemic 2019 level, the data showed. SPAIN CRUDE IMPORTS BY COUNTRY H1 2024 Volume Volume Y\/Y change source (000 mt) (b\/d) (%) Total 33,535 1,350,613 11 Africa 10,950 441,008 28 Angola 2,592 104,392 75 Algeria 1,550 62,426 20 Egypt 0 0 -100 Gabon 130 5,236 na Eq. Guinea 293 11,800 -43 Libya 2,156 86,832 6 Nigeria 4,230 170,362 34 North America 10,588 426,429 16 Canada 894 36,006 -40 US 5,656 227,794 54 Mexico 4,037 162,589 1 South America 6,705 270,042 47 Brazil 4,587 184,740 66 Colombia 0 0 -100 Ecuador 0 0 -100 Trinidad & Tob. 0 0 -100 Venezuela 1,363 54,894 229 Others Americas 756 30,448 85 Europe\/Eurasia 2,512 101,170 -45 Albania 119 4,793 -45 Azerbaijan 0 0 -100 Italy 269 10,834 58 Kazakhstan 1,332 53,646 -36 Norway 752 30,287 -4 UK 39 1,571 -86 Mid East 2,780 111,964 -18 S. Arabia 1,927 77,609 -3 Iraq 853 34,354 -40 Key NC: No change NA: no % change - previous year was zero source: CORES ","headline":" H1 crude imports rise 11% to 1.4 million b\/d","updatedDate":"2024-08-08T12:11:55.000"},{"Unnamed: 0":227,"body":" A number of refineries in China have resumed operations over the course of July after completing planned maintenance, refinery sources told S&P Global Commodity Insights. PetroChina\u2019s Dushanzi Petrochemical restarted July 6 following maintenance that started May 15. Sinopec Qilu Petrochemical in eastern Shandong province restarted July 11 following maintenance on a CDU that started May 19. Maoming Petrochemical had been carrying out works on a 100,000 b\/d CDU over May 25-July 19. Jinling Petrochemical will carry out works over Nov. 15-Dec. 31. ","headline":" Host of Chinese units back from works; Jinling maintenance in Nov-Dec","updatedDate":"2024-08-08T11:51:12.000"},{"Unnamed: 0":228,"body":" Some refineries in the Asia-Pacific region increased throughput in the second quarter of 2024, but runs at other refineries were affected by maintenance. Thai and South Korean refiners have been reluctant to purchase light sweet Mediterranean crude oil as attacks off the Red Sea coast of Yemen persist, leading to less-than-ideal delivery costs and cracking economics for the Kazakh, Libyan and Algerian grades. The ongoing Israel-Iran conflict and Red Sea maritime security risks have diminished East Asian refiners' appetite for Mediterranean crude over the past several trading cycles, as cargoes are now detouring the Suez Canal and Red Sea passage and opting for the longer Cape of Good Hope route, which make logistical costs more expensive. Thai refineries used to actively procure Libyan crude grades including El-Sharara, Mellitah and Amna as well as Algeria's Saharan Blend from the Mediterranean market, while Kazakhstan's CPC Blend crude also featured in their crude slate until 2023. However, Southeast Asia's second biggest economy took zero CPC Blend and Saharan Blend cargoes so far this year, while light sweet Libyan crude imports over January-May tumbled 62% year on year to 15,610 b\/d, Thai customs data showed. At least three major South Korean refiners regularly and actively purchased CPC Blend crude. One of the buyers has halted purchasing light sweet Kazakh crude since the third quarter 2023, while another importer stopped purchasing in April, according to refinery sources with direct knowledge of the matter and data from the Korea Petroleum Association. ** Throughput at Reliance Industries Ltd.'s Jamnagar refinery complex in India totaled 19.8 million mt from April through June of its fiscal 2025, up 0.5% from the corresponding FY 2024 quarter, the company said July 19. RIL-operated Jamnagar, located in Gujarat on the west coast of India, is the world's largest refinery complex. ** India's Mangalore Refinery and Petrochemicals Ltd. recorded 4.35 million mt of total throughputs in the April-June period compared with 4.36 million mt a year ago, company officials said July 23. The first quarter throughput, including crude and others, was 5.4% lower compared with the January-March quarter. MRPL recorded a 52% year-on-year decline in its gross refining margin to $4.70\/b for the April-June period or Q1, reflecting lower returns from cracks. In Q1, MRPL added three new crude grades for the first time -- Varandey (API 37.63) and Kaliningrad (API 39.43) from Russia and Eocene crude from the Saudi-Kuwait Neutral Zone (API 18.07). ** Gross refining margins at Hindustan Petroleum's Vizag refinery in Andhra Pradesh state is expected to improve by $3\/b after the completion of its residual upgrade by the end of the current 2024-25 fiscal year in March 2025, company officials said July 31. The refinery is expected to run at its full expanded capacity of 300,000 b\/d after the expansion project. In the October-December period, the Vizag refinery is expected to produce high-value refined products, the officials said. Separately, Hindustan Petroleum Corporation Ltd. posted a 32.8% year-on-year drop in gross refining margin to $5\/b in the April-June quarter on lower returns from cracks despite processing the highest-ever quarterly volume, company officials said July 30. HPCL recorded a $7.44\/b gross refining margin a year ago. In the first quarter, which runs from April to June, HPCL's two refineries at Mumbai and Vizag processed a record 5.76 million mt, up 6.7% on the year. Widening the company\u2019s crude basket, HPCL's two refineries processed imported crude Khafji and Varandey, and indigenous crude KGDWN for the first time during the quarter. ** Indian refineries processed 5.42 million b\/d of crude in June, up from 5.26 million b\/d in June 2023, the oil ministry said in its latest update, reflecting a 3% year-on-year increase in processing in Asia's third-largest economy. The combined runs of all types of refineries, state-run and private, were 4.2% above the 5.2 million b\/d target for the month. Analysts attributed the year-on-year increase to most of the refineries ramping up processing to meet higher demand for auto fuels. Indian refineries processed 5.24 million b\/d in 2023-24 (April-March), up 2.1% year on year, reflecting domestic demand for oil and oil products. ** Thailand\u2019s Bangchak reported July 19 that the utilization rate at its 120,000 b\/d Phra Khanong refinery dropped to 63% in the second quarter, from 101% in the first three months of the year, due to a planned turnaround at the plant. The average crude run at Phra Khanong fell to 76,200 b\/d in the quarter, from 121,400 b\/d in the first quarter, as the refinery was shut down for a planned turnaround between May 7 and June 2. Meanwhile, the utilization rate at Bangchak's other refinery, the 174,000 b\/d Sriracha facility, increased to 89% in the second quarter, from 86% in the first quarter. Over April-June, the Sriracha refinery processed 154,200 b\/d of crude oil, up from 150,300 b\/d in Q1 2024. Bangchak\u2019s combined utilization rate in the second quarter was 78%, with average crude runs of 230,400 b\/d. ** Thailand\u2019s IRPC reported a 94% utilization rate in the second quarter of 2024, up from 90% in the same period of 2023 and 85% in the first quarter, the company said in its latest results report Aug. 6. Its utilization in the first half was 89%, down from 91% in H1 2023. The IRPC Rayong refinery processed 201,000 b\/d of crude oil in the second quarter, up 3.6% year on year and surging 10.4% from Q1 2024. It processed 192,000 b\/d of crude oil between January and June, down from 195,000 b\/d in the same period of last year. Its gross refining margin in Q2 was $2.45\/b, down from $4.12\/b in Q2 of last year and dropping from $6.56\/b in Q1, mainly due to lower spreads of diesel and gasoline products compared with the Dubai crude oil price. The company's GRM in the first half was $4.38\/b, down from $5.86\/b a year earlier. ** Thai Oil reported a slight decrease in the utilization rate at its Sriracha refinery in the second quarter of this year compared with last year due to a planned shutdown at a crude distillation unit (CDU) in May, the company said in its Q2 results report on Aug. 8. The utilization between April and June was 111%, which was lower than 113% in Q2 last year as its CDU-1 and related units had a planned shutdown in 11 days in May this year. However, the Q2 utilization was higher than the 105% in Q1 as its CDU-3 had experienced an unplanned shutdown in 13 days in January due to technical issues. In Q2, the Sriracha refinery processed 306,000 b\/d of crude oil, lower than 311,000 b\/d in the same period in 2023 but higher than 288,000 b\/d in the Q1 of 2024. Thai Oil\u2019s gross refining margin (GRM) in Q2 was at $3.8\/b, falling from $4.5\/b in Q2 2023 thanks to lower spreads of gasoline and jet fuel\/kerosene over Dubai crude oil prices because of oversupply. Thai Oil\u2019s utilization in the first half was 108%, lower than 113% in the first six months of 2023. Its Sriracha refinery processed 297,000 b\/d of crude oil in the period, lower than 309,000 b\/d in H1 last year. The company's GRM in H1 was $6.3\/b, lower than $7.2\/b in H1 2023. ** Australia's Ampol said July 25 that production at its Lytton refinery in the first half of 2024 was at 2.802 billion liters (around 95,000 b\/d) -- 5.8% lower compared with the year-ago period. Refining margin in H1 was at $10.27\/b, largely unchanged from $10.29\/b in the year-ago period. However, in Q2 it rose to $8.81\/b from $5.66\/b in the year-ago quarter when margins were impacted by an unplanned FCC outage. ** South Korea's S-Oil Corp. raised its crude run rate to average 94.6% in the second quarter, from 80.3% a year earlier and 91.9% in the previous Q1, despite weak refining margin. The refinery ran RFCC\/hydrocracker at average of 96.1% in Q2, up from 80.9% a year earlier, but down from 97.6% in Q1. The refiner would keep its crude throughput high in the third quarter. ** SK Innovation's crude run rate at Ulsan and Incheon averaged 81% in the second quarter, up from 80% a year earlier but down from 85% in the first quarter. Its crude run rate was still well below the prepandemic level of around 90%, though it has bounced back from 77% in 2022, 66% in 2021 and 75% in 2020. The refiner could slightly raise crude throughput later this year, but would remain cautious due to lingering market uncertainties. SK Innovation operates the Ulsan complex on the southeast coast that runs five CDUs with combined capacity of 840,000 b\/d. Its another complex in Incheon on the west coast runs two CDUs with 275,000 b\/d, which makes its total refining capacity of 1.115 million b\/d in addition to a 100,000 b\/d condensate splitter. Meanwhile there have been reports of new products, as well as change of ownership and mergers. ** India's oil refinery at Paradip has developed a high-octane gasoline variant, STORM- X, for racing cars, company officials said July 23. The new fuel variant is developed by the Indian Oil Research and Development Centre in Faridabad and produced at the state-of-the-art Paradip Refinery. The variant blends high-octane gasoline streams with advanced sustainable components, including 2G Ethanol from the Panipat Refinery. ** South Korea's top oil refiner SK Innovation and SK E&S, a major LNG importer and utility, agreed to merge to become \u201cAsia\u2019s biggest private energy entity,\u201d the companies said July 17. SK Innovation and SK E&S held separate board meetings that approved the merger plan as part of their parent SK Group\u2019s restructuring efforts aimed at strengthening its energy business and providing financial support to the struggling electric vehicle battery segment. The merger will be finalized following approval at the companies\u2019 emergency shareholders' meeting slated for Aug. 27, followed by the official launch of a new entity Nov. 1. The merger ratio between SK Innovation and SK E&S was set at 1:1.2. ** Independent commodity trader Gunvor has agreed to purchase TotalEnergies' 50% stake in Total PARCO Pakistan, a fuel marketing company, the companies said Aug. 6. Total PARCO Pakistan is a 50\/50 joint venture between TotalEnergies Marketing and Services and Pak-Arab Refinery Limited (PARCO) in Pakistan with a retail network of more than 800 service stations, fuel logistics and lubricants activities. Following the transaction, the new entity will continue its retail business under the existing \u201cTotal Parco\u201d brand and its lubricants business under the \u201cTotal\u201d brand for five years in Pakistan. In other news, Pakistan\u2019s government has allowed several refineries recently, including Pak Arab Refinery, PARCO, National Refinery and Attock Refinery to export fuel oil to help reduce stockpiles and optimize refinery operations. In May, Pakistani refineries had exported around 150,411 mt of fuel oil, up 59.5% on the year, according to data from the Oil Companies Advisory Council, which compiles data for petroleum products consumption, imports, and exports. New and ongoing maintenance Refinery Capacity b\/d Country Owner Unit Duration Balikpapan 260,000 Indonesia Pertamina Part Back Taoyuan 200,000 Taiwan CPC Part June Dalin 400,000 Taiwan CPC Part Aug SRC 290,000 Singapore Joint Part May Onsan 669,000 South Korea S-Oil Part H2 Lytton 109,000 Australia Ampol Full H2 Kochi 310,000 India BPCL Part Sept Port Dickson 88,000 Malaysia Petron Full Back Manali 210,000 India Chennai Full July Bina 156,000 India BPCL Full Aug Upgrades Vizag 166,000 India HPCL Expansion 2023 Mathura 160,000 India IOC Upgrade N\/A Paradip 300,000 India IOC Upgrade N\/A Panipat 500,000 India IOC Expansion 2024 Gujarat 275,000 India IOC Expansion NA Vadinar 400,000 India Nayara Expansion NA Jamnagar 1,360,000 India Reliance Expansion NA Numaligarh 60,000 India BPCL Expansion 2025 Kochi 310,000 India BPCL Expansion 2025 Haldia 150,000 India IOC Upgrade 2023 Port Dickson 88,000 Malaysia Petron Expansion NA Bataan 180,000 Malaysia Petron Expansion NA Sriracha 275,000 Thailand Thai Oil Expansion 2023 Barauni 120,000 India IOC Expansion NA Balikpapan 260,000 Indonesia Pertamina Expansion 2024 Balongan 125,000 Indonesia Pertamina Upgrade 2026 Tuban 100,000 Indonesia TPPI Upgrade 2024 Byco 155,000 Pakistan Byco Group Upgrade NA Cilacap 348,000 Indonesia Pertamina Upgrade 2023 Plaju 133,700 Indonesia Pertamina Upgrade Pakistan Ref 50,000 Pakistan Pakistan Ref Upgrade NA Hengyi 160,000 Brunei Hengyi Ind Expansion 2024 Dung Quat 130,000 Vietnam Binh Son Expansion 2026 Attock 53,400 Pakistan Attock Upgrade NA National Refinery 70,000 Pakistan National Ref Ltd Part Dec Dumai 170,000 Indonesia Pertamina Expansion NA Bongaigaon 54,000 India IOC Expansion NA Pulau Muara Besar 160,000 Brunei Hengyi Upgrade NA Nagapattinam 180,000 India Chennai Launch NA Ulsan 840,000 South Korea SK Energy Upgrade NA Geelong 120,000 Australia Viva Energy Upgrade 2025 Digboi 13,000 India IOC Expansion 2025 Rayong 215,000 Thailand IRPC Upgrade Completed Launches Barmer 180,000 India HPCL Launch 2024 Maharashtra 1,200,000 India Joint Launch NA Tuban 300,000 Indonesia Joint Launch 2024 Dornogovi 30,000 Mongolia Government Launch 2026 Mumbai 1,200,000 India Ratnagiri Launch 2025 Gwadar 300,000 Pakistan Joint Launch NA Balasore NA India Haldia Launch NA Hambantota NA Sri Lanka Joint Launch NA Bontang 300,000 Indonesia Pertamina Launch NA PARCO 250,000 Pakistan PARCO Launch 2025 Nagapattinam 180,000 India Chennai Launch 2025 Ratnagiri 1,200,000 India Joint Launch 2025 Trans Asia Refinery 120,000 Pakistan Joint Launch NA Long Son 300,000 Vietnam PetroVietnam Launch 2027 New and ongoing maintenance New and revised entries ** There has been no impact on the refinery units at South Korea's S-Oil's Onsan facility following a fire at an aromatics unit. \u201cNo other facilities at the complex -- such as crude distillation units and heavy oil upgraders -- were affected,\u201d a company official said July 29. S-Oil shut its No. 2 aromatics unit in Onsan after a fire on July 28 morning. The fire erupted at 4:47 am local time (0747 GMT) July 28 and was completely extinguished about five hours after it started, according to the official. No casualties were reported. The unit can produce 1.05 million mt\/year of paraxylene and 300,000 mt\/year of benzene. Separately, S-Oil Corp. plans to shut its smallest No. 1 crude distillation unit at Onsan with a capacity of 90,000 b\/d for maintenance for several weeks later this year, with cracking margins forecast to rebound in the third quarter, a company official said July 26. However, the official refused to provide details such as exact dates for the maintenance in the second half of 2024. Earlier, the official said shutdown of No. 1 CDU might come in the second quarter, indicating the maintenance seems to have been delayed. The company conducted massive turnaround for the past two years, there would be no maintenance plans for this year, except the No. 1 CDU, according to the official. ** South Korea's SK Innovation has no plans to shut its crude distillation units at Ulsan and Incheon for maintenance in the third quarter as it forecasts solid products crack margins, but has remained cautious in raising crude throughput, a company official said Aug. 1. \u201cThe company will not shut down other facilities such as heavy oil upgraders in the third quarter as we conducted massive maintenances so far this year,\u201d the official said. The refiner has restarted its 240,000 b\/d No. 4 CDU in the Ulsan complex since June 20 after a month-long maintenance. SK Innovation has also restarted the 260,000 b\/d No. 5 CDU since April 15 after a month-long maintenance focused on replacing the preheater for boosting efficiency. The refiner\u2019s No. 1 residue hydrodesulfurization unit with a capacity of 72,000 b\/d in the Ulsan complex has restarted since June 20 after a month-long maintenance. The company also restarted two vacuum residue desulfurization units, both in the Ulsan complex and each with a 40,000 b\/d capacity, in early April after weeks-long maintenance. On April 15, SK Innovation restarted the 260,000 b\/d No. 5 CDU after a month-long maintenance period focused on replacing the pre-heater for boosting efficiency. ** Hindustan Petroleum's officials ruled out any planned turnaround at the Vizag refinery during the remaining period of the current fiscal year. Vizag ran at 114% of capacity in 2023-24 (April-March) against 112% in 2022-23. In June, Vizag ran at 114% while it ran at 102% during the April-March period. ** India's Bharat Petroleum Corporation's refinery at Bina, Madhya Pradesh, is set for a 15-day turnaround over August-September, company officials said July 30. All the four major units at the refinery -- hydrocracking unit, diesel hydro desulphurization unit, diesel hydrotreater unit and sulfur recovery unit -- are expected to undergo maintenance during the turnaround. ** Indian state-owned Bharat Petroleum Corp Ltd plans a 30-day turnaround at its Kochi refinery for primary and secondary units, company officials said. During the turnaround period, most units will be shut for maintenance. The units to be shut down are expected to be CDU-2, the fluid catalytic cracking block, the vacuum distillation unit, the sulfur recovery unit, and the hydrogen sulfide removal unit. The CDU has a 4.5 million mt\/year (90,000 b\/d) capacity. Officials have previously said the maintenance was planned for September-October when the refinery's usual capacity would be reduced by 29%. During the planned shutdown period, the second CDU with 10.5 million mt\/year capacity would function normally. ** Taiwan's CPC has further delayed the restart of its residue fluid catalytic cracking unit in Dalin to Aug. 23, according to company notice seen by S&P Global Commodity Insights. The delay was attributed to further technical issues, with the RFCC unit's catalytic equipment suffering damage following a restart attempt Aug. 2, the notice said. The unit, which can produce 280,000 mt\/year of propylene, was initially slated to resume operation July 28 but was postponed to Aug. 1. It was shut July 21 due to technical issues. ** India\u2019s Nayara Energy may undertake maintenance at the Vadinar refinery in the near term as evident from a tender where the refiner offered vacuum gasoil for loading in September, market sources said July 24. The maintenance is expected to take place in September. According to market sources one of the units expected to undergo works is a hydrocracker which processes VGO into diesel. Company officials did not comment on the possible maintenance citing company policy. ** The 360,000 b\/d CDU No. 4 at Pertamina's Balikpapan refinery in East Kalimantan, Indonesia, has resumed normal operations as of July 26, sources said July 29. The unit underwent maintenance following a fire incident May 25. The whole refinery is fully back online after completing its maintenance, sources said. Balikpapan has been under maintenance and expansion since the start of the year. This is a key step in integrating existing refinery units with newly-built ones and has resulted in raising capacity by 100,000 b\/d to 360,000 b\/d and increasing the quality of products to Euro 5 standards from Euro 2. The new capacity includes the revamped 300,000 b\/d CDU No. 4 and the 60,000 b\/d CDU No. 5, according to the company. ** India\u2019s Bharat Petroleum Corp. Ltd. has no maintenance plans for its Mumbai refinery for 2024 and has not carried out any work in July, company officials said July 31. Earlier, the refiner had planned to shut down one of the crude distillation units for 30 days to coincide with the second quarter, which runs from July to September. The CDU that had been planned to undergo maintenance was of smaller capacity. ** Australia's Ampol in a brief statement to Commodity Insights July 10 said the refinery will be undergoing planned turnaround commencing mid-July to end-August. \"[The turnaround] is for the reformer primarily, although we will take the opportunity to do some other minor maintenance and cleaning,\" the company said in the statement. Ampol said Feb. 19 its Lytton refinery will have a \"scheduled turnaround and inspection\" in H2 2024 and expected to last about seven weeks. Existing entries ** Taiwan's Formosa Petrochemical will enter planned turnaround at Mailiao in mid-September 2024, with both the 180,000 b\/d No. 1 CDU unit and the 80,500 b\/d No. 1 RDS unit expected to be offline for 40 days, while the 76,000 b\/d No. 1 RFCC unit will likely be taken offline for nearly 70 days. ** SRC will carry out planned maintenance at its plant on Jurong Island between mid-August and mid-September, according to market sources. Two of the CDUs were expected to be offline. The refinery has three CDUs. One CDU was due to have maintenance in May, although it has been deferred, according to market sources. An SRC spokesperson said the company does not comment on its facility operations. ** India's Chennai Petroleum Corporation Ltd. plans a month-long maintenance shutdown mid-year, company officials said. The maintenance at Manali refinery was expected to take place over July-August. ** Malaysia's Melaka bigger 200,000 b\/d CDU is expected to undergo maintenance in 2026. ** Taiwan's state-run CPC plans to shut the 50,000 b\/d residue catalytic cracker at the Taoyuan refinery for scheduled maintenance over June 25 to Sept. 2, a source close to the company said. ** CPC has scheduled to shut the 40,000 b\/d catalytic reformer at the Dalin refinery for turnaround over Aug. 30 to Oct. 18. The unit produces the reformate feedstock for the company's No. 3 and No. 6 BTX plants. CPC's No. 6 BTX unit is also scheduled for maintenance from Aug. 30 to Oct. 1. The refiner also plans to shut its residual oil cracking unit at Dalin refinery from Oct. 30 to Dec. 23 for maintenance. The unit can produce 53,000 mt\/year of propylene. ** Repair works on the RDS No. 3 unit of Taiwan's state-owned CPC Corp's Dalin refinery -- also known as Talin -- were ongoing, a company spokesperson said in November 2023. The company expected the works to be completed by early 2025, though the timeline will be reviewed on a \u201crolling basis\u201d as the project progresses, he said. The RDS unit was shut following a fire at the refinery's 40,000 b\/d residue hydrotreater No. 3 unit in late October 2022. ** New Zealand's sole refinery Marsden Point converted operations to an import-only fuel terminal in April 2022. ** ExxonMobil Australia integrated the common infrastructure between the Altona refinery in Melbourne and the new fuel import and storage terminal over the course of 2022. The process of shutting down the refinery started at the end of August 2021 and was completed in May 2022. Upgrades New and revised entries ** Hindustan Petroleum's Vizag refinery in Andhra Pradesh state is expected to run at its full expanded capacity of 300,000 b\/d after the expansion project, which includes a 3 million mt\/year hydrocracker, a sulfur recovery unit and hydrogen unit. Its bottom-of-the-barrel upgrade will be over by the January-March quarter of the current 2024-25 fiscal year. After the fully expanded capacity comes into force, the refinery's overall distillate yields will increase by at least 10% from the current level of 75%. After expansion, Vizag's distillates would reach 60% from 48%-50%, gasoline at 18%, and LPG at 5%. From the next fiscal year (2025-26), there will be no fuel oil production at the Vizag refinery. ** Thailand's IRPC said it put its ultra clean fuel project into commercial operation in April. The UCF project, which includes a new 75,000 b\/d diesel hydrotreater, will enhance the efficiency of the refinery plant and improve the quality of its diesel to meet the Euro-5 standard, in alignment with Thai Ministry of Energy's policy that requires diesel distribution to comply with the Euro-5 standard beginning Jan. 1, 2024. This standard reduces the permissible sulfur level to 10 ppm from 50 ppm under Euro 4, IRPC said. ** Thai Oil reported little progress on its delayed clean fuel project (CFP). The company completed 96.8% of work at the project as of Jun. 30, slightly higher than the 96% as of March 31. The CFP will help Thai Oil move from producing low-value products to producing higher value and more environmentally-friendly products. It will also enable the company to process more types of crude oil with higher quantities. Thai Oil initiated the commissioning of the Hydrodesulfurization unit (HDS-4) in February, ahead of schedule. This unit played a vital role in enabling the company to comply with the Euro-5 standard, which was enforced in Thailand this year. Additionally, Thai Oil is working to accelerate the commissioning of the remaining units, it said. Existing entries ** PetroVietnam's Binh Son Refining and Petrochemical was targeting completion of the expansion project at its Dung Quat refinery in the third quarter of 2028, PetroVietnam said in May. The target was announced during the 2024 annual stakeholders meeting that BSR held on May 23. The board of managers of BSR announced in March that it has approved the expansion project, which will raise Dung Quat's capacity to 171,000 b\/d from 148,000 b\/d. The company hopes it can award the engineering, procurement and construction contract so work to build the expansion project can begin from 2025. The expansion project will add seven new units, including gasoline hydrotreating technology, diesel hydrotreating technology and sulfur recovery unit; and revamp nine existing units. Currently Dung Quat refinery has 15 units. ** Pakistan Refinery Ltd. is aiming to award the EPC contract for the upgrade and expansion of the refinery by the end of 2024 and \"work towards achieving financial close of the project\" by the middle of 2025, it said in a filing to the Pakistan Stock Exchange in May. The announcement was made after senior management visited China and engaged with EPC contractors and financial institutions. Pakistan Refinery Ltd. plans to double its capacity to 100,000 b\/d in five years at a total project cost of around $1.7 billion, CEO Zahid Mir said in January. It also reiterated that its refinery expansion and upgrade project involve doubling of the capacity and adopting a deep conversion configuration. The upgraded refinery will produce Euro V products, enhancing the refinery's \"operational efficiency and environmental footprint,\" it also said. Pakistan Refinery has previously said it aims to install bottom-of-the-barrel conversion technology and naphtha processing. That includes a residue fluidized catalytic cracking process, LPG Merox process and a naphtha complex, featuring a naphtha hydrotreater and a CCR platforming unit. ** Indonesia's Pertamina said that its Balikpapan refinery will also produce propylene upon completing its upgrade and expansion which started in February and has largely been completed. The refinery's production capacity will raise to 360,000 b\/d from 260,000 b\/d and the quality of products will improve from Euro II to Euro V. Upon the completion of the upgrade, the refinery will produce 225,000 mt\/year of propylene, which will be used as a feedstock for the polypropylene unit at Balongan. That unit subsequently will be able to substitute imported products. KPI, which runs six refineries, has petrochemical units currently at Balongan, as well as a paraxylene unit at Cilacap and a polypropylene unit at Plaju. ** Indian Oil Corp has selected global technology processing company Lummus' Cumene Technology solution for the 440,000 mt\/year cumene unit at its Paradip refinery on India's east coast. The new cumene unit is part of a grassroots petrochemical and polymers expansion at the refinery. ** India's Nayara Energy plans to set up two ethanol plants of 200,000 liters\/day capacity each by 2025-26 (April-March), company officials said. One plant will be in Andhra Pradesh while the other unit will be in Madhya Pradesh. Nayara's two plants will help meet the government's 20% ethanol blending target for 2025, the company said. Nayara aims to gradually increase the number of ethanol plants to five with production capacity 1 million l\/d in the near future, to ensure the reliability of the blending program. Nayara Energy also plans to expand and modernize existing refining capacity, a company official said Feb. 15, without providing further details. According to Russian media reports, citing an energy ministry source, the refinery looks at more than doubling its capacity. A Rosneft-led consortium owns Nayara in which trading company Trafigura and UCP Investment Group are partners. Nayara is looking to set up a 450,000 mt\/year polypropylene plant at the Vadinar refinery as part of the upgrade. The plant is expected to be commissioned in 2024. ** Thai Oil had completed 96.8% of work at the project as of June 30, slightly higher than the 96% as of March 31. The CFP will help Thai Oil move from producing low-value products to producing higher value and more environmentally-friendly products. It will also enable the company to process more types of crude oil with higher quantities. Thai Oil initiated the commissioning of the Hydrodesulfurization unit (HDS-4) in February, ahead of schedule. This unit played a vital role in enabling the company to comply with the Euro-5 standard, which was enforced in Thailand this year. Additionally, Thai Oil is working to accelerate the commissioning of the remaining units, it said. The $4-billion project is expected to increase the refinery's capacity to 400,000 b\/d and help Thai Oil move from producing low-value products to producing higher value and more environmentally friendly products. It will also enable the company to process more types of crude oil with higher quantities. Thai Oil initiated the commissioning of the Hydrodesulfurization unit (HDS-4) in February, ahead of schedule. This unit played a vital role in enabling the company to comply with the Euro-5 standard, which was enforced in Thailand this year. Additionally, Thai Oil is working to accelerate the commissioning of the remaining units, it said. ** India's Numaligarh Refinery plans to run at an expanded capacity of 9 million mt\/year (180,000 b\/d) in December 2025, company officials said. The latest timeline to start the expansion is three months behind an earlier deadline. The refiner is expected to complete installation works related to a new CDU and associated secondary units by September at the latest. Currently, the refinery has a 3 million mt\/year (60,000 b\/d) capacity. The proposal related to NRL's capacity expansion was approved by the federal government in 2019. The expanded full runs would be sourced 61% through imported crude and the rest via local production, said Ranjit Rath, OIL's chair. The expansion plan will add a second CDU of 6 million mt\/year. Details of a new diesel hydrotreating unit to be installed as part of its multiyear expansion have also been finalized. Toyo Engineering Corp. said that its India subsidiary was awarded a contract for the engineering, procurement, construction and commissioning of a 3.55 million mt\/year diesel hydrotreating unit. Separately, Axens will provide technical support and license a naphtha hydrotreating unit, continuous catalytic reforming unit, isomerization and fluid catalytic cracker. ** Indian Oil Corp.'s Panipat refinery is set to run its expanded capacity of 500,000 b\/d (25 million mt\/year) in December 2025 form the current 15 million mt\/year, company officials said in February 2024. The setting up of new petrochemical units as part of the expansion project would help the refinery in North India diversify its product portfolio. The project will produce gasoline, diesel, jet fuel and LPG by utilizing indigenous INDMAX technology. The installation of polypropylene and catalytic dewaxing units will help diversify product offerings, strengthening market competitiveness. McDermott has been awarded a project management consultancy (PMC) contract by IOC for the Maleic Anhydride (MAH) unit at the Panipat Refinery and Petrochemical Complex. The contract includes FE","headline":" Mixed runs in Asia-Pacific","updatedDate":"2024-08-08T11:50:48.000"},{"Unnamed: 0":229,"body":" The physical low sulfur (1%S) fuel oil Med-North spread widened to a record high Aug. 7, amid a strong pull of demand from within the Mediterranean markets. Platts last assessed the LSFO Med-North spread -- the spread between 1%S FOB Med cargoes and 1%S FOB NWE cargoes -- at $41\/mt Aug. 7, marking a record high since the assessment began, S&P Global Commodity Insights data showed. Within the Platts Market on Close assessment process, Alkagesta has consistently been bidding since early August for a 25,000-mt LSFO cargo on a CIF Malta basis, pushing up the Med-North spread in recent days. With the majority of LSFO production occurring within the Northwestern European markets, the 1%S Med-North predominately sees a premium within the Mediterranean markets to incentivize flows to move from the North into the Mediterranean. One trader said the Mediterranean LSFO market has become stronger over the past two weeks \u201cas it needs the arb\u201d from Northwest Europe, adding that they have seen lots of prompt demand for LSFO within the Mediterranean from utility shorts to meet their power generation needs. A second trader said the lack of 1%S production within the European refinery complex means that there is a more limited pool of supply entering the markets. The LSFO market remains thinly traded and therefore more susceptible to larger fluctuations in prices, traders continued to note. ","headline":"Physical 1%S fuel oil Med-North spread hits record high on competitive bidding in Platts MOC","updatedDate":"2024-08-08T11:28:20.000"},{"Unnamed: 0":230,"body":" Bunkering activity in India has experienced significant growth during the first seven months of 2024, with the total number of bunkering and ship-to-ship (STS) calls to Indian ports increasing by 64% year on year. According to S&P Global Commodities at Sea data, the total number of bunkering and STS calls to Indian ports surpassed 6,765 compared with just 4,113 during the same period in 2023. \u201cThis year the performance of all ports is better because mostly the demand has increased,\u201d a Gujrat-based trader told Commodity Insights. \u201cWe anticipate that volumes could increase significantly, reaching up to 3,000-4,000 mt in the coming months for Hazira and Dahej,\u201d said a Hazira-based trader. This time, the monsoon has had little effect in Mumbai, said market participants. Mumbai, which is one of the major bunkering hubs in the country, saw a 53% rise in total bunkering and STS calls, CAS data showed. \u201cOne barge is operating at Mumbai OPL, specifically handling monsoon deliveries,\u201d a Mumbai-based trader said Aug. 8. \"For July, Mumbai's total volume is expected to exceed 60,000 mt. Product availability is strong, with significant HSFO and VLSFO orders at OPL deliveries,\" the trader added. Attacks on shipping in the Red Sea have prompted shipowners to take longer voyages around Africa. This disruption caused a substantial increase in monsoon bunker demand at Indian ports, which is typically lower due to weather disruptions. The growth was further fueled by favorable pricing and consistent supply from domestic refineries since the second quarter of 2024. Platts, part of Commodity Insights, assessed 0.5% marine fuel oil delivered to Mumbai at $641\/mt CFR on Aug. 8, down $4\/mt week on week, while in Kochi prices were at $647\/mt, up $4\/mt. Weather disruptions hit bunker volumes at Gujarat-based ports Demand for bunker fuels at West coast India ports took a hit in July as supplies have been impacted by the ongoing monsoon season, traders said. During the Southwest monsoon period from June to September, certain port authorities impose restrictions on barge movement due to unfavorable weather conditions impacting anchorage supplies. \u201cDespite a steady flow of inquiries in July, weather conditions prevented us from fulfilling orders at locations like Vadinar and Sikka,\u201d said a Kandla-based supplier. In June, the total volume of supplies was around 52,000 mt while in July it decreased to 35,000 mt, the supplier added. \u201cOur limitation lies in the lack of barge supply at anchorage, restricting us to tank truck deliveries at berth, which impacts our ability to handle larger volumes,\u201d said a Dahej-based supplier Total Bunkering and STS calls fell to 26% month-over-month to 357 in July 2024 for Gujrat-based ports, CAS data showed. Gujarat ports include Kandla, Sikka, Vadinar Terminal, Port Okha, Bedi Bunder, Navlakhi, and Mundra in the Gulf of Kutch, along with Dahej, Hazira, Jafrabad, Magdalla, and Pipavav in the Gulf of Khambhat. East Coast ports see some product unavailability Haldia market demand remained stable, with consistent supply maintaining market stability. Uncertainty about refinery maintenance has left market participants unsure about its impact on August demand, with some predicting a product shortage and others expecting market stability \u201cIn July Haldia's bunker volumes ranged between 15,000 mt-17,000 mt,\u201d said a Visakhapatnam-based trader adding \"Annually, we\u2019re seeing a 16% rise.\" \u201cWe had a surplus of product in July and we attained volumes of around 16,000 mt. There is no firm date yet for the refinery shutdown, it was planned to take place in July but things got delayed. We\u2019re hearing it might start around mid-August\u201d, a Haldia-based IOCL official told Commodity Insights. Market sources reported increased demand at Visakhapatnam and Kakinada from late Q2 due to Red Sea diversions, while other ports showed no significant change. Pipeline issues at Paradip disrupted VLSFO supplies and reduced inquiries. \u201cIn July, we recorded volumes of 36,000 mt at Visakhapatnam, while Kakinada saw volumes of around 32,000 mt,\u201d said another trader. Since January, Paradip has been facing issues with the refinery pipeline, leading to a shortage of VLSFO supply there, the trader added. \u201cNew Mangalore and Tuticorin have experienced stable volumes, with no significant increase compared to last year.\u201d Kochi demand stable, volumes shift Market sentiment in Kochi has remained stable, but some suppliers experienced product shortages in July, leading to a decrease in their monthly volumes. However, suppliers who had the product saw increased volumes as customers shifted to them. According to a Kochi-based supplier, the monsoon season has not been favorable, resulting in a decrease in monthly volumes. It could be due to limited options or a diversion of demand to Sri Lanka. An IOCL official in Kochi mentioned a slight dip in VLSFO inquiries but highlighted better performance due to less competition last month. \u201cWe have done more than 20,000 mt in July. There hasn\u2019t been much change in the industry volumes, it's basically a shift of volumes from one participant to another,\u201d the official added. An increase in bunker demand at Colombo led to a decline in Kochi. Increased demand led to supply tightness in Sri Lanka, mainly impacting Colombo and Hambantota, while Trincomalee remained unaffected. \u201cBut the situation is now easing,\u201d a Sri Lanka-based supplier said. Platts assessed 0.5% marine fuel oil delivered to Kochi at $647\/mt CFR on Aug. 7, a $23\/mt discount to Marine Fuel 0.5% Bunker Delivered Colombo. ","headline":"Indian ports see Jan-July bunker, STS calls up 64% on year, monsoon hits July demand","updatedDate":"2024-08-08T11:27:15.000"},{"Unnamed: 0":231,"body":" LNG bunker prices in Rotterdam and Barcelona reached their highest level of 2024 amid rising demand and bullishness in the wider LNG market. Platts, part of S&P Global Commodity Insights, assessed LNG bunker Rotterdam and Barcelona at $13.83\/MMBtu and $13.93\/MMBtu respectively Aug. 7. This is a rise of 0.82 cent\/MMBtu and 0.81 cent\/MMBtu respectively on the week, placing both assessments at the highest levels since Dec. 7, 2023. Market sources attributed factors such as higher demand, arbitrage economics, and bullish price movements in the physical LNG and gas arenas for the price increase. \u201cWe see a healthy port calling with a mixed bag of product tankers, pure car carriers, cruise ships, it' getting better\u2026 and it's only going to go up,\u201d said one Atlantic LNG bunker trader. Rising geopolitical tensions in Russia and the Middle East have added to market jitters with increasing uncertainty leading to an uptick in prices, market sources said. Meanwhile, market sources noted that ships are increasingly turning to Europe due to high prices and infrastructure limitations in Asia as ships face long waitlists for bunker slots in Singapore and Malaysia. The spread between LNG bunker Rotterdam and Singapore also narrowed as the latter was assessed Aug. 7 at $14.792\/MMBtu, placing the spread between Bunkers Singapore and Rotterdam at 0.959 cent\/MMBtu- the lowest since Feb. 29. ","headline":"LNG bunker prices in Europe hit 8-month high amid rising demand","updatedDate":"2024-08-08T10:51:11.000"},{"Unnamed: 0":232,"body":" Singapore-based commodities trader Wellbred Trading acquired French refinery La Nivernaise de Raffinage SAS that processes used cooking oil as feedstock, with plans to expand capacity next year by taking advantage of increased demand for renewables-based refined products. The 60,000 mt\/year refinery in Premery produces biodiesel and is Wellbred's first refinery, the company said Aug. 8. Wellbred, which has offices in Geneva, Dubai and Lagos, was approved July 20 to buy the plant in an auction held by the commercial court of Nevers, France. The refinery will operate under Wellbred's renewables desk based in Geneva, it said. Wellbred Trading started its renewables desk in 2022 supplying biofuels to Norway and Sweden. Since then, it has added biofuels for the shipping industry. The French refinery allows Wellbred Trading to start trading feedstocks and distributing biodiesel in France, Germany and Spain, the company added. ","headline":" Wellbred Trading acquires La Nivernaise de Raffinage in France","updatedDate":"2024-08-08T10:50:54.000"},{"Unnamed: 0":233,"body":" Singapore-based commodities trader Wellbred Trading acquired French refinery La Nivernaise de Raffinage SAS that processes used cooking oil as feedstock, with plans to expand capacity next year by taking advantage of increased demand for renewables-based refined products. \"This acquisition gives us the opportunity to engage further with the renewable energy space and reinforces our commitment to growth in this important aspect of Wellbred\u2019s value chain,\u201d CEO Ghazi Abu al-Saud said Aug. 8 in a statement provided first to S&P Global Commodity Insights. The 60,000 mt\/year refinery in Premery produces biodiesel and is Wellbred's first refinery, it said. \"The biodiesel produced at our refinery will be suitable for both road and marine applications,\" Simon Lausch, managing director of Wellbred Trading and president of the refinery, told Commodity Insights. \"The marine sector, in particular, is experiencing rapid growth in France with the implementation of B30 fuel standards.\" Platts, part of Commodity Insights, assessed the bunker fuel price for B30 -- a blend of 70% 0.5% sulfur fuel oil and 30% used cooking oil methyl ester -- at $774.25\/mt in Rotterdam Aug. 7, up from $754.75\/mt at the end of last year. Wellbred, which has offices in Geneva, Dubai and Lagos, was approved July 20 to buy the plant in an auction held by the commercial court of Nevers, France. The refinery will operate under Wellbred's renewables desk based in Geneva, it said. Wellbred Trading started its renewables desk in 2022 supplying biofuels to Norway and Sweden. Since then, it has added biofuels for the shipping industry. The French refinery allows Wellbred Trading to start trading feedstocks and distributing biodiesel in France, Germany and Spain, the company added. ","headline":"Wellbred Trading buys French diesel refinery that runs on used cooking oil","updatedDate":"2024-08-08T10:40:34.000"},{"Unnamed: 0":234,"body":" There is a high probability that 2024 will be the hottest year ever as extreme weather events such as wildfires and heat waves become increasingly commonplace, the EU\u2019s Copernicus Climate Change Service said Aug. 8. This comes as July 2024 was the second-warmest month on record, with the two hottest days ever recorded last month, according to data from EU'c climate monitor. Surface air temperatures averaged 16.91 degrees Celsius in July this year, which was 1.48 C above the estimated July average for 1850-1900, the designated pre-industrial reference period. But July marked the end of 13-month period when each month was the warmest on record for the respective month of the year. July 2023 was the hottest month ever averaging 16.95 C. \"The streak of record-breaking months has come to an end, but only by a whisker. Globally, July 2024 was almost as warm as July 2023, the hottest month on record,\" Samantha Burgess, Deputy Director of the Copernicus Climate Change Service (C3S). \"July 2024 saw the two hottest days on record. The overall context hasn\u2019t changed, our climate continues to warm. The devastating effects of climate change started well before 2023 and will continue until global greenhouse gas emissions reach net-zero.\" The UN Framework Convention on Climate Change has repeatedly said phasing out of fossil fuels was urgently needed for the world to meet its Paris Agreement commitments, to limit warming to 1.5 C above pre-industrial levels. Climate change and energy July 22 and July 23 were declared the hottest days on record with temperatures reaching 17.16 C and 17.15 C respectively, data showed. Temperatures were mostly above average in southern and eastern Europe, western Canada, western US, most of Africa, the Middle East and Asia, and eastern Antarctica. Sea surface temperatures also remained at very high levels with temperatures for June averaging 20.88 C over the global extrapolar ocean, from 60 degrees south to 60 degrees north, the second-highest value on record for the month, and only 0.01 C below July 2023. Warmer temperatures are already starting to have an impact on energy demand and renewable energy output, with extreme weather events seen in 2023 and more expected this year. The continuing wildfires in the Western Canadian province of Alberta could impact some 400,000 b\/d of crude oil production, with multiple producers being on high alert as 119 fires are currently burning in the province. Alberta is home to some 4 million b\/d of heavy and light oil and nearly 16.8 Bcf\/d of natural gas production. The likely return of the climate phenomenon La Nina, and the associated shift in global weather patterns and temperature extremes, could also result in a fresh wave of disruption and volatility across key global commodity markets. Climate change caused by a surge in greenhouse gas emissions has been increasing the intensity and frequency of extreme weather events, all of which have a measurable impact on air quality, human health and the environment. Global energy-related CO2 emissions rose to a record high 37.4 gigatonCO2e in 2023, an increase of 410 million mtCO2e from 2022, according to International Energy Agency data. ","headline":"EU's climate monitor says 2024 'increasingly likely' to be warmest year on record","updatedDate":"2024-08-08T10:29:33.000"},{"Unnamed: 0":235,"body":" The differential between the European propane and naphtha markets has narrowed consistently over the past three months to near year-on-year lows as the propane market gained steeply while naphtha strength remained marginal. A significant narrowing in the spread between the two commodities could see naphtha preferred in flexible petrochemical steam crackers as the margins for naphtha turn more favorable. Platts, part of S&P Global Commodity Insights, assessed the discount of the front-month CIF NWE propane swap to the equivalent Platts CIF NWE naphtha swap at $79\/mt on Aug. 7, which has been narrowing consistently since the highest point of $181.25\/mt on April 4. While narrowing differentials could re-incentivize naphtha use at flexible steam crackers, some players remain skeptical of any substantial shift in the market, with the majority of steam crackers still on max LPG due to larger margins. For LPG, butane continues to offer the largest returns, as steam cracker margins stood at $463.54\/mt compared with $353.91\/mt for propane in Europe. Prices in the European propane market have been buoyed by early month crude oil strength and tightness in the market. Short supply has emerged on the back of reduced US LPG inflows to the continent after Hurricane Beryl disrupted loadings, while stronger netbacks into the Asian market have pulled US product eastward. \u201cThe main concern is US exports, with a healthy arbitrage into the East, all the barrels are heading there due to robust demand, leaving US producers with very few spot barrels and keeping the flat price very high,\u201d one source said. According to the source, \u201cExpectations from US producers when selling are based on FEI netbacks, making the economics of importing into Europe very challenging due to extremely high US premiums and terminal fees.\u201d Consequently, European and Mediterranean LPG imports plunged to n ear three-year lows for July as players struggled to locate product. \u201cPropane is strong due to delays in the US and stronger Asian demand, which adds to general strength in gas,\u201d a second Europe-based trader said, adding that although the propane market remains heavily backwardated, petrochemical players \u201cstill buy propane, having a baseload of propane they have to take, and potentially need a narrower discount to make a switch to naphtha\". Meanwhile, the naphtha market was relatively backwardated but faced a limited increase on the month, especially as crude oil prices weakened, thus narrowing its premium over propane. Platts, part of Commodity Insights, assessed the front-month CIF NWE naphtha swap at $646\/mt and the August-September time spread at $12.50\/mt on Aug.7. Another European trader said naphtha market tightness reduced slightly over July, thus explaining the limited rise in naphtha prices. According to this source, the European naphtha market \u201cdoes not look super short as it seems most blenders and petrochemical companies are covered\u201d, the \u201csituation does not look as intense as last month\u201d. The upcoming refinery turnaround season and recent steepening of naphtha backwardation structure can, however, give much stronger support to naphtha prices looking forward. ","headline":"European LPG discount to naphtha narrows, shifting petchem feedstock appetite","updatedDate":"2024-08-08T10:22:07.000"},{"Unnamed: 0":236,"body":" Thai Oil reported a slight decrease in the utilization rate at its 275,000 b\/d Sriracha refinery in the second quarter of this year compared with last year due to a planned shutdown at a crude distillation unit in May, the company said in its Q2 results report Aug. 8. The utilization between April and June was 111%, which was lower than 113% in Q2 last year as its CDU-1 and related units had a planned shutdown for 11 days in May this year. However, the Q2 utilization was higher than 105% in Q1 as its CDU-3 had experienced an unplanned shutdown for 13 days in January due to technical issues. In Q2, the Sriracha refinery processed 306,000 b\/d of crude oil, lower than 311,000 b\/d over the same period in 2023 but higher than 288,000 b\/d in Q1 of 2024. Thai Oil\u2019s gross refining margin in Q2 was at $3.8\/b, falling from $4.5\/b in Q2 2023 thanks to lower spreads of gasoline and jet fuel\/kerosene over Dubai crude oil prices because of oversupply. The GRM between April and June tumbled from $9\/b in Q1 largely due to the decline in spreads of almost all refined products, resulting from high supply and elevated inventory levels in the US, the company said. Thai Oil\u2019s utilization in the first half was 108%, lower than 113% in the first six months of 2023. Its Sriracha refinery processed 297,000 b\/d of crude oil over this period, lower than 309,000 b\/d in H1 last year. The company\u2019s GRM in H1 was $6.3\/b, lower than $7.2\/b in H1 2023. Meanwhile, Thai Oil reported little progress on its delayed clean fuel project (CFP). The company completed 96.8% of work at the project as of June 30, slightly higher than 96% as of March 31. The CFP will help Thai Oil move from producing low-value products to producing higher value and more environmentally-friendly products. It will also enable the company to process more types of crude oil with higher quantities. Thai Oil initiated the commissioning of the Hydrodesulfurization unit (HDS-4) in February, ahead of schedule. The unit played a vital role in enabling the company to comply with the Euro-5 standard, which was enforced in Thailand this year. Additionally, Thai Oil is working to accelerate the commissioning of the remaining units, it said. The company said the capex for Thai Oil and its subsidiaries over 2024-2027 will be kept at $743 million, comprising $228 million for the CFP. ","headline":" Thai Oil\u2019s Q2 utilization drops on planned CDU shutdown","updatedDate":"2024-08-08T09:50:35.000"},{"Unnamed: 0":237,"body":" South Korea\u2019s top oil refiner SK Innovation said Aug. 8 that its upstream unit has joined a project to build a submarine carbon storage facility in Australia as part of its strategy to diversify beyond oil and natural gas development. SK Earthon, the exploration and production subsidiary of SK Innovation, has acquired a 20% stake in the project to explore the G-15-AP submarine mining area off the northwest coast of Australia. \u201cThe G-15-AP block marks the first mine to be used to store carbon captured from industries in Australia,\u201d SK Innovation said in a press release. The project is 75% owned by InCapture, an Australian carbon capture and storage company, and 5% by CCS technology consulting company CarbonCQ. The three entities will build the undersea facility and sign deals with local companies so as to start the CCS project from 2030, after feasibility studies to confirm the project\u2019s business value, according to SK Earthon. \u201cThe CCS project in Australia is expected to generate synergy for SK Earthon\u2019s traditional business of energy development projects and new business of carbon capture and storage,\u201d it said. SK Earthon is currently involved in 13 oil and gas upstream projects across eight countries, including six blocks under production, such as Block 17-03 in China and Block 15-1 in Vietnam. The 13 projects also comprise three LNG ones, such as Oman LNG and Qatar\u2019s Ras Laffan LNG. The company has recently adopted a strategy to concentrate its upstream business efforts in the Asian region, moving away from remote markets like the US and Peru, as part of \"business reorganization strategy focused on decarbonization.\" SK Earthon has led a group of South Korean companies for the Shepherd CCS project in Malaysia, which launched in August 2022 in a consortium that also consists of Malaysia's state-run oil company Petronas. The Shepherd project aims to capture CO2 emitted from industrial sites in South Korea and collect it in local carbon capture plants before transporting it to Malaysia for onshore or offshore storage. \u201cSK Earthon aims to secure carbon capture and storage capacity of 2 million mt by 2030, 5 million mt by 2040 and 16 million mt by 2050,\u201d the release said. ","headline":"South Korea\u2019s top oil refiner SK Innovation joins carbon storage project in Australia","updatedDate":"2024-08-08T09:14:41.000"},{"Unnamed: 0":238,"body":" The Middle East sour crude complex saw cash differentials for key markers jump for a second session to hit month-to-date highs during the Singapore Platts Market on Close assessment process Aug. 8. Platts, part of S&P Global Commodity Insights, assessed October cash Dubai and cash Oman at a premium of $1.07\/b to same-month Dubai crude futures at the market close, both up 37 cents\/b on the day. October cash Murban was also assessed at a premium of $1.07\/b to same-month Dubai futures, up 35 cents\/b on the day. During the MOC, 22 October Dubai partials of 25,000 barrels each traded. The sellers were Mitsui, Idemitsu, PetroChina, Unipec, Trafigura, Phillips 66, BP and Reliance and the buyers were Gunvor and Vitol. No convergences were reached during the MOC. A convergence occurs when 20 partials are traded between two counterparties, resulting in a full 500,000-barrel physical cargo being declared from the seller to the buyer. In the broader market, Saudi Aramco's September crude oil allocations have yet to be released, though spot trades were taking place for October-loading ADNOC crudes, traders said. October-loading Murban crude cargoes were heard sold to two South Korean refiners at premiums in the high-60s cents\/b to Platts Dubai, FOB, while an October-loading Umm Lulu crude cargo was also heard sold to South Korea, though price levels for the cargo were unclear. Iraq's SOMO was also seen issuing its September crude oil official selling prices late in the Aug. 7 session. ","headline":" Middle East sour crude cash differentials hit month-to-date highs","updatedDate":"2024-08-08T08:20:14.000"},{"Unnamed: 0":239,"body":" State-owned oil and gas major China National Offshore Oil Corp. has approved more than 100 billion cubic meters of proven natural gas reserves at the Lingshui 36-1 gas field in the South China Sea, the company said in a statement late Aug. 7. Lingshui 36-1 gas field is the first large-size ultra shallow gas field in ultra-deep water in the world, which opens a new area of exploration in deep waters, CNOOC said. Located in the southern portion of the Central Sag, Qiongdongnan Basin, the average water depth of the gas field is approximately 1,500 meters, and the burial depth is 210 meters, CNOOC said, adding that the field has been tested to produce over 10 cu m\/day of open flow natural gas. CNOOC has been searching for oil and gas resources in the South China Sea for decades, finding a total of more than 1 trillion cubic meters of proven natural gas reserves, the company said. These include multiple large-size gas fields discovered in Yinggehai, Qiongdongnan and Pearl River Mouth basins, namely Dongfang 1-1, Liwan 3-1, Lingshui 17-2, Baodao 21-1 and now, Lingshui 36-1, the company added. \"The newly discovered ultra-deep-water ultra-shallow gas field is an important composition of the trillion cubic meters gas region in the South China Sea,\" Zhou Xinhuai, CNOOC\u2019s CEO and President said. Apart from the South China Sea, CNOOC is building another two gas production areas in the Bohai Sea and onshore, with current proven natural gas reserves of about 500 Bcm and 400 Bcm, respectively, data from the company showed. The Lingshui 36-1 gas field is situated in the southern part of the Qiongdongnan Basin, south of the LS 17-2 deep-water gas field which was the most significant large-sized gas discovery for CNOOC in the deep-water of the Qiongdongnan Basin when it was discovered in March 2014, according to Linda Wang, Associate Director for Research in Upstream at S&P Global Commodity Insights. \u201cThe discovery has proved the exploration potential of structural and lithological trap in the central canyon system of the Lingshui Sag and confirmed the good exploration prospects in the deep-water area of the Qiongdongnan Basin,\u201d Wang said in a note. \u201cThe LS 17-2 field was brought onstream in June 2021 and the field is expected to reach a peak output of 328 MMcf\/d of gas and 6,751 b\/d of condensate in 2022,\u201d Wang added. ","headline":"CNOOC approves 100 Bcm of proven reserves at South China Sea gas field","updatedDate":"2024-08-08T05:40:35.000"},{"Unnamed: 0":240,"body":" The Singapore government will work with CAPGC, which is buying over Shell\u2019s assets in the city-state, as well as others in the refining and petrochemicals sector to help decarbonize their product slate, Trade and Industry Minister Gan Kim Yong said Aug. 6. Gan, who is also Singapore\u2019s deputy prime minister, was responding to a parliamentary question on how the sale of Shell\u2019s assets would impact the city-state\u2019s emissions levels. \u201cThe Government\u2019s commitment to reducing the carbon footprint of the petrochemical sector and creating a Sustainable Jurong Island remains unchanged,\u201d he said in a written reply to the Parliament. Around one-third of Singapore\u2019s total emissions are directly from the refining and petrochemicals sector, which accounts for most of the activities on Pulau Bukom and Jurong Island -- where Shell\u2019s assets are located as well. In May, Shell Singapore had confirmed that it will sell its Energy and Chemicals Park in Singapore to CAPGC -- a joint venture between Chandra Asri Capital and Glencore Asian Holdings -- and the sale is due to be completed by end-2024. The transferred interests from Shell include both physical assets and commercial contracts, including a 237,000 b\/d refinery and a 1.1 million mt\/year ethylene steam cracker at Pulau Bukom, as well as downstream chemicals assets on Jurong Island. \u201cAt this point, it is not yet clear how the buyers of Shell\u2019s refinery and petrochemical assets intend to operate or transform the facilities,\u201d said Gan. \u201cIn any case, the Government is not at liberty to disclose company-level emissions data,\u201d he added in response to the parliamentary question. The Singapore complex is Shell's largest petrochemicals production site in Asia and was its biggest ever downstream and petrochemicals investment when completed in 2010. Shell's Singapore chemicals assets, including its share of JVs, produce roughly 1.4 million mt\/year of ethylene, or 18% of the company\u2019s present global capacity. Singapore currently charges a carbon tax of S$25\/mtCO2e ($18.75\/mtCO2e) this year and it remains on track to raise this to S$45\/mtCO2e ($33.18\/mtCO2e) in 2026, Sustainability and the Environment Minister Grace Fu said in a separate parliamentary written reply on the same day. ","headline":"Singapore to work with Shell\u2019s refinery, petrochemicals asset buyers to decarbonize: minister","updatedDate":"2024-08-08T04:17:34.000"},{"Unnamed: 0":241,"body":" The BLM Montana-Dakotas federal oil and gas lease sale netted nearly $24 million in total high bids in the latest quarterly auction, according to Energynet.com. During the sale, 23 parcels covering 4,819.2 acres received bids, of an original 26 parcels covering 5.569.6 acres offered to industry, the website, a platform for selling petroleum properties both government and privately owned, said Aug. 6. The sale received total high bids of $23.9 million. Parcels in states with predominantly Bakken Shale production received the priciest bids, Energynet.com data showed. The largest bid was $15 million for a 273-acre parcel in Mountrail County, North Dakota -- one of the biggest Bakken producing states. A parcel in that same state's McKenzie County -- another big Bakken producing region -- went for $1.68 million. But a parcel in nearby Richland County, Montana, where the Bakken was originally discovered decades ago, captured $2.34 million, Energynet.com records show, while a second Richland County parcel went for $1.44 million. Those four bids alone accounted for more than $20 million, or nearly 86% of all high bids. Ten of the 26 parcels offered were in North Dakota, while 16 were in Montana. The three parcels that did not receive bids were all in Montana, Eergynet.com records show. The second-quarter 2024 BLM Montana-Dakotas federal oil and gas lease sale, held in late April, received total high bids of $663,524 for 21 parcels covering 4,635.11 acres, according to the website. And the first-quarter BLM Montana-Dakotas federal oil and gas lease sale took in total high bids of $2.4 million for six parcels covering 2,335.6 acres. ","headline":"BLM federal Montana-Dakotas oil and gas lease sale nets nearly $24 mil: Energynet.com","updatedDate":"2024-08-08T04:13:37.000"},{"Unnamed: 0":242,"body":" Refinery: Sohar, Oman Owner: OQ Overall capacity: 198,000 b\/d Units affected: Unclear Duration: Started week of Aug. 5; targeted restart date Aug. 13 Notes: Oman's 198,000 b\/d Sohar refinery was heard to have undergone an unplanned shutdown in the week of Aug. 5, trade sources said Aug. 7. Refinery operator OQ could not be immediately reached for comment. The refinery is targeting a restart date of Aug. 13, sources said. The refinery was heard to have released a very prompt August-loading Oman crude cargo into the market due to the shutdown, sources said. Source: Market sources ","headline":" Oman's Sohar undergoes unplanned shutdown: sources","updatedDate":"2024-08-08T03:53:50.000"},{"Unnamed: 0":243,"body":" Crude oil futures were higher in midmorning trading Aug. 8, following the sixth consecutive weekly decline in US commercial crude stocks. However, concerns about weakening activity in the world's biggest economies, the US and China, limited the gains. At 11:35 Singapore time (0335 GMT), the October ICE Brent crude oil futures contract increased 21 cents\/b, or 0.27%, to $78.54\/b, while the September NYMEX light sweet crude contract gained 31 cents\/b, or 0.41%, to $75.54\/b. US commercial crude stocks fell 3.73 million barrels to 429.32 million barrels in the week ended Aug. 2, data from the Energy Information Administration showed Aug. 7. The draw put stocks about 6% below the five-year average for this time of year. \u201cUS crude oil inventories are at their lowest level since February, this suggests demand for physical barrels remains robust, despite concerns about weak economic activity,\u201d said ANZ commodity strategists. US refinery utilization strengthened 0.4 percentage points on the week to 90.5% of capacity, and refinery net crude input increased 250,000 b\/d to 16.4 million b\/d. Meanwhile, both gasoline and distillate fuel production increased in the week ended Aug. 2. Slower demand and increased production have led to higher oil product stocks. US gasoline stocks climbed 1.34 million barrels to 225.1 million barrels, according to the EIA. The counter-seasonal build narrowed the deficit to the five-year average to 1.7% from 3.2% the week prior. Implied demand for gasoline declined for the second straight week, sliding 3% to 8.97 million b\/d and falling nearly 4% below normal for this time of year. Recent weaker-than-expected US employment data and contracting Chinese manufacturing activity have raised concerns about slowing economic growth and its impact on crude oil demand. \u201cThe latest trade data from China was relatively bearish, Chinese crude oil imports in July averaged 10.01 million b\/d, down 3.1% on the year and 11.8% lower on the month,\u201d ING commodity strategists said. Dubai swaps Dubai crude swaps strengthened, and intermonth spreads were steady in midmorning trading in Asia from the previous close on Aug. 8. The October Dubai swap was pegged at $76.16\/b at 10 am Singapore time (0200 GMT), widening $1.36\/b, or 1.36%, from the Aug. 7 Asian close. The September-October Dubai swap intermonth spread was pegged at 59 cents\/b at 10 am Singapore time, unchanged from Aug. 7, and the October-November intermonth spread was pegged at 46 cents\/b, also stable on the session. The October Brent-Dubai exchange of futures for swaps was pegged at $2.19\/b, widening 13 cents\/b on the day. ","headline":" Crude prices higher as US stockpiles extend decline, demand concerns cap gains","updatedDate":"2024-08-08T03:38:12.000"},{"Unnamed: 0":244,"body":" Qatar Petroleum announced the acceptance of September-loading LPG cargoes under term contracts with Asian lifters in line with nominated dates, without any cuts or delays heard, market sources said. \"Heard nothing unusual with Qatar acceptances for September,\" a Singapore-based industry source said. While some market participants cautioned that Asian demand for AG cargoes could fall as the landed cost of Middle East LPG exports could increase on the back of rising tensions in the Middle East, market participants also said the overall impact on landed prices could be quite mild as the market has already priced in regional tensions. \"I believe that the market has already priced in regional tensions in the Middle East such as the recent Houthi attacks on ships,\" an industry source said. Asian demand for LPG was heard stable to weaker, as Chinese PDH demand was heard lackluster with PDH average run rates heard at 73% in the week of Aug. 5, down 1% from the previous week, sources said. However, demand for LPG as a heating fuel is expected to increase moving toward the winter period, sources said. The spread between the month one (September) Saudi Aramco propane contract price swap and the month two (October) Saudi Aramco propane contract price swap was pegged at plus $2\/mt Aug. 7, widening from the Platts assessment at flat Aug. 6, while the September butane CP swap was pegged at $10\/mt below propane, S&P Global Commodity Insights data showed. ","headline":"Qatar announces acceptance of Sep LPG cargoes with no cuts or delays heard","updatedDate":"2024-08-08T02:45:55.000"},{"Unnamed: 0":245,"body":" The South Korean government aims to wrap up legal and administrative procedures required to fully implement the free trade agreement with Gulf Cooperation Council members by September, a deal that could allow local refiners to procure Middle Eastern sour crude cheaper and improve their margins. Minister for Trade Dukgeun Ahn and GCC Secretary General Jassim Mohammed Al-Budaiwi had signed a joint preliminary statement for the South Korea-GCC FTA in December 2023. The government is now aiming to complete an economic impact evaluation, seek the National Assembly's ratification agreement and execute other necessary administrative procedures for the FTA's entry into force, public relations managers and officials at state-run Korea Trade Investment Promotion Agency and the Ministry of Trade, Industry and Energy told S&P Global Commodity Insights over Aug. 6-8. \"Although the agreement was signed last year [2023], the treaty still requires various procedures to be cleared ... the ultimate goal is to finalize all necessary domestic procedures by September and to proceed to the formal implementation of the FTA before the end of the year,\" a MOTIE official said. Minister Ahn recently met Saudi Arabia\u2019s Minister of Commerce Majid bin Abdullah Al-Kassabi on July 30 in Seoul to discuss about the FTA's swift entry into force. \"To expedite the legal review process of both parties, we ask for [Saudi Arabia's] support as a member of the GCC,\" Ahn said at the July meeting. Apart from South Korea's top crude supplier Saudi Arabia, the six GCC members include other major crude suppliers such as Kuwait, the UAE, Qatar and Oman, as well as Bahrain. Among major Middle East crude suppliers to South Korea, only Iraq is not a GCC member. Sour crude trading edge Traders, feedstock managers and oil product marketers at major South Korean refiners indicated the formal implementation of FTA with major Middle Eastern crude producers would provide them a significant edge in buying Persian Gulf sour crude cargoes at a lower cost. South Korea currently levies a 3% tariff on imported crude oil, which is abolished or cut for volume from suppliers that have free trade agreements with the nation. In the first half of 2024, South Korea imported 160.6 million barrels from Saudi Arabia and paid on average $86.66\/b, Elsewhere, 39.1 million barrels came from Kuwait in the first six months at an average cost of $84.56\/b and 74.7 million barrels were imported from the UAE over the same period at an average price of $86.46\/b, latest data from state-run Korea National Oil Corp. showed. KNOC's import cost data includes freight, insurance, tax and other administrative and port charges. Platts, part of Commodity Insights, assessed Middle Eastern sour crude physical benchmark Cash Dubai at an average $83.26\/b in H1. \"If the FTA with GCC nations can be fully implemented by end of the year, we could restructure and reconfigure our Persian Gulf sour crude procurement plans for 2025 in a positive manner ... every cent saved on taxes and tariffs would all contribute to healthier refining margins,\" said a feedstock and logistics manager at a major South Korean refiner. The South Korea-US FTA, for example, allows cost cuts by up to $2\/b for WTI Midland crude purchases, a trade source at a South Korean refiner's feedstock trading team in Singapore said. South Korean refiners combined spent over $40 billion for feedstock crude purchases and procurement in H1, according to Korea Petroleum Association. FTAs with energy producing nations would be strategically essential for the world's fourth biggest crude importer, refinery sources based in Seoul and Ulsan said. Most recently, South Korea separately signed a bilateral FTA with the UAE on May 29, removing the 3% tariff on various Abu Dhabi sour crude grades including Murban, Das Blend and Upper Zakum over the next 10 years. ","headline":"South Korea aims for full GCC FTA execution by year-end, refiners hopeful for cheaper sour crude","updatedDate":"2024-08-08T02:09:25.000"},{"Unnamed: 0":246,"body":" Indonesia's Ministry of Energy and Mineral Resources set the Minas crude oil price at $84.95\/b for July, rising $3.35\/b from June, according to its monthly selling price notice seen by S&P Global Commodity Insights on Aug. 8. With the Dated Brent benchmark averaging $85.31\/b in July, the Minas alpha, or differential, for the month was at a discount of 36 cents\/b. Among Indonesia's other main grades, the July Indonesia crude price for Banyu Urip crude was set $1.36\/b higher on the month at $88.31\/b. The monthly ICPs are set retroactively. ICPs for main Indonesian crude grades: (Unit: $\/b) Grades May June July Change Minas 82.13 81.60 84.95 3.35 Attaka 79.91 79.35 81.91 2.56 Duri 86.67 85.88 86.97 1.09 Belida 80.15 79.54 82.06 2.52 Senipah 70.88 70.93 73.77 2.84 Banyu Urip 87.48 86.95 88.31 1.36 ICP alphas for main Indonesian crude grades: (Unit: $\/b) Grades May June July Change Minas 0.08 -1.01 -0.36 0.65 Attaka -2.14 -3.26 -3.40 -0.14 Duri 4.62 3.27 1.66 -1.61 Belida -1.90 -3.07 -3.25 -0.18 Senipah -11.17 -11.68 -11.54 0.14 Banyu Urip 5.43 4.34 3.00 -1.34 Source: Directorate General of Oil and Gas ","headline":"Indonesia sets Minas crude price at $84.95\/b for July, rising $3.35\/b from June","updatedDate":"2024-08-08T02:05:13.000"},{"Unnamed: 0":247,"body":" Hong Kong\u2019s Cathay Pacific Airways carried a total of 10.7 million passengers over the January-June period, a 36.4% year-on-year increase, while flight capacity -- measured available seat-kilometers -- rose 42.7%, the company reported in its 2024 interim results Aug. 7. Passenger traffic, measured in revenue passenger-kilometers, increased 34.9% on the year in the first half of 2024. This brought passenger load factor to 82.4%, 4.8 percentage points lower compared to the same year-ago period. \u201cOur passenger flights reached 80% of pre-pandemic levels as a Group within the second quarter as planned,\" Cathay Group Chair Patrick Healy said in a statement. \"As more passenger flights have been added to the market, we have seen yields begin to normalize as expected.\" \u201cOur strong performance for the first six months of the year was primarily driven by the ongoing robust demand for travel, and the solid performance of our cargo business,\u201d he added. Cathay Pacific carried 719,000 mt of cargo in the first half of the year, an increase of 10.4% compared to the same year-ago period. Cargo revenue tonne kilometers and cargo flight capacity rose 4.6% and 11.4% year on year, respectively. \u201cDemand was robust in the first half of 2024 with solid support from e-commerce and some traditional commodities, especially electronics,\" the company said in its results statement. \"The overall tonnage growth in Hong Kong and the rest of the Greater Bay Area exceeded our capacity growth compared with the same period last year.\" Overall, Cathay Pacific\u2019s revenue totaled HK$44,784 million in H1 2024, up 14% on the year. Tracking growth in Cathay Pacific\u2019s air traffic, Hong Kong imported 3.4 million kiloliters (541,107 b\/d) of jet fuel\/kerosene over January-June, surging 29.75% in the same year-ago period, latest Census and Statistics Department data showed. The data is published in kiloliters, which S&P Global Commodity Insights converts to barrels using a factor of 6.2898. Reflecting improving demand, the Platts-assessed FOB Singapore jet fuel\/kerosene cargo flat price averaged $100.48\/b in H1 2024, $1.52 higher compared to the same period a year ago, S&P Global Commodity Insights data showed. At the Asian close Aug. 8, the flat price was assessed at $89.89\/b. Looking ahead, demand for jet fuel is expected to remain strong for the rest of the year, driving global oil demand alongside gasoline and petrochemicals, Saudi Aramco CEO Amin Nasser told reporters on a media call Aug. 6. According to Nasser, global oil demand is anticipated to grow by 1.6 million b\/d to 2 million b\/d this year, up from his previous forecast of 1.5 million b\/d in March. Asian jet\/kerosene demand growth will remain strong on the year at 304,000 b\/d in the third quarter, driven by continued strength in the aviation sector due to increased global and regional air travel demand, Commodity Insights analysts said in the latest Asia short-term outlook for refined products. Notably, China and Southeast Asia will continue to lead regional jet\/kerosene growth at a rate of 200,000 b\/d and 67,000 b\/d, respectively. Japan is also experiencing a resurgence in demand, with an anticipated year-on-year increase of 43,000 b\/d in the third quarter, the analysts added. ","headline":"Cathay Pacific H1 2024 passenger traffic rises 36% on year; Hong Kong\u2019s jet fuel demand bolstered","updatedDate":"2024-08-07T23:44:33.000"},{"Unnamed: 0":248,"body":" Ultra-low sulfur diesel inventories in the US continued their upward trend, with notable stock builds in the Gulf Coast, while inventories on the Atlantic Coast dropped slightly, Energy Administration data released Aug. 7 showed. Total US ULSD stocks rose by 684,000 barrels to around 117 million barrels in the week ended Aug. 2, a nearly six-month high, the EIA said in its Weekly Petroleum Status Report. Stocks increased even as demand for ULSD weakened week on week, according to the EIA. ULSD product supplied, which is considered a demand indicator, decreased for the second consecutive week by 256,000 b\/d to reach 3.469 million barrels, a four-week low. ULSD inventories in the US Gulf Coast increased 1.16 million barrels, reaching a seven-week high of 39.15 million barrels. On the other hand, inventories in the USAC slid by 576,000 barrels from the previous week's 18-month high. This rise in USGC inventories contributed to a net boost in the nation's supply of ULSD by 684,000 barrels, resulting in a 26-week high of 117.47 million barrels. Meanwhile, US distillate refinery utilization rates, which includes ULSD, rose from a 14-week low by 0.4 percentage point to 90.5%. US production of ULSD increased by 74,000 b\/d to 4.92 million b\/d, a two-week high, reflecting the refinery utilization rate builds. ULSD imports fell 23,000 b\/d to 114,000 b\/d in the week ended Aug. 2. In comparison to the same year-ago week, import quantities experienced a 43% increase from 65,000 b\/d in Aug. 2023. Total US distillate exports, including ULSD, increased 371,000 b\/d, bringing the total exports to 1.55 million b\/d, recovering from the previous week\u2019s drop. Platts, part of S&P Global Commodity Insights, assessed the differential for benchmark USGC ULSD minus 0.27 cent weaker Aug. 7 at NYMEX September ULSD futures minus 9.80 cents\/gal, while its outright price rose 5.71 cents to $2.2576\/gal, as the underlying futures contract settled 0.0598 cent higher at $2.3556\/gal. ","headline":" Total ULSD stocks near a six-month high as demand continues to fall","updatedDate":"2024-08-07T22:21:53.000"},{"Unnamed: 0":249,"body":" US product supplied of propane and propylene jumped to a three-month high in the week ending Aug. 2, according to Energy Information Administration data released Aug. 7. The product supplied of propane and propylene rose to 1.032 million b\/d from 716,000 b\/d in the week ended July 26. EIA data reported that domestic product has fluctuated heavily since the week ending July 12, bouncing between half a million to over one million b\/d. The recent data shows more product is being supplied in comparison to this time last year, which closed at 803,000 b\/d in the week ending Aug. 4. US refiner, blender and gas plant net production of propane and propylene fell from a three-week high on the week as it dropped 19,000 b\/d to 2.629 million b\/d. Nationwide stocks of propane and propylene continued the seasonal trend of strengthening for the fall. On the week, US stocks rose 515,000 barrels to 87.909 million barrels. The inventories fell short in comparison last year, which closed at 89.950 million barrels in the week ended Aug. 4, 2023. Data from 2023 showed propane and propylene inventories stockpiled from May until mid-October. \u201cPropane is well supplied so pricing near lows v. crude,\u201d said one NGL broker. Platts assessed US Gulf Coast propane at the Enterprise terminal up 3.375 cents to 75.50 cents\/gal, reaching a one-week high. Exports of propane and propylene rise for the second week, strengthening by 7,000 b\/d to 1.648 million b\/d. The price of LPG Very Large Gas Carrier freight traveling from Houston to Northwest Europe weakened on the day, shedding $2.00\/mt to $48\/mt, while Houston to Chiba held steady at $90.00\/mt. \u201cExpect the price of shipments to Japan to drop into the 80's soon,\u201d said one LPG shipping broker. \u201cEast market is much weaker, so owners sending their ships West.\u201d Platts is a part of S&P Global Commodity Insights ","headline":" Product supplied of propane and propylene reach three-month high","updatedDate":"2024-08-07T21:10:18.000"},{"Unnamed: 0":250,"body":" Tanker operator International Seaways spent the second quarter replacing a portion of its aging fleet, as order books grew to about 11% of its total fleet, with seaborne activity bolstered by increased demand paired with ongoing disruptions to oil markets, the company said Aug. 7. \"Strong tanker market naturally would dictate more ordering and the order book has grown to about 11% of the total fleet,\" CEO Lois Zabrocky said during the company's second quarter earnings call. \"However, ships on order are not enough to replace a fleet that is aging significantly.\" Today, the average age of the tanker fleet is over 13 years old and is \"likely to get older with so few newbuilding deliveries.\" International Seaways took delivery of six eco MR's while selling three vessels aged 15 years or older, which lowered its average MR age by one year. By mid-July, the tanker operator closed on one out of three of the vessel sales. \"In general, older ships have less efficiency and utilization,\" Zabrocky said. \"With a greater percentage of the fleet in this vintage, the industry needs more shifts to cover the increase in seaborne demand.\" Total oil demand is expected to grow by 1.7 million b\/d in 2024, with growth focused in China, India and other major Asia oil demand centers, according to analysts at S&P Global Commodity Insights. \"We expect oil demand to continue to grow at a rate above its 30 year average growth, with a good portion of the growth regionally in Asia which has grown slower than expected at the beginning of the year,\" Zabrocky added. The company expects no more than 2 million b\/d of oil demand growth in 2024, expecting it to land in a range between 1 million and 1.5 million b\/d. Referencing both tanker supply disruptions and geopolitical risks, crude tanker demand is expected to grow by 8%-9% in 2024 and decrease 3.5%-4.5% in 2025, according to BIMCO's Tanker shipping Market Overview and Outlook published in May. According to the report, crude tanker demand is forecast to outpace supply in 2024 but grow slower than supply in 2025 as ships potentially return to the Suez Canal and sailing distances shorten. Product tanker demand is forecast similarly, to increase between 5%-6% in 2024 and decrease 3%-4% in 2025. The company reported 47% of fixtures booked at approximately $373,000\/d, with VLCC's averaging $46,400\/d during the second quarter while Suezmax and Aframax rates averaged at $45,000\/d and $31,500\/d, respectively. LR1 and MR spot fixtures averaged at $53,100\/d and $35,000\/d respectively over the same period. The Platts 70,000 mt US Gulf Coast-UK Continent freight assessment from S&P Global Commodity Insights averaged $50.14\/mt in January 2024, up from $43.21\/mt in the fourth quarter of 2023 and a $28.21\/mt average in the third quarter of 2023. Platts, a part of Commodity Insights, assessed freight for the 70,000 mt US Gulf Coast-UK Continent route for loading Aug. 12-27 at w120 Aug. 7, exclusive of EU Emission Trading Systems costs, reflected at w5 premium, down w0.25 from Aug. 6, for average-lifting tonnage. Platts assessed freight for the 270,000 mt VLCC US Gulf Coast-UK Continent route for the typical loading dates of Aug. 22-Sept. 21, at lump sum $2.69 million Aug. 7. Freight for the 270,000 mt VLCC US Gulf Coast-China route for the typical loading dates of Aug. 22-Sept. 21 were assessed at lump sum $6.85 million Aug. 7. ","headline":"Internatonal Seaways focused on replacing aging fleet during second quarter: CEO","updatedDate":"2024-08-07T21:07:05.000"},{"Unnamed: 0":251,"body":" Devon Energy's oil production hit an all-time record level in the second quarter of 2024, driven by the Delaware Basin which remains by far its biggest operation as it prepares to add a sizable Williston Basin acquisition announced in the period, the company's top executive said Aug. 7. Devon's Q2 oil production reached 335,000 b\/d, Devon CEO Rick Muncrief said during a company earnings conference call. That figure was up 5% from just three months earlier, and also exceeded guidance by 3% in the quarter, Devon quarterly production figures showed. Of Devon's total Q2 oil volumes, 221,000 b\/d, or 66%, came from the Delaware Basin. \"Our business continued to strengthen and build momentum\" in Q2, Muncrief said. Besides the output kick from Delaware oil production, \"we also saw improved cycle times across the entire company, setting multiple drilling and completion records.\" Devon's total Q2 oil, gas and NGL output averaged 707,000 b\/d of oil equivalent, up about 6.5% from three months ago and nearly 7% more than in the same period in 2023. A \"key driver\" of the record-setting oil result was what Muncrief called a \"superb\" performance from the Delaware Basin where the company benefitted from addition of a temporary fourth hydraulic fracturing crew. \"We were able to bring online 62 new Delaware Basin wells in the quarter,\" he said. \"Well productivity from this batch of wells was ... outstanding with per-well recoveries on track to achieve a greater than 10% uplift compared with last year's program.\" Devon's total Delaware Basin output also posted record-high volumes in Q2 of 461,000 boe\/d, which represents a 5% growth rate compared with the previous quarter, Clay Gaspar, Devon's executive vice president and chief operating officer, said. 10% uplift from new Delaware wells \"We brought online more than 60 wells during the quarter,\" Gaspar said. \"These wells ... achieved average 30-day rates of more than 2,800 boe\/d, with [ultimate] recoveries projected to exceed 1.3 million boe per well.\" \"It's no surprise that the Delaware is the driving force behind the company's improved production outlook,\" he said. Total Q2 production spiked after a full year of virtually flat output in the low-to-mid-660,000s\/boe\/d. But besides the Delaware Basin, the larger quarterly volumes came from two other key Devon spheres of operation \u2013 the Eagle Ford Shale and the Anadarko Basin, Gaspar said. \"In the Eagle Ford, production growth was driven by strong redevelopment results in DeWitt County, [Texas] where average 30-day rates from our 15-well program consistently exceeded 3,000 boe per day per well,\" he said. \"In the Anadarko, our capital program driven by our joint venture with Dow delivered both solid returns and double-digit production growth in the quarter.\" Eagle Ford volumes grow 13% in Q2 Eagle Ford total volumes of 79,000 boe\/d in Q2 grew 13% from Q1, mainly from natural gas which rose to 92,000 Mcf\/d, up 16% over Q1, while gas volumes in the Anadarko Basin also rose 9% over Q1 to 244,000 Mcf\/d. \"Looking ahead, we expect the benefit of these carried enhanced returns [in the Anadarko Basin] with Dow will support activity through most of next year,\" he added. \"We're evaluating opportunities to expand this mutually beneficial partnership.\" Meanwhile, owing to its \"solid\" performance for H1 2024 of better-than-anticipated well results and improved cycle times year-to-date, Devon has raised its guidance for the second time this year, this time 5% higher than its original outlook, to a range of 677,000-688,000 b\/d of oil equivalent, Muncrief said. In early July, the company announced it would acquire the Williston Basin assets of Grayson Mill Energy for $5 billion, a purchase which bulks up Devon's portfolio by 100,000 boe\/d of production in the basin and 307,000 net acres, making it one of the largest US oil producers at around 375,000 b\/d. The acquisition is scheduled to close before the end of September. \"This transaction nearly triples our production and expands our inventory in the Williston Basin,\" Muncrief said. In Q2, Devon produced 61,000 boe\/d from the Williston, unchanged from Q1. Although there was a slight pullback in Devon's Q2 Williston oil volumes to 37,000 b\/d from 40,000 b\/d in Q1, the company made it up on the gas side with 71,000 Mcf\/d in Q2, up 13% from Q1. The company maintains its full-year capital budget range of $3.3 billion to $3.6 billion but expects to be in the upper part of the range from efficiency gains that led to bringing activity forward. In the third quarter, Devon expects oil production to average 319,000 b\/d to 325,000 b\/d. ","headline":"Devon Energy's oil output hits all-time record high from Delaware, Eagle Ford operations","updatedDate":"2024-08-07T21:01:26.000"},{"Unnamed: 0":252,"body":" Brazilian independent oil and natural gas producer Prio remains in a holding pattern amid plans to develop the offshore Wahoo discovery and carry out maintenance work and interventions at shuttered wells amid ongoing work actions at key regulatory agencies, company executives said Aug. 7. \"We are waiting for the green light and expect to see it in coming weeks,\" Prio Chief Operating Officer Francisco Francilmar Fernandes said during a conference call with analysts and investors. \"We're going to adapt and deliver results in the quickest way possible.\" Prio needs two environmental licenses to move forward with development of Wahoo, which is expected to pump 40,000 b\/d from four production wells and two water injection wells, company officials said. That includes one license to drill production and injection wells and one license to install submarine equipment, manifolds and production lines that will be tied back to the FPSO Valente floating production, storage and offloading vessel anchored at the nearby Frade Field. The licenses, however, have been held up by work-to-rule actions in place at the Brazilian Institute for the Environment and Natural Resources, or IBAMA, since January, Prio officials noted. In late June and early July, IBAMA workers walked off the job. While a federal judge ordered workers involved in environmental licensing to return to work, the work-to-rule actions have remained in place. \"We're watching for a solution to this impasse very attentively so that we can return to growing production,\" CEO Roberto Monteiro said. The approvals processes for the two licenses are advancing in parallel and will allow Prio to move forward with installation and drilling as soon as they are granted, Monteiro said. Prio will use its company owned Hunter Queen rig to drill the Wahoo wells, which should take about 60-70 days each to complete. Work to install submarine equipment and production lines, meanwhile, will take about 60-90 days to complete once work starts, Monteiro added. Prio has arranged contracts with Sapura that create a window to conduct the work in September-December. But any additional delays into 2025 would require further negotiations to secure a ship to carry out the submarine installations, Monteiro said. First oil could be produced with just a single well, depending on the timing, and will likely take place in the first half of 2024, Monteiro said. So far, Prio has spent about $500 million-$600 million on development of Wahoo, out of an initial investment budget of about $800 million, Monteiro said. Prio expects to spend the remaining $200 million to drill the production wells at the field and install the submarine equipment. Polvo, Albacora Leste wells In addition to the environmental licenses for Wahoo, Prio also needs IBAMA to approve workovers at the Frade field and Polvo-Tubarao Martelo production hub, Monteiro said. In the second quarter of 2024, Prio shuttered the ODP3 production well at Frade as well as the TBMT-8H, TBMT-10H and TBMT-4H wells at Tubarao Martelo. The delays will likely cause average output from Frade to drop to about 42,000-43,000 b\/d in 2024, Fernandes said. The Polvo-Tubarao Martelo hub, meanwhile, should return to average output of about 15,000-16,000 b\/d after Prio swaps out faulty pumps in the three idled production wells. Prio also plans to drill two new production wells at Polvo in coming months, which could add up to 1,000-1,500 b\/d, Fernandes said. A revitalization campaign is also planned for Albacora Leste after Prio completed a 13-day maintenance shutdown in July, Monteiro said. Under the plan, Prio wants to add eight production wells and two-three injection wells at Albacora Leste. Five of the new production wells, which will take about 70 days to drill, should add about 5,000 b\/d worth of output. In-fill drilling also will add three wells that could produce about 3,000 b\/d. \"Once we get the environmental licenses we need, we have about one year of work ahead of us,\" Monteiro said. Prio also remains on the lookout for mergers and acquisitions opportunities, with about $1.2 billion worth of cash on hand at the end of the second quarter, Monteiro said. \"We are paying attention and are animated about M&A opportunities over the next 12 months,\" Monteiro said. \"Prio doesn't work in pure exploration, so M&A is an important entryway for the company.\" Prio is evaluating the potential sale of a stake in the Peregrino heavy oil field, where China's Sinochem has put up its 40% minority stake in the field up for sale, Monteiro said. Equinor owns a 60% operating stake. In addition, Prio also is looking at opportunities in the US Gulf of Mexico, Monteiro said. Recent discoveries could see major oil companies move toward development of deeper, high-pressure deposits in the region. That would open the door for Prio to buy assets that it could use to create a production hub in the region. Prio, however, isn't interested in onshore assets, Monteiro said. \"I think it adds too much complexity. We want to operate offshore,\" Monteiro said ","headline":"Brazil's Prio still waiting on IBAMA license approvals to boost oil, gas output","updatedDate":"2024-08-07T21:01:25.000"},{"Unnamed: 0":253,"body":" Delek US expects third-quarter refinery utilization rates for its four-refinery system to dip below its record-high Q2 rates, a company executive said Aug. 6. \u201cBottom line for our second quarter: safe, compliant and reliable operations led the way to record-high throughput of 316,000 b\/d and a favorable $5.02 b\/d cost structure for our refining system,\u201d Joseph Israel, Delek US\u2019 head of operations, said on the company's Q2 results call. \u201cOur implied system throughput target for the third quarter is in the 301,000-315,000 b\/d range,\u201d he added. Delek US has been on a mission to upgrade operations at its four refineries, earmarking $20 million of its 2024 capital spending, with 93% going toward sustaining and regulatory projects and 7% going toward improving reliability and yields as it looks to boost margin capture at all four of its refineries. At Krotz Springs in Louisiana, Q3 planned throughput is expected in a 79,000-83,000 b\/d range, compared with 82,000 b\/d throughput in Q2, as \u201cthe team is in the final stages of preparation for our fourth-quarter turnaround,\u201d Israel said. Delek US previously announced planned work at Krotz Springs on the crude distillation unit and gasoline-making fluid catalytic cracking unit in Q4. Earlier this year, Delek US said the Krotz Springs turnaround will focus on three main issues: improving crude rates and flexibility through the enhancement of crude-unit piping, increasing conversion and yields at the FCCU by putting in a new reactor, and replacing and optimizing reformer catalyst operations. At El Dorado in Arkansas, Q3 throughput is expected in a 79,000-82,000 b\/d range. Q2 throughput totaled 85,000 b\/d with a production margin of $2.79\/b, driven, in part, by a \u201clow-margin environment\u201d where operating expenses averaged $4.12\/b. The Q2 Group-3 cracking margin for WTI ex-Cushing averaged $14.45\/b, down nearly $1 from Q1. It has rebounded so far in Q3, averaging $15.50\/b as of Aug. 7 on refinery outages in the Chicago market. Delek US \u201csuccessfully demonstrated\u201d to boost the volume of heavier crude at El Dorado to optimize operations by increasing volumes of heavy Canadian crude, Israel said. \u201cThe team is pushing forward initiatives on the product side, including product diversification and logistics to support new market optionality.\" A brief fire at the plant Aug. 6 was expected to have \u201cminimal impact on production,\u201d Israel added. Delek US is continuing to upgrade its refinery in Big Spring, Texas, successfully completing a benzene stripper project in Q2 that \u201cis well reflected in our results,\u201d Israel said. Big Spring\u2019s Q2 throughput was 74,000 b\/d, with production margin of $8.92\/b and operating expenses falling to $6.35\/b as Delek US moves closer to its targeted $5.50\/b range. Estimated Q3 throughput will fall in the 69,000-73,000 b\/d range. At Delek US' other Texas refinery, located in Tyler, Q2 throughput was 76,000 b\/d with production margins averaging $10.11\/b and operating expenses $4.83\/b. Q3 throughput is estimated in a 74,000-77,000 b\/d range. ","headline":" Delek US sees Q3 refinery utilization dip from record Q2 highs","updatedDate":"2024-08-07T20:31:17.000"},{"Unnamed: 0":254,"body":" Crude oil futures settled higher Aug. 7 against a backdrop of tighter US supply, stabilizing global financial markets and brewing Middle East tensions. NYMEX September WTI settled up $2.03 at $75.23\/b, and ICE October Brent climbed $1.85 higher to $78.33\/b. US commercial crude stocks fell 3.73 million barrels to 429.32 million barrels in the week ended Aug. 2, EIA data showed Aug. 7. The sixth-consecutive weekly draw put stocks 5.5% behind the five-year average for this time of year, opening the widest deficit since October 2023. American Petroleum Institute data released late Aug. 6 showed US oil inventories grew 180,000 barrels in the week to Aug. 2, while analysts surveyed by S&P Global Commodity Insights had forecast a 700,000-barrel decline over the period. NYMEX September RBOB ended the session up3.11 cents at $2.3573\/gal, and September ULSD climbed 5.98 cents to $2.3556\/gal. Oil futures were trading higher ahead of the EIA release, buoyed by signs of ascendant global financial markets and concerns of rising Middle East tensions. Global financial markets appeared to be stabilizing following a steep selloff early in the week sparked in part by a Bank of Japan interest-rate hike that preceded a rapid strengthening of the Japanese yen. On Aug. 7 BOJ deputy Governor Shinichi Uchida strived to reassure the market, saying \"the central bank will not hike interest rates when financial markets are unstable,\" leading to 1.2% growth in Nikkei average. \"It is still difficult for the market to feel safe after the Nikkei turmoil,\" but the rebound supports the crude futures market at the moment, said Bjarne Schieldrop, chief commodities analyst at Seb Research. Meanwhile, Middle East tensions remain in focus after Hezbollah issued a fresh pledge to respond to Israel's killing of its military commander despite international attempts to pursue a diplomatic solution to the ongoing conflict. \"Any spike in Middle Eastern tensions could drastically heighten the risk of supply disruptions, effectively leaving oil traders feeling as though they're perched precariously on a barrel of dynamite,\" SPI's Innes said. ","headline":" Crude rallies as traders eye tighter US supply, global financial market stabilization","updatedDate":"2024-08-07T19:56:45.000"},{"Unnamed: 0":255,"body":" The balance month -- currently August -- Dated to Frontline (DFL) contract gained $1.35\/b from the previous close Aug. 7, rallying from a two-month low the day before. The DFL represents the difference between ICE Brent futures and Dated Brent. Platts, part of S&P Global Commodity Insights, assessed the balance month DFL contract at $1.10\/b Aug. 7, up from minus 25 cents\/b Aug. 6 which marked the lowest value since June 13. The balance month DFL contract particularly strengthened towards the close of the Aug. 7 Platts Market on Close assessment process, trading at $1.10\/b at 1626 London time, up from 50 cents\/b at 1527. The balance month and month 1 DFL contracts flipped back into backwardation Aug. 7, after being assessed in contango for two days Aug. 5 and Aug. 6 for the first time since June 18. Platts assessed the month 1 -- currently September -- DFL contract at 46 cents\/b Aug. 7. Strength at the prompt was a theme for other key Brent complex contracts in the day, with prompt CFDs also making impressive gains. The balance week CFD, currently settling across Aug. 5-9, gained $2.03\/b from the previous close Aug 7, reaching its highest level since July 17. \"Front CFDs are certainly much stronger,\" said one derivatives trader. \"The market has put a halt to the recent downtrend; Dated has found some support following improving refinery margins and increasing tension in the Middle East,\" the trader added. The strengthening in these contracts contrasts with the weakness seen across the physical crude markets in recent days. Platts last assessed the global Dated Brent benchmark at $79.91\/b, up $3.635\/b on the day. ","headline":"Prompt DFL, CFD contracts rally","updatedDate":"2024-08-07T19:26:57.000"},{"Unnamed: 0":256,"body":" Notes: State oil company Petroper\u00fa, which operates four refineries with total capacity for 123,000 b\/d, saw total second-quarter fuel sales fall 4.4% to 93,700 b\/d. Domestic fuel sales dropped 5.7% to 65,700 b\/d from 75,000 b\/d a year ago, while exports rose 21.7% to 28,000 b\/d, the Lima-based company said Aug. 7 in a statement. The company increased crude purchases by 14% from a year ago to 53,600 b\/d from 47,100 b\/d, while slashing refined gasoline purchases by 63% to 19,000 b\/d from 51,700 b\/d. The company's 95,000 b\/d Talara oil refinery has been hampered by the closure of its flexicoking unit for the entire quarter, while its 200,000 b\/d North Peruvian Oil Pipeline (ONP) was damaged by repeated attacks by local communities during the quarter. The pipeline was brought back online in mid-July, while the flexicoking unit remains halted due to technical problems since late March. Petroper\u00fa took over three north coastal oil blocks last year, guaranteeing Talara direct supply of 7,100 b\/d of crude and 16,400-Mcf\/d of natural gas. Petroper\u00fa also holds stakes in northern oil Blocks 10 and 192. Petroper\u00fa posted a $268.8 million Q2 loss compared with a $222.3 million loss a year earlier as sales fell 8% to $874.2 million in the quarter from $949.3 million a year ago. Petroper\u00fa, which competes in Peru with Repsol's 117,000 b\/d La Pampilla refinery, is undergoing restructuring after posting eight straight quarterly losses. Source: Company statements ","headline":" Petroper\u00fa sees 2Q refined fuel sales drop 4.4% on year to 93,700 b\/d","updatedDate":"2024-08-07T19:22:19.000"},{"Unnamed: 0":257,"body":" US Gulf of Mexico pure-play operator W&T Offshore plans to unfurl details of its latest drilling joint venture that would involve other investors in the coming weeks, the company's top executive said Aug. 7. The JV would involve an as-yet undetermined number of wells and expenditures with several participants, which would include institutional investors, E&P oil and gas industry partners and financial players, W&T's CEO Tracy Krohn said during a second-quarter earnings call. However, \"it looks like it will be about six or seven wells\" to be drilled over the multiyear length of the JV, Krohn said. \"We haven\u2019t completely vetted all the wells we want to drill or the exact timing on it,\" he said. \"We're still hunting rigs and there is timing on lifting equipment and whatnot that move platform rigs around.\" More JV details to come More information will be provided on the dollar amount of expenditures going forward, \"in pretty short order,\" he added. W&T has had a couple of similar JVs throughout its 40-plus year operating history. Basically, the ventures have allowed W&T to develop a high-return drilling inventory at a faster pace with a greatly reduced outlay of capital. It also maintains flexibility that permit the company to make acquisitions and pay down debt, according to W&T's most recent slide presentation. Most recently W&T undertook a drilling JV in 2018 known as Monza, for 14 US Gulf wells carrying a price tag of $361.4 million. The venture also had potential to upsize the program over time with additional wells. Through the end of Q1 2024, ten wells had been drilled under Monza. The most recent was at two shallow-water tracts off the Louisiana coast at East Cameron Blocks 338\/349. That work resulted in a discovery, the Cota well, which came online in March 2022. According to the terms of that venture, W&T initially received 30% of the net revenues from the drilling program, in exchange for contributing 20% of capital expenses plus associated leases and providing access to available infrastructure. After each investor received a certain return threshold, W&T's share of each well's net revenue increased to 38.4%, W&T presentation slides said. W&T total output flat in Q1 In Q2, W&T reported net sales volumes of 34,900 b\/d of equivalent oil, essentially flat with Q1 and down nearly 6% from the same quarter a year ago. Production in Q2 included 15,187 b\/d of oil, down 1% from Q1 output. Production in Q2 also included 3,670 b\/d of NGLs, down nearly 3% from Q1, and 96,400 Mcf\/d of natural gas, about flat with Q1. Production in Q2 was largely down owing to a gas processor at its Mobile Bay 916 field offshore Alabama. During the quarter W&T negotiated a new agreement with a gas processor and returned the field to production in late May 2024, Krohn said. \"With the return of that field production, four of the six fields recently acquired from Cox [a US Gulf operator] are now in production,\" he said. Also during Q2, the company continued to integrate assets from the $32 million Cox asset acquisition which closed in January after being announced in September 2023. The assets, chiefly six shallow-water producing fields, are all sited in shallow water depths ranging from 25 feet to 265 feet along the US Gulf Continental Shelf, offshore Louisiana. Krohn said W&T continues to \"make good progress integrating these new assets into W&T.\" ","headline":"W&T Offshore nears close of new US Gulf of Mexico drilling joint venture","updatedDate":"2024-08-07T19:15:23.000"},{"Unnamed: 0":258,"body":" Mergers and acquisitions remain a key part of driller Permian Resources growth strategy following the announcement of the Barilla Draw acquisition from Occidental Petroleum in late July, coasting off strong second-quarter results which were driven by improved drilling and completion efficiencies, top executives said Aug. 7. Production exceeded company expectations during the second quarter due to strong drilling and completion efficiencies, strong run times, and steady well performance, resulting in increased oil production at 153,000 b\/d and total production at 339,000 barrels of oil equivalent per day. \"For example, we averaged 1,500 drilled feet per day in over 21 pumping hours per day in Q2, which are both company records for a quarter,\" co-CEO William Hickey said during the company's second-quarter earnings call. \"As a result, we're raising our full year oil guidance for the second consecutive quarter, amounting to a 4,500 barrels of oil per day increase in total when compared to our initial guidance in February.\" Current full year oil production guidance is now at 152 million b\/d while total production is at 325 million boe\/d. That is up more than 60% from its 2023 full-year production of 194,500 boe\/d, largely boosted by the previous Earthstone acquisition and additional support from the latest Barilla Draw acquisition. Strength in drilling and completion efficiencies drove a 13% cost improvement per foot during the quarter, resulting in one of the strongest cash cost quarters to date as workover costs were significantly reduced due to \"low failure rates on downhole lift equipment and a reduction in cost per failure,\" Hickey said. The Midland, Texas based company continues to optimize on recently acquired wells, resulting in an increased full-year turning-in-line guidance by around 15 wells. Looking ahead, the company aims to maintain their rig count and frac count to maintain incremental production growth. Just last week, the company announced that it was buying 27,500 net acres on the Texas side of the Delaware Basin and another 2,000 acres on the New Mexico side from Occidental Petroleum for $817.5 million, the latest in a string of M&A activity for the company. \"This acquisition consists of the Barilla Draw assets in Reeves County and approximately 2,000 net acres offset our existing position in Eddy County,\" co-CEO James Walter said. \"These are assets that we have been keeping an eye on for quite a long time that fit extremely well with our existing footprint.\" The transaction is expected to close by the end of the third quarter with an effective date of July 1, 2024. The land offers more than 200 potential drilling locations and 15,000 boe\/d of production, making it comparable to existing operations in the Permian Basin, the company previously said. The deal also includes a water recycling facility with a capacity of about 25,000 b\/d and more than 100 miles of oil and natural gas pipelines, Walter said. ","headline":"Imrproved efficiencies, continued M&A activity to drive growth for Permian Resources","updatedDate":"2024-08-07T19:07:56.000"},{"Unnamed: 0":259,"body":" Mexico's state oil company Pemex will start exploring an onshore reservoir located only 5 km from Quesqui, one of its most prolific natural gas fields in decades. Quesqui has been one of the main projects that has allowed Pemex to increase its gas output during the current administration of President Andres Manuel Lopez Obrador, who has prioritized quick production at shallow-water and onshore blocks to boost output, neglecting deepwater and unconventional deposits. The Mexican upstream regulator, the National Hydrocarbons Commission, or CNH, on Aug. 6 approved a request from Pemex to drill Ocuapan 401, an exploration well located inside the onshore block operated under contract AE-0143-3M in the Comalcalco region. Ocuapan 401 is located 4.8 km (2.9 miles) from one of the over 30 wells at Quesqui, CNH data shows. The deposits at Ocuapan are divided from the Quesqui reservoir by a salt formation, the CNH said. Pemex expects roughly 6 million barrels of oil equivalent at the site and has committed $53 million to drilling Ocuapan 401, the CNH said. Pemex will begin drilling in early December and it will take roughly 190 days to drill and terminate the well, the CNH said. Quesqui is one of the projects Pemex has identified as a priority to boost its output, key to accomplish its plans to increase its production and stop its reliance on imports from the US. Pemex announced the discovery of Quesqui in 2019 and called it the largest onshore hydrocarbons find in the last 30 years, with roughly 700 million boe. In June, Pemex produced 555 MMcf\/d of gas and 159,000 b\/d of condensate at the site, CNH data shows. ","headline":"Mexico's Pemex to explore deposit adjacent to major onshore gas field Quesqui","updatedDate":"2024-08-07T18:43:11.000"},{"Unnamed: 0":260,"body":" Par Pacific expects third-quarter refinery utilization to top that of Q2, following completion of a major overhaul of its 61,500 b\/d Billings, Montana, refinery, a company executive said Aug. 7. \"I'm pleased to report that Billings executed one of their largest turnarounds on record, successfully meeting all health, safety and environmental targets and ... finishing on schedule and on budget,\" Richard Creamer, Par Pacific's head of refining and logistics, said on the Q2 earnings call. \"The plant restart went well and has met or exceeded all operational objectives. Given the turnaround downtime in Billings, Q2 throughput and production costs were 38,000 barrels per day and $16.18 per barrel,\" he added. In Q3, Par Pacific has planned work on the 10,000 b\/d fluid coker at Billings and expects the refinery's Q3 throughput to range between 55,000 b\/d and 59,000 b\/d. \"The completion of the Billings maintenance positions us to push utilization rates in Q3 in order to meet market demand. Each of our markets is short refined product demand in the summer months, requiring long-haul imports to balance supply and demand,\" CEO Will Monteleone said on the call. During Q2, the Billings US Gulf Coast index averaged $17.93\/b while gross margin capture was 94%, which reflected seasonally strong clean product differentials in the Upper Rockies. \"Looking ahead to the third quarter in Billings, clean product premiums to the Gulf Coast remained strong, trending slightly above Q2 levels quarter-to-date. Cost of crude differentials in the third quarter are expected to increase by approximately $5 per barrel, reflecting tighter heavy and light crude differentials during the second quarter,\" he said. Par Pacific said dynamics in PADD 4 -- the Rockies region -- have largely returned to typical premiums compared with the US Gulf Coast and margins have responded and moved up to mid-cycle levels. \"However, the Southern Rockies has been slightly less attractive, as excess Mid-Continent inventories have pressured markets like Denver and Rapid City,\" he said. Wyoming margin capture falls on increased Midwest barrels At Par Pacific's smaller Rockies refinery -- the 18,000 b\/d refinery in Newcastle, Wyoming -- Q2 margin capture to Par's USGC index was 82%, reflecting softer South Rockies' premiums. Q2 refinery throughput was 19,900 b\/d with guidance for Q3 throughput slightly lower at 19,000 b\/d. \"Local demand continues to strengthen into the third quarter, and clean product spreads to the Gulf Coast have returned to typical summer levels,\" Monteleone said. The Southern Rockies \"has a fair amount of interconnectivity with the Mid-Continent. And I think our observation would be in June and July, while you typically expect to see significant rail-borne imports into the Southern Rockies, ultimately, we didn't see the spreads that you would typically expect in those markets,\" he said. These conditions began to normalize later in July and in August back to higher levels more consistent with \"rail-borne imports into PADD 4 to balance supply and demand during peak season,\" he added. Hawaii moves forward with renewables; Tacoma planned work ends Par Pacific's Hawaii refinery reported Q2 throughput of 81,000 b\/d, with expectations for Q3 rates of between 78,000 b\/d and 82,000 b\/d. Q2 refinery margin capture was exceptional at 135% with utilization at 99% of capacity. \"With Hawaii's consistent throughput and strong catalyst performance, we'll be extending the scheduled 2025 turnaround into 2026,\" Creamer said. Par Pacific's sustainable aviation fuel project at Hawaii remains on track, with expectations the project will come online in the second half of 2025. Par Pacific is converting a diesel hydrotreater to make 61 million gal\/year of renewable fuels with the ability to switch yield to produce 60% SAF for Hawaii's significant air travel market. \"We've completed at least two of the feedstock tanks that will be necessary and, again, are working on and have major bids in hand from critical vendors and providers to begin executing that and are awaiting 1 or 2 critical permits, but I think we feel confident on the time line there to receive and move ahead with those items,\" Monteleone said. The renewable cogen project remains viable and negotiations with Hawaiian Electric continue with completion targeted by end of 2024. \"And so I think from there, we'll have firmer estimates on our engineering and, ultimately, the power purchase agreement time line and can make a final investment decision,\" he added. Earlier this year, Par Pacific cancelled a renewables project at its Tacoma site, which would have used green hydrogen to produce SAF and other renewable fuels, citing the policy backdrop and higher risk due to increased production of SAF and RD reducing the economics and value of credits from Washington's Low Carbon Fuel Standard needed to support the project. In Q2, refinery utilization at the Tacoma refinery was 41,000 b\/d, which included planned work that started in March and ended in April. In Q3, Par Pacific expects Tacoma throughput to be between 38,000 b\/d and 41,000 b\/d. ","headline":" Par Pacific reports softer south Rockies results as Midwest barrels spill into region","updatedDate":"2024-08-07T18:10:56.000"},{"Unnamed: 0":261,"body":" Suncor Energy is well positioned for a strong second half of the year, as the company has completed major planned turnaround at both its upstream and downstream facilities, CEO Rich Kruger said Aug. 7. \u201cFollowing a strong first quarter, the second quarter was about execution and momentum,\u201d Kruger said on a webcast to discuss Suncor\u2019s second-quarter 2024 earnings results. \u201cThe focus was on high quality execution of major upstream and downstream turnaround activities and maintaining momentum in targeted improvement priorities, including operational reliability and cost management.\u201d The \u2018execution\u2019 was of major turnaround activities last quarter of the company\u2019s Base oil sands mine, the Syncrude coker and the Sarnia and Montreal refineries, Kruger said, adding the \u2018momentum\u2019 element is of targeted improvement areas. Suncor typically spends about C$1.2 billion ($873 million) each year in planned maintenance of its oil sands assets in Alberta and Eastern Canada. This includes bitumen mines, steam-assisted gravity drainage plants, upgraders, refineries and offshore oil fields. However, last quarter was one of its largest turnarounds, with a total spending of C$800 million. The company was able to complete the turnaround work with a 10% saving -- or 20 days -- on time, he said. The majority of the planned maintenance work last quarter focused on the 350,000 b\/d Syncrude coker plant of C$450 million, followed by C$370 million on the 350,000 b\/d Base mine plant, Kruger said. \u201cImproving the competitiveness of turnarounds is a major opportunity for us and we are focused on shortening the duration and bring costs down,\u201d Shelley Powell, senior vice president for operational improvement and support services, said on the same webcast. For the current year, Suncor is tracking above the higher end of its guidance of 770,000 b\/d to 810,000 b\/d. The company also plans to maintain its planned capex of about C$6.3 billion to C$6.5 billion and an overall cash operating costs of C$28\/b to C$31\/b, Kruger said. \u201cWe have a second half to go and will play to the final whistle,\u201d he said. Growth plans, record Q2 output Suncor is targeting \u201cacross the board improvements\u201d and an over 100,000 b\/d increase in production by 2026, Kruger said, adding: \u201cWe will go for growth within the existing assets from a wealth of long-term, internal assets. There will be no significant capital directed towards new bitumen development in the next five years.\u201d The company is also one of Canada\u2019s oldest oil sands operators that uses both mining and SAGD technology to extract raw bitumen from its resources in northern Alberta. This includes its legacy Base Mine plant, Firebag, Fort Hills, MacKay River, North Steepbank and Syncrude facilities. Total upstream production last quarter was 770,600 b\/d, up 28,700 b\/d, or 3.8%, compared with 741,900 b\/d in the same quarter the prior year, CFO Kris Smith said on the same webcast. Total oil sands bitumen production increased to 834,400 b\/d in the second quarter of 2024, compared to 814,300 b\/d in the prior year quarter, primarily due to increased working interest in Fort Hills, in addition to record second quarter gross bitumen production at Fort Hills and record quarterly production at Firebag, Smith said. The company\u2019s net synthetic crude oil production was 461,700 b\/d in the second quarter of 2024, representing combined upgrader utilization of 86%, compared to 505,000 b\/d and 92% in the prior year quarter, reflecting higher planned maintenance in the current period and strong upgrader utilizations outside of planned maintenance activities, Smith said. SCO is upgraded raw bitumen that is produced by Syncrude and fetches a premium to the Western Canadian Select heavy crude grade. SCO and WCS prices averaged C$83.65\/b and C$67\/b last quarter. This is compared with C$76.65\/b for SCO and C$58.70\/b for WCS in the same quarter of 2023, according to the earnings release. Oil sands operations cash operating cost last quarter was C$28.45\/b, compared to C$29.10\/b in the prior year quarter, primarily due to increased production volumes, lower operations and maintenance costs, according to the earnings release. Downstream performance Refinery crude throughput increased to 430,500 b\/d and refinery utilization was 92% in the second quarter of 2024, compared with 394,400 b\/d and 85% in the prior year quarter, reflecting strong utilizations at all refineries outside of planned turnaround activities in the current quarter, Kruger said. \u201cOur money-maker Edmonton refinery had a new quarterly utilization record at 108%,\u201d he said. Suncor also saw improved reliability at its Commerce City refinery compared to the prior year quarter. Following the completion of planned turnaround activities, the company\u2019s refineries finished the quarter strong, with average utilization of over 100% through June and into July. Record quarterly refined product sales were of 594,700 \/d in the second quarter of 2024, compared with 547,000 b\/d in the prior year quarter, with the increase primarily due to the company leveraging its extensive domestic sales network and export channels in the current quarter, as well as the impacts of restart activities at the company\u2019s Commerce City refinery in the prior year quarter, Kruger said. Suncor's refinery assets are the 135,000 b\/d plant in Montreal, 85,000 b\/d facility in Sarnia and 146,000 b\/d plant in Edmonton, all in Canada and the 98,000 b\/d plant in Denver in the US. ","headline":"Suncor sees improved H2 oil and gas output, completes major Q2 turnarounds","updatedDate":"2024-08-07T17:58:32.000"},{"Unnamed: 0":262,"body":" Brazilian state-led oil company Petrobras signed a letter of intent with Espirito Santo state government and a leading state industrial trade group to study low-carbon hydrogen production and the potential installation of an offshore carbon-capture utilization and storage, or CCUS, hub in the state, according to the company. \"Petrobras owns infrastructure installed in the state that could be used for CCUS projects, as well as holding ample geologic knowledge about the region's sedimentary basin,\" Petrobras said Aug. 6. According to Petrobras, the company has already started initial planning to install equipment to transport carbon dioxide along the Espirito Santo state coastline and at offshore storage reservoirs. Under terms of the memorandum, Petrobras would operate the hub and be responsible for investments in pipelines, compression stations and injection wells. The long-term goal is to reduce carbon emissions across Espirito Santo state industry and manufacturing, helping the state meet its target of net-zero emissions by 2050, Petrobras said. \"We believe that, through this agreement, we can identify commercial opportunities and generate potential partnerships that are aligned with the strategy to diversify the energy matrix and reduce carbon emissions,\" said Paulo Baraona, president of the Espirito State Federation of Industries, or FINDES. The deal with Espirito Santo state represented the latest project involving technologies related to the global energy transition and reduced greenhouse gas emissions, which was part of a strategy shift implemented after President Luiz Inacio Lula da Silva took office in January 2023. Lula and his Workers' Party, or PT, have tasked Petrobras with being the country's lead investor in renewable energy and transition-related technologies as part of Brazil's efforts to meet emissions targets under the Paris Accords. Petrobras is already one of the world's leading carbon-capture companies, accounting for about 25% of capture in 2023, according to the company. Under the company's $102 billion investment plan for 2024-2028, Petrobras planned investments of about $5.5 billion in low-carbon projects. In February, for example, Petrobras announced a $16.0 million investment in a pilot plant to produce sustainable, low-carbon hydrogen using electrolysis and solar power generated at the Alto Rodrigues Solar Plant in Rio Grande do Norte state. The CCUS project, meanwhile, will also help Espirito Santo state and state-based manufacturers to reduce emissions, according to officials. Espirito Santo state committed to reaching net-zero emissions by 2050 earlier in 2024, when the state launched a carbon-reduction plan. Included in the plan's directives were CCUS projects as part of a policy aimed at creating a green industrial hub, state officials said. \"Espirito Santo has been creating this work flow, implementing public policies that promote renewable energies, consolidating solid partnerships and creating economic opportunities,\" said Felipe Rigoni, Espirito Santo state's secretary for the environment and water resources. ","headline":"Brazil's Petrobras, Espirito Santo state to study potential CCUS, hydrogen hubs","updatedDate":"2024-08-07T17:06:22.000"},{"Unnamed: 0":263,"body":" Argentina\u2019s Energy Secretariat said Aug. 7 it authorized hikes in the prices of biodiesel and ethanol for oil refiners to blend into fuels. The price of biodiesel, which is produced mostly from soybean oil, was increased 1.5% to Pesos 965,554\/mt ($1,031\/mt) in August from the previous price of Pesos 951,285\/mt that took effect in June. The price of corn ethanol was raised 1.5% to Pesos 590.73\/liter (63 cents\/l) from Pesos 582\/l, where it had been since February, while the price of sugarcane ethanol was increased 1.5% to Pesos 644.53\/l (69 cents\/l) from Pesos 635\/l over the same period, the secretariat said. Argentina produces all of its own ethanol and biodiesel to meet 12% and 10% blend requirements, respectively. State-backed YPF has a 55% share of diesel and gasoline sales, trailed by Shell-backed Raizen, BP-backed Pan American Energy and Trafigura. ","headline":"Argentina raises biodiesel, ethanol prices for blending by 1.5% in August","updatedDate":"2024-08-07T16:39:21.000"},{"Unnamed: 0":264,"body":" Bolivian President Luis Arce announced late Aug. 6 tax breaks and other incentives for importing equipment for biodiesel plants and planting feedstock in a bid to increase production and reduce diesel imports after a spate of shortages. The tax breaks and other fiscal and financial incentives are designed to strengthen biodiesel production in the country by spurring private investment, he said in a statement. Arce said a decline in domestic oil production has led to a rise in imports, with the country now reliant on foreign suppliers for 58% of its gasoline and 86% of the diesel. To turn this around, the state-owned oil company YPFB has been stepping up exploration to increase oil production and building new biodiesel production capacity. In March, the company launched operations of a 1,500 b\/d biodiesel plant , the first of two planned facilities that will use castor, palm, soy and other vegetable oils to meet an up to 25% blend in diesel. Bolivia\u2019s crude production tumbled 59% to 21,000 b\/d in April from a peak of 51,100 b\/d in 2014, according to data from the state statistics institute INE. The increased reliance on diesel imports led to shortages in late July and early August because of disruptions in the supply chain. A storm surge delayed the unloading of four ships with a total of 160 million liters of diesel at the Port of Arica in Chile, while low water levels on rivers stalled deliveries from neighboring countries. ","headline":"Bolivia offers tax breaks to import equipment for biodiesel plants following fuel shortages","updatedDate":"2024-08-07T16:29:59.000"},{"Unnamed: 0":265,"body":" The US West Coast oil stock inventory reached a six-week low of 4.296 million barrels in the week ended Aug. 2, down 204,000 barrels from the previous week , Energy Information Administration data released Aug. 7 showed. USWC was the only market region whose inventory decreased compared to the US Atlantic and US Gulf Coast markets. The USAC inventory rose 591,000 barrels, totaling 4.821 million barrels on the week. Stocks were last higher July 12, at 5.299 million barrels. Furthermore, USGC stocks reached a four-week high at 16.293 million barrels, up 332,000 barrels from the previous week, EIA data showed. US fuel oil stocks jumped 841,000 barrels to 26.697 million barrels in the week ended Aug. 2. The inventory was last higher July 12, when stocks stood at 27.586 million barrels. US fuel oil product supplied, an indication of demand, decreased a second consecutive week to 262,000 b\/d, down 71,000 b\/d from the previous week. Platts assessed USGC HSFO at $67.88\/b on Aug. 2, down $2.37 from July 26, when Platts assessed it at $70.25\/b, S&P Global Commodity Insights data showed. Although the USGC HSFO price has moved down on the week, multiple sources said that HSFO supply tightness was due to less product coming from Mexico the last month. In addition, Platts assessed USGC marine fuel 0.5%S at $527\/mt Aug. 2, down $24 from the previous week, Platts data showed. US fuel oil exports stood at 147,000 b\/d in the week ended Aug. 2, up from 138,000 b\/d the previous week. US fuel oil imports totaled 261,000 b\/d, up 172,000 b\/d from the previous week. US imports reached a two-year high, as imports reached 373,000 b\/d July 8, 2022, EIA data showed. ","headline":" West Coast fuel oil stocks hit a six-week low, EIA says","updatedDate":"2024-08-07T15:59:32.000"},{"Unnamed: 0":266,"body":" Iraq's SOMO announced cuts to its official selling prices for September-loading crude oil bound for Europe, according to a pricing notice seen by S&P Global Commodity Insights August 7. For cargoes loading in September and destined for Europe, the Basrah Medium and Basrah Heavy OSPs were lowered to Dated Brent minus $3.90\/b and minus $6.45\/b, respectively. This accounts for a $1.50\/b decrease to both OSPs compared with August. Kirkuk was set at a discount of $1\/b, 10 cents\/b below the August price. September\u2019s Basrah Medium and Basrah Heavy OSPs for European buyers dropped to the lowest level since May after reaching a 2024 high in August, reflecting weakening sour crude fundamentals in the region. European sour crudes, including Norway\u2019s Johan Sverdrup and Kazakhstan Export Blend Crude Oil (KEBCO), weakened in July, according to data from Platts, part of Commodity Insights. Platts last assessed Johan Sverdrup on a CIF basis at a $1.09\/b premium to Forward Dated Brent Aug. 6, down from a $2.45\/b premium on the same day in July. Globally, sour crude supply remains on the tight side as OPEC+ confirmed at their latest ministerial meeting Aug. 1 that production cuts among member countries would remain at their current level until at least October. Flows of Iraqi Kirkuk and Kurdish Blend Test (KBT) crudes into the Mediterranean, via the Turkish port of Ceyhan, remain at a standstill 17 months after the initial suspension of exports. The Iraq-Turkey pipeline was officially closed on March 23, 2023, by Turkey following an international arbitration decision that it had breached a bilateral treaty with Iraq by allowing the KRG to use the pipeline to independently market its crude. The pipeline closure has prevented roughly 450,000 b\/d of medium sour crude, most of it produced in the semi-autonomous Kurdistan region of northern Iraq, from reaching the Mediterranean market. Despite a series of talks between Turkey, the Iraqi federal government and the Kurdistan Regional Government, there appears to so far be no progress in the reopening of the pipeline and the resumption of exports. Looking outside of Europe, SOMO set the September OSPs for Asian buyers at the average of Platts Oman\/Dubai assessments for Basrah Medium crude, up 10 cents\/b from August. The Basrah Heavy OSP was set at a discount of $3\/b to the same average, unchanged on the month. For US buyers of Iraqi crude, Basrah Medium was set at a discount of $1.10\/b to the Argus Sour Crude Index, 45 cents\/b below the August OSP, and Basrah Heavy at a discount of $5.45\/b to the benchmark, 50 cents\/b down on the month. Kirkuk\u2019s September OSP was set 40 cents\/b below August at a premium of $1.25\/b. ","headline":"Iraq\u2019s SOMO cuts official selling prices for September-loading crude oil for Europe","updatedDate":"2024-08-07T15:44:44.000"},{"Unnamed: 0":267,"body":" Nigeria\u2019s Dangote Group is seeking to divest a 12.75% stake in its new 650,000 b\/d refinery as it battles financing concerns, according to Fitch Ratings. Dangote had hoped to secure state backing for the new refinery after starting operations in January, expecting the country\u2019s Nigerian National Petroleum Company to hold a 20% stake in the project. In July, Dangote surprised markets by reporting that NNPC had not provided sufficient funding to secure its 20% stake, and that its ownership would be limited to a 7.2% share. The state oil company was expected to fund its expanded stake through 300,000 b\/d of discounted crude, but has delivered closer to 82,000 b\/d since the refinery's inauguration, according to S&P Global Commodities at Sea data. In an Aug. 5 report, Fitch Ratings said the refinery was courting alternative investors to take on the stake previously earmarked for NNPC. \u201cSince the [NNPC] option has not been exercised, the group plans to divest a 12.75% stake in [Dangote Oil Refining Company] in 2024,\u201d it said. Dangote intends to repay a loan maturing in August with proceeds from the divestment, the ratings agency said, expressing concern over the refiner's ability to sell the stake promptly. \u201cSignificant deterioration in the group\u2019s liquidity\u201d caused Fitch Ratings to downgrade its credit rating for the refining business from AA to B+ and put it on ratings watch negative, a signal of potential future downgrades.\" A representative for Dangote was not available for comment on the report Aug. 7. Rapid deterioration in Nigeria's currency has also contributed to a weaker financial position for Dangote, Fitch Ratings said, reporting foreign exchange losses of Naira 2.7 trillion (around $1.7 billion) for the refiner in 2023. Due to its location in the Lekki Free Zone, the refinery has purchased most of its crude oil in US dollars. Dollar-denominated debts have left Dangote particularly exposed to foreign exchange movements, Fitch Ratings said, anticipating a higher rate of devaluation in 2024. Feedstock challenge, ramp-up plans The Nigerian government took measures to alleviate the refinery's foreign exchange burden in July by allowing it to buy its crude oil from NNPC in naira, though foreign suppliers will continue to demand dollars for crude deliveries. To date, Dangote has sourced over 70% of its crude oil from Nigeria and around 30% from the US, according to S&P Global Commodities at Sea data , while NNPC has committed to supplying around a quarter of its feedstock requirements going forward, according to figures shared by presidential spokesperson Bayo Onanuga July 29. Difficulties in accessing foreign exchange had left PetroChina vessels loaded with WTI Midland crude from the US sitting off the refinery for weeks, Commodity insights has reported previously, while Dangote was recently seen reoffering US crude supply to the market in what it called an effort to pivot to Nigerian grades. Faced with challenging economic headwinds, the refinery has continued to pursue ambitious ramp-up timelines for its operations, with a company source saying Aug. 5 that the plant\u2019s first gasoline supplies were expected \"within a fortnight.\" The source previously said July 31 that the plant had been operating at over half its capacity, processing around 400,000 b\/d. Fitch Ratings said the refinery had operated at around 325,000-375,000 b\/d in H1, anticipating levels to remain around 350,000 b\/d until September. At around 50% capacity, Fitch Ratings sees the refinery\u2019s operations \u201cbarely breaking even\u201d this year. S&P Global Commodity Insights analysts have kept forecasts unchanged for the refinery\u2019s reformer to start up in September, projecting a ramp-up in crude runs after the residue fluid catalytic cracker is expected to start up in 2025. In a July 31 note, Commodity Insights analysts signaled a \"faster-than-anticipated startup\" for the refinery after the recent streaming of its mild hydrocracker, though the plant is not expected to achieve steady state capacity until 2027. ","headline":"Nigeria's Dangote refinery plans to divest 12.75% stake: ratings agency","updatedDate":"2024-08-07T15:32:53.000"},{"Unnamed: 0":268,"body":" Kazakhstan's Ayrau refinery processed 2.911 million mt crude over January-June and produced 2.632 million mt of oil products, it said late Aug. 6. The output included 671,728 mt of 92 RON gasoline and 115,132 mt of 95 RON; 878,963 mt diesel, 95,296 mt jet fuel, 106,021 mt LPG. Its depth or processing was 86.6% with the light products yield accounting for 68.6%. Platts, part of S&P Global Commodity Insights, assessed CPC Blend at $74.90\/b on a CIF Augusta basis on Aug. 6. ","headline":" Kazakhstan's Atyrau processes 2.9 mil mt crude in H1","updatedDate":"2024-08-07T13:13:31.000"},{"Unnamed: 0":269,"body":" Thailand\u2019s IRPC reported a 94% utilization rate in the second quarter of 2024, up from 90% in the same period of 2023 and 85% in the first quarter, the company said in its latest results report Aug. 6. Its utilization in the first half was 89%, down from 91% in H1 2023. The IRPC Rayong refinery processed 201,000 b\/d of crude oil in the second quarter, up 3.6% year on year and surging 10.4% from the first quarter of 2024. It processed 192,000 b\/d of crude oil between January and June, down from 195,000 b\/d in the same period of last year. Its gross refining margin in the second quarter was $2.45\/b, down from $4.12\/b in the second quarter of last year and dropping from $6.56\/b in the first quarter, mainly due to lower spreads of diesel and gasoline products compared with the Dubai crude oil price. The company\u2019s GRM in the first half was $4.38\/b, down from $5.86\/b a year earlier. IRPC\u2019s sales volume for refined products declined to 14.48 million barrels in the second quarter, down 7.7% year on year, mainly due to the lower sales of diesel. The sales volume in the first half also dropped by 8.3% year on year, largely due to the drop in the sales volume of diesel and gasoline IRPC said it put its ultra clean fuel project into commercial operation in April. The UCF project will enhance the efficiency of the refinery plant and improve the quality of its diesel to meet the Euro-5 standard, in alignment with Thai Ministry of Energy's policy that requires diesel distribution to comply with the Euro-5 standard beginning Jan. 1, 2024. This standard reduces the permissible sulfur level to 10 ppm from 50 ppm under Euro 4, IRPC said. ","headline":" Thailand's IRPC reports Q2 utilization of 94%","updatedDate":"2024-08-07T12:40:48.000"},{"Unnamed: 0":270,"body":" Norwegian oil and gas operator DNO reported in an update on Aug. 6 that the gross operated production for Kurdistan in the second quarter of 2024 was 79,783 b\/d, compared with 76,310 b\/d in Q1 and 65 b\/d in Q2 2023. It also said no production was reported for the North Sea over any of these periods. In terms of net entitlement production, DNO in Kurdistan produced 17,167 b\/d in Q2, down from 20,503 b\/d in Q1. The levels were 598 b\/d in Q2 2023. For the North Sea, net entitlement production was 16,321 b\/d in Q2, up from 14,217 b\/d in Q1 and 10,841 b\/d in Q2 2023. Turkey suspended exports of Iraqi crude on March 25 from the port of Iraq-Turkey Pipeline late in March 2023 in response to an international arbitration ruling on March 23, 2023 that upheld Baghdad's sovereignty over oil produced by the Kurdistan Region. As a result, DNO previously said that its 2023 revenues were negatively impacted by the Iraq-Turkey Pipeline shutdown in Kurdistan resulting in reduced Kurdistan production, with volumes sold in the local market at lower realized oil prices than previously achieved through exports. Moreover, DNO said that lower realized oil and gas prices in the North Sea also contributed to the decrease in 2023 revenues. ","headline":"DNO reports higher Q2 crude production in Iraq's Kurdish region","updatedDate":"2024-08-07T12:36:54.000"},{"Unnamed: 0":271,"body":" The tankers market is expected to have a \u201cstrong rate environment\u201d this year while dry-bulk and containers are set to record solid rates for 2024, ADNOC L&S said in statement Aug. 7. The company also reported \"weather delays and deferred progress\u201d in the first quarter on its $975 million contract from ADNOC Offshore awarded in June 2023 to build an artificial island for the Lower Zakum offshore field. The project is under the company\u2019s integrated logistics, which it expects to show revenue growth in the \u201cmid-40% range\u201d in 2024 due to jack-up barge fleet growth, utilization and rates, it said. ADNOC L&S said its marine services business will benefit from contracted operations at petroleum ports and oil spill response services. In 2020, ADNOC awarded ADNOC L&S a 25-year contract to oversee all petroleum ports in Abu Dhabi, including the onshore Jebel Dhanna Ruwais petroleum port and the offshore Das Island, Zirku Island and Mubarraz ports. Revenue in marine services is expected to grow by the \u201cmid-single digit\u201d percent in 2024, the company said. Container shipping rates have climbed this year, with the Platts Container Index at $3,734.24\/FEU on Aug. 6, up from $2,247\/FEU at the end of 2023, according to S&P Global Commodity Insights data. Many crude oil tanker rates have dropped this year to the point that some charterers have said rates can only go higher. Platts, part of Commodity Insights, assessed the Persian Gulf-China VLCC route for a 270,000 mt cargo at $10.11\/mt on Aug. 6, down from $12.69\/mt at the end of 2023. Tankers as part of its shipping business are \u201cdelivering higher-than-expected growth,\u201d ADNOC L&S said in the statement, predicting that overall shipping revenue gains would be in the \u201clow to mid-teens percentage range\u201d this year. Gas carriers will show a \u201cslight reduction\u201d in revenue this year due to sales of older ships but next year through 2027 annual revenue is expected to grow in the \u201cmid 20%s\u201d annually due to the delivery of new LNG carriers, the company said. ","headline":"ADNOC L&S expects \u2018strong rates\u2019 in tankers, dry-bulk, containers in 2024","updatedDate":"2024-08-07T12:18:20.000"},{"Unnamed: 0":272,"body":" Freight rates for dirty tanker voyages loading in West Africa have fallen to their lowest since the start of October, as supply\/demand fundamentals remain firmly in favor of charterers, according to sources. Platts, part of S&P Global Commodity Insights, assessed freight on the 130,000 mt WAF-UK\/Continent route, exclusive of EU Emissions Trading Scheme charges, at $12.34\/mt on Aug. 6 -- its lowest level since Oct. 9. This represents a significant decline from earlier in the year, with rates for this run remaining within a range of $16.50-18.50\/mt from late April until the end of June, before beginning to soften in July. \u201cThings have been quiet -- we\u2019re in a very typical summer market now,\u201d a Europe-based shipbroker said. \u201cThe US Gulf, which is usually the driving force for the West market, is also weak.\u201d A London-based Suezmax broker agreed with this view, also pointing to a saturated tonnage list as another reason for the decline in rates. \u201cThere\u2019s less cargo demand in summer, with countries using their reserves, and barrels have been going unsold recently, so we\u2019re not seeing the demand,\u201d the broker said. According to a second London-based Suezmax broker, although the WAF market may be reaching a bottom, \u201cthe US Gulf and Guyana [markets] aren\u2019t in great shape, and until they pick, things up could be rough.\u201d WAF-UKC Suezmax rates are currently near to levels where the market bottomed in August and September of last year, so it is difficult to predict whether rates will continue falling or remain steady in the short term, a third London-based Suezmax broker said. Sluggish VLCC rates Larger ship sizes have also fared poorly recently, with Platts assessing freight on the 260,000 mt WAF-East route at $18.48\/mt on Aug. 6 -- near to its lowest level since Oct. 10, and down from its latest high of $26.81\/mt on May 21. \u201cIt\u2019s an underwhelming market currently -- speaking to owners, they think the floor has been found, but there\u2019s unlikely to be a major recovery in the short term,\u201d a London-based VLCC broker said. A Europe-based shipowner cited tepid cargo demand levels, in part due to OPEC+ production cuts leading to a decrease in monthly shipments loading in the Persian Gulf, as well as a seasonal lull in heating demand in Europe and the US. \u201c[Charterers] are reluctant to come to the market,\u201d the owner said. Nevertheless, WAF VLCC rates have been prevented from falling even further by owners' reluctance to lock in longer eastbound voyages while the market is in a downturn, opting to fix shorter voyages from the Persian Gulf instead, according to sources. Q4 could herald recovery Despite bearish headwinds looking likely to prevail in the short term, market sources generally expect rates to begin to recover as the fourth quarter approaches. \u201cWe have another few weeks left I think, hopefully things get better soon,\u201d the first London-based broker said, adding that \u201cearnings for owners aren\u2019t currently horrific.\u201d \u201cOil stocks are lower everywhere and prices are lower, so we should start to see demand pick up as we approach the winter,\u201d the Europe-based shipowner said. \u201cI don\u2019t think we\u2019re in a catastrophe -- I think the market will settle down.\u201d ","headline":"WAF crude tanker rates hit 10-month lows amid sluggish inquiry levels","updatedDate":"2024-08-07T12:10:56.000"},{"Unnamed: 0":273,"body":" Senegal's inaugural crude stream Sangomar is scheduled to load four 950,000-barrel cargoes in September, of which three of them are bound for China, according to trading sources, with average loadings for the month set at 126,666 b\/d. The West African market is beginning to turn to the shifting of September-loading barrels, despite lingering August barrels struggling for buyers. While markets such as in Nigeria struggle with length, three of the four September-loading Sangomar cargoes have already secured end-users, one WAF trader said, adding that the three were headed to China. The fourth cargo -- scheduled as a cross-month loader between late September and early October -- is yet to be offered to buyers, sources said. Buying interest from China follows Senegal's first two export cargoes, which were headed to Shell's refineries in the Netherlands and Germany , S&P Global Commodity Insights reported earlier. The crude comes from Woodside's 100,000 b\/d Sangomar project off the coast of Dakar, Senegal's capital, which saw first oil in June, marking a key milestone for the African country\u2019s economy. The production has been stable since the project startup, sources said. Sangomar crude has an API gravity of 31 degrees and contains 1% sulfur, making it comparable with medium sour grades from Oman and Norway's Johan Sverdrup, a key feedstock for European refiners. Beyond Europe and Asia, African refiners including Nigeria's colossal Dangote development have expressed an interest in processing Sangomar crude. Meanwhile, the director of Senegal's only refinery, Mamadou Abib Diop, said July 23 that his plant hopes to process crude from the Woodside project from September, subject to sample tests. Sangomar September-loading program: Country Crude Loading Volume (barrels) Senagal Sangomar Sept. 1-4 950,000 Senagal Sangomar Sept. 10-14 950,000 Senegal Sangomar Sept. 20-24 950,000 Senegal Sangomar Sept. 29-Oct. 1 950,000 Source: Traders ","headline":"Senegal's inaugural crude stream Sangomar to load 3.8 mil barrels in September","updatedDate":"2024-08-07T11:55:22.000"},{"Unnamed: 0":274,"body":" China's vegetable oil imports stood at 645,000 mt in July, up 2.9% from 627,000 mt in June, as buyers took advantage of lower prices to replenish domestic inventories, data from China's General Administration of Customs showed Aug. 7. Total vegetable oil imports in the first seven months of 2024 (January-July) were pegged at 4.13 million mt, down 21% from 5.23 million mt in 2023 at the world world's second-largest vegetable oil buyer, the customs data showed. China's vegetable oil imports have dropped in 2024 as economic uncertainties in the country have subdued demand and kept buyers wary, sources told S&P Global Commodity Insights. The country's vegetable oil inventories at ports rose to 1.99 million mt as of Aug. 2, according to shipping data shared by traders, up 22.8% from 1.62 million mt a month before. In oilseeds, China's soybean imports fell to 58.33 million mt during the January-July period, down 1.3% from the same year-ago period, customs data showed. China is the world's largest importer of soybeans and crushes much of it to make soybean meal, an important animal feed ingredient for its hog herd -- also the largest in the world. However, soybean crush margins have been negative since May and the demand for pork has weakened as consumers tighten their belts, prompting breeders to reduce the herd sizes and feed demand. Given the great yield expectations, smooth planting progress and non-threatening weather conditions in the US, Chinese soybean crushers continued to adopt a wait-and-see approach and remained reluctant to place bids in the market, market sources told Commodity Insights. ","headline":"China's July vegetable oil imports rise 3% on month as buyers replenish domestic stocks","updatedDate":"2024-08-07T11:17:10.000"},{"Unnamed: 0":275,"body":" The Middle East sour crude complex saw cash differentials for key sour crude markers rebound from five-week lows during the Singapore Platts Market on Close assessment process Aug. 7. Platts, part of S&P Global Commodity Insights, assessed October cash Dubai and cash Oman at a premium of 70 cents\/b to same-month Dubai futures at the market close, both up 16 cents\/b on the day. October cash Murban was assessed at a premium of 72 cents\/b to same-month Dubai futures, up 17 cents\/b on the day. During the MOC, 50 October Dubai partials of 25,000 barrels each traded. The sellers were Mitsui, Trafigura, PetroChina, Phillips 66, ExxonMobil, BP, Reliance and Unipec, and the buyers were Gunvor, Vitol and Glencore. No convergences were reached during the MOC. A convergence occurs when 20 partials are traded between two counterparties, resulting in a full 500,000-barrel physical cargo being declared from the seller to the buyer. In the broader market, more producer crude oil official selling prices were seen, with Abu Dhabi National Oil Co. and QatarEnergy issuing their September OSPs over the late Aug. 6 to Aug. 7 session. Unplanned shutdowns were also heard in the Middle East, with Omna's 198,000 b\/d Sohar refinery heard to have gone into shutdown this week with a targeted restart date of Aug. 13, trade sources said. Refinery operator OQ was not immediately available to comment. ","headline":" Middle East sour crude cash differentials rebound","updatedDate":"2024-08-07T11:14:34.000"},{"Unnamed: 0":276,"body":" Crude oil futures were up in the mid-morning London trade Aug. 7 amid improvement in financial markets and as concerns over Middle Eastern supply disruption persisted. At 1103 GMT, the October ICE Brent crude oil futures contract was at $77.34\/b, up 86 cents\/b from the previous settlement at $76.48\/b, while the October WTI Crude Futures contract was at $73.09\/b, up 85 cents\/b from the previous settlement at $72.34\/b. Financial stocks gained with Stoxx Europe 600 Index rising 0.8% and futures on both S&P500 and Nasdaq 100 recovering after the underlying indexes rose by more than 1% at the close on Aug.6. In particular, Bank of Japan (BOJ) strived to reassure the market after the Nikkei rally early in the week with BOJ\u2019s deputy Governor Shinichi Uchida saying that \u201cthe central bank will not hike interest rates when financial markets are unstable,\u201d leading to 1.2% growth in Nikkei average. Recovery in wider financial markets, therefore, expanded to the crude oil markets too with a slight increase in crude futures. \u201cIt is still difficult for the market to feel safe after the Nikkei turmoil,\u201d but the rebound supports the crude futures market at the moment, said Bjarne Schieldrop, chief commodities analyst at Seb Research. Another factor contributing to the rise in crude futures is a higher threat in the Middle Eastern escalation which could potentially disrupt oil supply thus keeping premiums elevated currently. On Aug. 6, the leader of the Iranian-backed Hezbollah group, Hassan Nasrallah, said in a televised speech to mark one week since Fuad Shukr\u2019s killing that the retaliation would be \u201cstrong\u201d and \u201ceffective\u201d. This increases the risks of wider conflict in the Middle East which in turn can disrupt oil flows, thereby supporting the crude futures. ","headline":" Crude oil recovers as financial markets improve","updatedDate":"2024-08-07T10:59:15.000"},{"Unnamed: 0":277,"body":" Africa-focused Tullow Oil\u2019s hydrocarbons production in the first six months of 2024 rose 4% year on year, while higher crude prices pushed up profits, it said Aug. 7. Oil and gas output was slightly ahead of expectations in the period, averaging 63,100 b\/d of oil equivalent across Tullow\u2019s upstream assets in Ghana, Gabon and Ivory Coast, compared with 60,800 boe\/d in the same period last year, the London-listed firm said in its half-year results. The company has kept its full-year production guidance at the lower end of its 62,000-68,000 boe\/d range, it said in the update, with one well at its Jubilee South East project in Ghana underperforming due to water injection issues. The company\u2019s Ghana drilling program is ending six months ahead of deadline. Meanwhile, the smaller TEN field in Ghana exceeded the company\u2019s expectations, CEO Rahul Dhir told S&P Global Commodity Insights in an interview. On the financial side, Tullow posted a post-tax profit of $196 million in the first six months of the year, up from $70 million in the same period last year. The company benefited from higher average crude prices in the first half, boosted by extensions to 5.8 million b\/d of overlapping OPEC+ production cuts and escalation geopolitical tensions in the Middle East following the Israel-Hamas war in October. However, prices have tailed off in recent weeks due to sluggish Chinese demand and sticky inflation. Platts, part of Commodity Insights, last assessed Dated Brent at $76.28\/b on July 6, down from a 2024 high of $93.35\/b on April 12. Richard Miller, Tullow\u2019s CFO, said profits had been boosted by higher production, higher market prices and fact that the company\u2019s legacy hedge program had \u201crolled up\u201d. Tullow said its realized oil price after hedging was $77.70\/b in H1 2024, up from $73.30\/b in H1 2023. The expiration of a number of its legacy hedges will allow the company to benefit from potential oil price increases moving forward, said Dhir, adding that hedges had been a \u201cbig constraint\u201d on the business. The company -- which warned of a potential default in 2020 -- continues to chip away at its debts through \u201csustainable free cash flow generation\u201d and hopes to reach net debt of $1 billion in the near term. In November it signed a $400 million five-year debt deal with trading house Glencore. Tullow\u2019s full-year free cash flow guidance remains unchanged at $200 million-$300 million, the company said, while capex is due to fall in the second half, with an ongoing focus on cost discipline. Business development Dhir said the company is looking to bring its skillset to other parts of West Africa as part of ongoing business development. In April, he made a trip to Equatorial Guinea, meeting with the president\u2019s son and de facto ruler Teodorin Obiang Nguema, according to local media reports. Tullow does not have any assets in the country. \u201cWe see opportunities as the majors are exiting a lot of the mid to late life assets,\u201d Dhir said. \u201cWith a stronger balance sheet, free cash flow generation, good operating track record and long history in Africa, we are well placed to play there successfully.\u201d The company also remains bullish on Kenya, where it is the sole operator of the South Lokichar basin oil project, having seen partners TotalEnergies and Africa Oil Corp. walk away last year. The field development plan was just pushed back six months, and there is no sign of a strategic partner for the asset. \u201cIn my business, patience is a very key skillset,\u201d Dhir said. \u201cIt\u2019s a big resource and whenever it gets developed it think it\u2019s going to have a very good impact on the nation...I just think it takes time.\u201d ","headline":"Tullow sees rise in crude output, profits on-year in H1 2024","updatedDate":"2024-08-07T10:34:18.000"},{"Unnamed: 0":278,"body":" Russia's Black Sea port of Taman handled 1.07 million mt of oil products in June and July, up by 26% from 847,000 mt in the same two-month period in 2023, port operator Oteko said late Aug. 6. For the first half of the year, overall oil products' throughput amounted to more than 3 million mt, the port said, without providing a year-on-year comparison. The main destinations for oil products loaded at Taman over the first half of the year were Turkey, Singapore and Malaysia. In addition oil products were shipped to countries in Africa and the Middle East. The port of Taman is used for exporting oil products, including gasoline, diesel, fuel oil and vacuum gasoil, as well as coal. ","headline":"Russia's Taman port June-July oil products throughput up 26% on year","updatedDate":"2024-08-07T10:19:20.000"},{"Unnamed: 0":279,"body":" Japan's oil products exports rose 4.5% on the week to 2.42 million barrels over July 28-Aug. 3, led by higher outflows of high sulfur fuel oil and kerosene, Petroleum Association of Japan data showed Aug. 7. HSFO exports surged 209.4% on the week to 661,689 barrels over the same period and kerosene exports jumped 86.2% on the week to 240,203 barrels. Meanwhile, gasoline outflows fell 99.7% from the week before to 780 barrels and low sulfur fuel oil exports declined 35.4% to 162,798 barrels. There were no HSFO imports for the 13th straight week and no LSFO inflows for the 18th consecutive week. The PAJ weekly petroleum statistics only cover imports of fuel oil and no other products. Japan oil product exports July 28-Aug 3 Product Kiloliters Barrels Change (W\/W) Gasoline 124 780 -99.7% Naphtha 0 0 N\/A Jet 138,969 874,115 -12.0% Kerosene 38,188 240,203 86.2% Gasoil (Diesel) 76,434 480,770 14.0% A-fuel oil 0 0 N\/A LS fuel oil 25,882 162,798 -35.4% HS fuel oil 105,197 661,689 209.4% Total 384,794 2,420,354 4.5% Source: Petroleum Association of Japan ","headline":" Oil product exports rise 4.5% on week to 2.42 mil barrels","updatedDate":"2024-08-07T10:05:20.000"},{"Unnamed: 0":280,"body":" Petro Rabigh\u2019s refinery on the west coast of Saudi Arabia will be upgraded as shareholders Saudi Aramco and Sumitomo Chemical agreed to a phased waiver of their loans to the company totaling $1.5 billion after Petro Rabigh\u2019s accumulated losses reached 53% of capital as of June 30, according to Aug. 7 statements by all three companies. Aramco will also buy some Petro Rabigh shares from Sumitomo Chemical for $702 million, increasing its stake to 60% and leaving Sumitomo with 15%. Moreover, Aramco will provide another $702 million to Petro Rabigh, for a total aggregate injection of $1.4 billion. Petro Rabigh\u2019s accumulated losses as of June 30 were equal to Riyal 8.871 billion ($2.36 billion). Rabigh Refining and Petrochemical Co., known as Petro Rabigh, processes 400,000 b\/d of Arabian Light crude and produces refined products including fuel oil, diesel, gasoline, kerosene, naphtha and LPG. Its ethane gas processing capacity of 1.6 million mt\/year also produces heavy and light oil, naphtha and kerosene. The refinery, covering 24 million square meters, is located 165 km north of Jeddah on Saudi Arabia\u2019s Red Sea coast. ","headline":" Petro Rabigh to be upgraded after Aramco takes control","updatedDate":"2024-08-07T09:36:06.000"},{"Unnamed: 0":281,"body":" Canada's ShaMaran Petroleum Corp. has closed the acquisition of TAQA Atrush B.V. and the subsequent sale of an indirect interest in Atrush to HKN Energy IV Ltd., announced Jan. 22. The company said the two-step transaction increased its indirect 27.6% stake in the Atrush Block to a 50% working interest (66.67% paying interest) following the sale of an indirect 25% working interest (33.33% paying interest) to HKN Energy IV Ltd. It also said that an affiliate of HKN Energy is now operator of the Atrush Block, and the Kurdistan Regional Government's (KRG) 25% working interest in the Atrush Block has been converted to a carried interest. The company was forced to rely on local sales after the closure of the Iraq-Turkey pipeline since March 25, 2023. The pipeline was closed after an international arbitration court in Paris ruled against Kurdish oil exports in a case filed by Iraq against Turkey. So far, talks between Iraq, the KRG and Turkey have failed to resume oil exports. \"The closing of the Atrush transaction with TAQA and HKN advances our consolidation strategy in Kurdistan,\" ShaMaran President and CEO Garrett Soden said. \"We expect to increase production at Atrush and achieve significant synergies between the adjoining Atrush and Sarsang blocks with HKN as operator of both blocks. We thank TAQA, the Kurdistan Regional Government and HKN for their tireless efforts to close this 'win-win' transaction for all parties.\" ShaMaran is an independent oil and gas company focused on the Kurdistan region of Iraq and indirectly holds an 18% working interest (22.5% paying interest) in the Sarsang Block and a 50% working interest (66.67% paying interest) in the Atrush Block. On May 8, the company said that in the first quarter of 2024, average gross daily oil production from Atrush and Sarsang combined was 57,400 b\/d, down 14% from Q1 2023, while lifting costs were 42% lower than Q1 2023. ","headline":"Canada's ShaMaran closes acquisition of Atrush oil field","updatedDate":"2024-08-07T08:46:07.000"},{"Unnamed: 0":282,"body":" China imported 10.86 million mt, or 14.97 Bcm, of natural gas, including piped gas and LNG, in July, up 5.3% on the year and 4.2% on the month, the General Administration of Customs' preliminary data showed Aug. 7. July's natural gas inflows marked the tenth straight month of year-on-year growth since October 2023, historical GAC data showed. The growth, however, fell short of expectations, according to domestic industrial sources. Natural gas demand from gas-fired power plants -- the primary consumer in the summer -- was lower than anticipated largely due to an ample power supply from hydropower, coal and renewables, which has likely capped natural gas growth demand this summer, the sources said. Separately, trade sources expect LNG imports to be weaker than those of pipeline gas, as the former is more expensive and thus discourages buying interest. According to a forecast published by S&P Global Commodity Insights on July 8, Platts JKM spot prices above $11\/MMBtu would disincentivize non-national oil company buyers from participating in the spot market. At around $12\/MMBtu, domestic trucked LNG remained discounted, and pipeline gas in northern regions is even cheaper. The average cost of natural gas imports was estimated at around $478\/mt, or about $8.93\/MMBtu, in July, up slightly from $8.89\/MMBtu a year earlier but broadly unchanged on the month, Commodity Insights' calculations based on the GAC data showed. Over January-July, China's natural gas imports rose 12.9% on the year to 75.44 million mt, or 104.03 Bcm, the GAC data showed. The average natural gas import cost was estimated at around $489\/mt, or about $9.14\/MMBtu, in the first seven months of 2024, down 11.4% on the year, according to the data. GAC will release detailed LNG import volumes later in the month. ","headline":" July natural gas imports rise 5% on year to 10.9 mil mt","updatedDate":"2024-08-07T07:01:27.000"},{"Unnamed: 0":283,"body":" Crude oil futures were rangebound in midafternoon Asian trade Aug. 7 as prices continued to stabilize from volatility earlier in the week and investors refocused on prevailing market fundamentals. At 2:30 pm Singapore time (0630 GMT), the ICE October Brent futures contract was up 2 cents\/b (0.03%) from the previous close at $76.50\/b, while the NYMEX September light sweet crude contract rose 6 cents\/b (0.08%) at $73.26\/b. Following a volatile start to the week for global financial markets, crude prices found a floor as the Relative Strength Index (RSI) reflected oversold conditions. \"The technical traders were back in action, eyeing the recent downward movements in oil prices as a key buying signal,\" explained SPI Asset Management's managing partner, Stephen Innes. \"[The RSI] suggested to many that oil was 'well overcooked' on the downside, sparking a flurry of activity to capitalize on potential corrections,\" he said. Still, the crude oil futures market remains in a precarious position with potential shifts in demand-supply fundamentals potentially triggering a downside move in prices, analysts warned. \"The price finds itself below the June lows at $76.60\/b, and also below the February lows. Further declines take the price on to the January low at $74.80\/b, and then down to the December low at $72.50\/b,\" said Chris Beauchamp, chief market analyst at IG. For now, investors continued to monitor developments in the Middle East and potential support from US purchases aimed at replenishing their Strategic Petroleum Reserve . Hezbollah has issued a fresh pledge to respond to Israel's killing of its military commander despite international attempts to pursue a diplomatic solution to ongoing tensions. \"Any spike in Middle Eastern tensions could drastically heighten the risk of supply disruptions, effectively leaving oil traders feeling as though they\u2019re perched precariously on a barrel of dynamite,\" SPI's Innes said. On demand, the US Department of Energy announced plans to buy 3.5 million barrels of crude for the SPR for January delivery. The purchases are part of the Biden administration's strategy to continue with solicitations when oil prices fall to $79\/b or less. However, fresh import data from China confirmed an expected fall in crude oil imports in July amid poor refining margins and soft domestic demand. China\u2019s crude oil imports dropped to 10.01 million b\/d (42.34 million mt) in July, the lowest since 9.83 million b\/d in September 2022, data from the General Administration of Customs showed Aug. 7. The volume represented a 3.1% year-on-year decline and a 11.8% reduction from June on a barrels-per-day basis. Dubai crude Dubai crude swaps and intermonth spreads were higher in mid-afternoon Asian trading Aug. 7 from the previous close. The October Dubai swap was pegged at $74.61\/b at 2 pm Singapore time (0600 GMT), up 11 cents\/b (0.15%) from the previous Asian market close. The September-October Dubai swap intermonth spread was pegged at 50 cents\/b, up 8 cents\/b over the same period, and the October-November intermonth spread was pegged at 40 cents\/b, up 10 cents\/b. The October Brent-Dubai exchange of futures for swaps was pegged at $2.00\/b, up 5 cents\/b. ","headline":" Crude stabilizes on technical bounce, supply uncertainty","updatedDate":"2024-08-07T06:33:24.000"},{"Unnamed: 0":284,"body":" Japan's oil product stocks edged up 0.8% on the week to 55.32 million barrels over July 28-Aug. 3, Petroleum Association of Japan data showed Aug. 7. Light distillate stocks were unchanged at 16.9 million barrels on the week, while middle distillate inventories increased 0.9% to 27.75 million barrels over the same period, the data showed. Japan's oil products stocks July 28-Aug. 3: Product Kiloliters Mil barrels Change (W\/W) Change (Y\/Y) Gasoline 1,437,094 9.04 -0.3% 0.4% Naphtha 1,249,405 7.86 0.4% -15.9% Jet 711,192 4.47 -2.3% -17.2% Kerosene 1,770,105 11.13 3.8% -10.6% Gasoil 1,251,558 7.87 -0.4% -3.2% LS marine diesel 308,912 1.94 1.5% 1.2% HS marine diesel 370,099 2.33 -1.9% -6.9% LS fuel oil 627,476 3.95 10.1% -4.4% HS fuel oil 1,068,587 6.72 -2.8% -12.1% Total 8,794,428 55.32 0.8% 48.0% Source: Petroleum Association of Japan ","headline":" Oil product stocks rise 0.8% on week to 55.32 mil barrels","updatedDate":"2024-08-07T06:23:04.000"},{"Unnamed: 0":285,"body":" Japan cut its fuel subsidy for refiners and oil product importers for the fourth consecutive week to Yen 21.40\/liter (14 cents\/liter) for the week of Aug. 8-14, from Yen 27.10\/liter the previous week, the government said Aug. 7. The government, which reviews the subsidy every week, reduced it as the average price of Nikkei Dubai oil fell 4.1% on the week to $78.74\/b over July 30-Aug. 5. The Nikkei Dubai oil price is one of the factors that the government monitors to decide the subsidy. Japanese Prime Minister Fumio Kishida said June 21 that the government has decided to continue its current fuel subsidy policy until the end of 2024 to curb rising retail prices of oil products, including gasoline. In March, the government extended the subsidy program from end-April to support inflation-hit households, without setting a specific deadline. The policy has been extended seven times since its introduction. The national average retail price for regular gasoline fell Yen 0.30\/liter on the week to Yen 174.60\/liter on Aug. 5, marking four straight weeks of decline, according to the Oil Information Center. The gasoil pump price declined Yen 0.30\/liter to Yen 154.30\/liter, and the kerosene pump price decreased Yen 0.10\/liter to Yen 117.10\/liter, according to the center. Without the subsidy, the retail price of gasoline would have risen Yen 27.30\/liter to Yen 201.90\/liter on Aug. 5, the Ministry of Economy, Trade and Industry said Aug. 7. The subsidy reduced gasoil and kerosene prices by Yen 27.30\/liter and Yen 27.10\/liter, respectively, the ministry added. Refiners use the subsidy to curb increases in weekly wholesale prices of oil products, while trading houses deduct the subsidy from selling prices of imported oil products. ","headline":"Japan cuts Aug 8-14 fuel subsidy by 21% as crude prices drop","updatedDate":"2024-08-07T05:48:26.000"},{"Unnamed: 0":286,"body":" Japan's refinery run rates rose to 66.6% in the week to Aug. 3, from 63.6% the previous week, on higher crude throughput, the Petroleum Association of Japan said Aug. 7. The country's crude throughput was up 4.7% over the same period at 2.07 million b\/d. Seven refining units, with a total production capacity of 790,200 b\/d, were offline across Japan as of Aug. 3 -- four on planned maintenance, two following technical issues and another due to operational adjustments -- based on information compiled by S&P Global Commodity Insights. The refinery capacity outage accounted for 25.4% of the country's total installed refining capacity of 3.11 million b\/d, the data showed. The offline capacity increased on the week from 774,200 b\/d after ENEOS, Japan's largest refiner, restarted the sole 129,000-b\/d crude distillation unit at its Chiba refinery in Tokyo Bay on July 28 after completing unplanned works, while the company shut the sole 145,000-b\/d CDU at its Sendai refinery in northeast Japan on Aug. 1 due to technical issues, Commodity Insights previously reported. Japan's crude stocks fell 1% on the week and 16.8% on the year to 66.11 million barrels as of Aug. 3, Commodity Insights data showed. Unfinished oil product stocks, or oil processed at refineries, totaled 36.64 million barrels Aug. 3, down 2.5% on the week and 10.6% on the year. ","headline":" Refinery runs rise to 67% over July 28-Aug 3 on higher crude throughput","updatedDate":"2024-08-07T05:03:43.000"},{"Unnamed: 0":287,"body":" The key Singapore reforming spread -- the difference between Singapore 92 RON gasoline and Singapore naphtha derivative, which is of a particular interest to gasoline blenders -- narrowed to an over two-year low of $12.60\/b at the Aug. 5 Asian close, as weakness in gasoline prices outpaced that of naphtha. The spread edged higher to $12.75\/b subsequently at the Aug. 6 Asian close. The spread was last lower March 3, 2022 at $9.85\/b, S&P Global Commodity Insights data showed. The reforming spread has been on a declining trajectory since May due to weak demand despite the US driving season. More recently, the collapse of the reforming spread was largely attributed to the drop in crude values, which caused the prices of gasoline and naphtha to fall. Crude oil prices are expected to remain subdued due to recession fears, driven by a weaker-than-expected US employment report and steep selloffs in global financial markets, despite geopolitical supply concerns following the assassination of Hamas militant leader on Iranian soil. Meanwhile, the Asian naphtha market is anticipated to remain under pressure due to thin trading activity and slower demand. Tracking lower crude prices, the benchmark C+F Japan naphtha prices fell $16.50.mt on the day to $658\/mt at the Aug. 5 Asian close, but marginally rebounded to $664\/mt at the Aug. 6 Asian close as crude values remained rangebound, Commodity Insights data showed. \"Gasoline-naphtha [spread] is shrinking; not hearing strong demand from the region,\" an industry source said. Another trader echoed similar sentiments, saying, \"Gasoline demand is dying in Asia.\" \"[The] general macroenvironment is not friendly for gasoline blending, although there should be a base demand to be supplied to the market,\" a second trader said, adding that a lower reforming spread suggests lesser profit for blenders. Gasoline demand to remain weak The Asian gasoline complex is expected to remain weak, driven by anticipation of fresh supplies entering the region and the tapering of the driving season in the US, sources said. Platts assessed the front-month September FOB Singapore 92 RON gasoline swap down 5.56% on the week at $83.25\/b at the Aug. 6 Asian close, Commodity Insights data showed. Some trade sources indicate a potential bearishness in Asian gasoline prices in the near term, due to refineries returning for better margins and expectations of fresh resupplies heading into the eastern markets alongside China's export quota in the third quarter. There have been reports of cargoes being transported from Europe and the Arab Gulf to Singapore, but market participants were not optimistic about the cargoes being fulfilled. Market participants expect weaker US demand as the driving season winds down, leading to lower gasoline prices, with refinery maintenance anticipated in the post-summer season, a Singapore-based trader said. ","headline":"Asian reforming spread hits over two-year low as gasoline prices lag naphtha","updatedDate":"2024-08-07T04:07:19.000"},{"Unnamed: 0":288,"body":" The FOB Singapore 500 ppm sulfur gasoil cash differential has weakened in August as demand from Indonesia tapers following the resumption of operations at state-owned Pertamina\u2019s Balikpapan refinery No. 4 crude distillation unit in East Kalimantan. Platts, part of S&P Global Commodity Insights, assessed FOB Singapore 500 ppm sulfur gasoil cargoes against the Mean of Platts Singapore gasoil assessment at a 10-week low of minus $1.70\/b at the Asian close Aug. 6. The differential was last weaker at minus $1.74\/b on May 27. During the Asian Platts Market on Close assessment process Aug. 7, Chevron sold 150,000 barrels of medium sulfur gasoil loading from the Straits over Aug. 21-25. The trade was assessed at a discount of minus $2.49\/b against the MOPS gasoil assessment, after accounting for deemed pricing. \u201c[The reason is] less demand from Indonesia. That\u2019s all,\u201d a regional middle distillates trader said. The 360,000 b\/d CDU No. 4 at Pertamina's Balikpapan refinery resumed operations July 26 following a fire May 25. Indonesia imported 554,864 mt of gasoil from Singapore in July, rising from 519,933 mt in June and from 345,807 mt in May, Enterprise Singapore data showed. The data does not provide a breakdown by gasoil sulfur grades. \u201cIt is not just Pertamina that is buying medium and high sulfur gasoil cargoes. There are other traders in Indonesia that also buy these grades, and once Balikpapan is up, demand from August should be much lower,\u201d a regional gasoil trader said. Pertamina has sought 50,000 barrels of 0.005%S diesel loading from the Straits (Singapore\/Malaysia) over Aug. 18-20, or delivery to Plumpang, Jakarta over Aug. 22-24, at the lower end of either the Aug. 9-31 average of MOPS Singapore 0.005%S gasoil assessment or Argus Singapore gasoil 0.005% sulfur assessment, FOB\/CFR. The tender closes Aug. 7, with validity until Aug. 8. The annual South China Sea fishing ban imposed by China, from May until Sept. 16 this year, to protect marine resources also leads to lower 500 ppm sulfur gasoil demand as the fuel is used to power motorized fishing boats. Vietnam -- a key importing center of the medium sulfur grade, has denounced China's annual fishing ban, citing violation of the Southeast Asian nation's sovereign rights and jurisdiction in Vietnamese waters, according to local media reports. The Philippines has also protested the ban on similar grounds. \u201cUsually demand for 500 ppm [sulfur gasoil] is weaker during the fishing ban but demand from Indonesia provided support in June and July,\u201d an industry source said. In comparison, the cash differential for benchmark FOB Singapore 10 ppm sulfur gasoil cargoes against the MOPS gasoil assessment strengthened on the day to minus 31 cents\/b on Aug. 6, from minus 33 cents\/b on Aug. 5. The differential was unchanged on the week and weaker compared with July\u2019s average of minus 27 cents\/b. The Platts FOB Singapore 10-500 ppm sulfur gasoil spread widened 22 cents\/b on the day to $1.39\/b at the Asian close Aug. 6. The spread was last wider at $1.43\/b on May 29, Platts data showed. The Asian ultra low sulfur diesel complex has been largely stable, supported by pockets of regional demand, though trade participants have been cautious about a potential downside due to seasonal weakness. ","headline":"Asia medium sulfur gasoil differential weakens as Indonesia demand tapers","updatedDate":"2024-08-07T03:24:48.000"},{"Unnamed: 0":289,"body":" QatarEnergy raised the September official selling price differentials for its Land and Marine crudes by 45-75 cents\/b from August, according to a notice on its website Aug. 7. The September OSP differential for Qatar Marine was set at plus 60 cents\/b against the average Platts Dubai crude assessments in the month of loading, increasing from plus 15 cents\/b for August. Platts is part of S&P Global Commodity Insights. The September Qatar Land OSP differential was set at plus 35 cents\/b against the average Platts Dubai crude assessments in the month of loading, rising from minus 40 cents\/b for August. Qatar crude oil official selling prices: (Unit: $\/b) Grade Basis July August September Change Qatar Land Platts Dubai 0.35 -0.40 0.35 0.75 Qatar Marine Platts Dubai 1.10 0.15 0.60 0.45 Source: QatarEnergy website ","headline":"QatarEnergy raises Sep Land, Marine crude OSPs by 45-75 cents\/b from Aug","updatedDate":"2024-08-07T02:38:17.000"},{"Unnamed: 0":290,"body":" Abu Dhabi National Oil Co. set the September official selling price for its flagship Murban crude oil $1.28\/b higher on the month at $83.80\/b, the company said in a late Aug. 6 notice. The September OSP differential for Umm Lulu was set at a premium of 20 cents\/b to the Murban OSP, equating to $84.00\/b. The September differential for Das Blend crude was set at a discount of 80 cents\/b to the Murban OSP, equating to $83.00\/b, while the September differential for Upper Zakum crude was set at a premium of 5 cents\/b to the Murban OSP, equating to $83.85\/b. In May 2021, ADNOC partnered with the Intercontinental Exchange to launch an Abu Dhabi-based exchange called ICE Futures Abu Dhabi, or IFAD, on which the Murban futures contract and related cash-settled derivatives are traded. ADNOC OSPs for its Murban exports are based on the monthly average of IFAD Murban Singapore marker first-line futures, which go to delivery two months ahead of the month of trade. The shipping terms are FOB Abu Dhabi ports and Fujairah loading terminals. ADNOC's crude oil official selling prices: (Unit: $\/b) Grade July August September Murban 83.93 82.52 83.80 Umm Lulu 84.13 82.67 84.00 Das Blend 83.28 81.77 83.00 Upper Zakum 84.23 82.52 83.85 Differential to Murban July August September Umm Lulu 0.20 0.15 0.20 Das Blend -0.65 -0.75 -0.80 Upper Zakum 0.30 0.00 0.05 Source: ADNOC ","headline":"ADNOC sets Murban Sep OSP $1.28\/b higher on month at $83.80\/b","updatedDate":"2024-08-07T01:26:50.000"},{"Unnamed: 0":291,"body":" US oil and natural gas company Diamondback Energy is continuing to push its well drilling lengths toward the four-mile mark and performing a greater number of well completions while it awaits the closure of a pending $26 billion merger with Endeavor Energy later this year, the company's top executive said Aug. 6. The Midland, Texas-based company continues to do \"more with less\" and become more operationally efficient each quarter, Diamondback CEO Travis Stice said during its company's second-quarter earnings conference call. \"At the beginning of the year we were anticipating a rig would drill 24 wells a year, and now we are modeling one rig drilling at least 26 wells per year,\" Stice said. Drilled wells 10% faster in Q2 \"On average, we are drilling wells approximately 10% faster than at the beginning of the year, primarily due to bit and bottom hole assembly improvements,\" he said. \"In fact, we set a new record [in Q2] on one of our wells in the Midland Basin, drilling over 20,000 feet with a single drill bit.\" The company set the new record on a Midland Basin well in the eastern Permian Basin, drilling a lateral or horizontal well sideways more than 20,000 feet -- or nearly four miles -- with a single bit run, he said. Diamondback achieved a similar efficiency gain on the well completions side; the company previously signaled it would complete 80 wells per year per crew, but currently it is completing 100 wells per crew per year, Stice said. As the fourth-quarter merger close with Endeavor approaches later in the third or fourth quarters, Stice said he \"fully anticipate[s]\" both companies' operations will continue to push efficiencies. When the merger was announced in mid-February, Diamondback executives talked about the ability to apply Diamondback's relatively low drilling and completion costs on a larger asset base, the CEO said. Diamondback and Endeavor -- by the numbers: Diamondback Endeavor Diamondback post-merger Enterprise value $36.2 billion $26 billion $62.2 billion Q4 2023 production 273,000 b\/d of oil; 463,000 boe\/d 195,000 b\/d of oil; 353,000 boe\/d 468,000 b\/d of oil; 816,000 boe\/d Net Midland acreage 350,000 acres 344,000 acres 694,000 acres Total Permian acreage 494,000 acres 344,000 acres 838,000 acres Gross core locations (at sub-$40\/boe) 3,800 2,300 6,100 Source: Diamondback Energy Costs now 'significantly below' early 2024 level \"I'm pleased to say today [the company's costs are] significantly below where we were in February,\" he said. \"So that \u2026 supercharges the delivery of the synergies that we were talking about.\" Those synergies are expected to total $550 million per year and total several billion dollars over the next decade. The efficiency gains already achieved are permanent and are not going to disappear even in the face of inflation or deflation of service costs, but rather will be further refined over time, Diamondback's President and Chief Financial Officer Kaes Van't Hof said. In the second quarter, Diamondback's total oil, gas and NGL production grew 3% to 474,700 b\/d of oil equivalent, up 3% from three months earlier, while its oil production grew 1% to 276,100 b\/d of oil in the same time frame. Gas output in the second quarter of 2024 averaged 564,000 Mcf\/d, up about 1% from three months earlier. In July, the company reduced drilling activity from 12 rigs to 10 and lowered its hydraulic fracturing fleet count from four SimulFrac crews to three, while raising full-year production guidance. SimulFrac is a technique used to complete wells where two wells are simultaneously completed instead of just one. Some companies are also experimenting with TrimulFrac, which allows hydraulic fracturing of three wells at one time. Diamondback's oil production target for 2024 was raised in the second quarter and is now at a range of 273,000 b\/d to 276,000 b\/d, up from 270,000 b\/d to 275,000 b\/d, reflecting accelerated first-half 2024 activity and year-to-date positive well performance, Diamondback said in a statement. The new 2024 oil production target would mean growth of 4% to 5% year on year. ","headline":"Diamondback Energy keeps pushing well drilling, completion efficiencies in Q2","updatedDate":"2024-08-06T21:00:14.000"},{"Unnamed: 0":292,"body":" Anglo-Turkish independent oil and gas company Genel Energy said Aug. 6 that oil production from the Tawke field was 19,510 b\/d in the first half of 2024, compared with 13,440 b\/d in the first half of 2023. In its first-half results report it also said domestic sale price averaged $34\/b for the period compared with $35\/b in 2023, with the last two months priced at $37\/b. Paul Weir, Chief Executive of Genel, said that cash generative production continues from their flagship Tawke license, where domestic sales demand has shown resilient consistency in the past 6 months and a recent price improvement. Moreover, Genel Energy said they have closed down unprofitable licenses in the Kurdistan Region of Iraq and minimized their in-country footprint. The export of Kurdish crude stopped since Turkey closed the Iraq-Turkey pipeline on March 25 last year after an international arbitration court ruled that Turkey violated a bilateral agreement with Baghdad by allowing independent Kurdish export sales. Genel Energy said that when exports restart, they could deliver over $100 million of entitlement-free cash flow to Genel per year, more than double the current level. However, the company said that so far there is no breakthrough in the political impasse between Baghdad, Erbil and Ankara to resume oil exports. Genel Energy added that it will continue to lobby regional and federal governments to break the current political impasse so that international exports of Kurdistan oil can resume in a manner that properly rewards the international oil companies that have chosen to invest in Kurdistan. In 2021 Genel Energy took the Kurdistan Regional Government (KRG) to an international arbitration court in the UK after years of failure to agree on a plan to develop the Miran and Bina Bawi gas fields. The international arbitration case has now been concluded, with closing submissions exchanged in May and reply reports exchanged in June. Genel Energy said it is now for the panel to deliberate and make an award, likely before the end of the year. ","headline":"Genel Energy\u2019s oil production from Tawke field increases to 19,510 b\/d in 1H 2024","updatedDate":"2024-08-06T20:55:17.000"},{"Unnamed: 0":293,"body":" Record production from the Rocky Mountain and Mid-Continent regions lifted Oneok's natural gas and NGLs volumes during the second quarter, extending a similar trend seen last quarter despite fluctuating rig counts that have declined on average since the start of the year, with growth driven primarily by longer laterals and higher well performance, executives said Aug. 6. The Tulsa-based service provider reported a 9% quarterly increase in natural gas processing volumes in the Rocky Mountain region, with average processed volumes hitting a record 1.63 Bcf\/d during the second quarter compared to 1.49 Bcf\/d in the first quarter. Year-over-year, volumes increased 10%. Oneok includes Bakken volumes in its Rocky Mountain region data. Looking ahead, the company maintained its full-year guidance for Rocky Mountain processing volumes to rise to 1.52-1.75 Bcf\/d in 2024. \"As we look to the remainder of the year, we are reaffirming our volume guidance due to the benefits we're seeing from the drilling of longer laterals and higher well performance on traditional laterals without the need for as many well connects,\" Sheridan Swords, executive vice president of Oneok's commercial liquids and natural gas gathering and processing said during the company's second-quarter earnings call. Bakken production averaged at 2.6 Bcf\/d the week to Aug. 5, the producing area's strongest week in four weeks, S&P Global Commodity Insights data showed. Production averaged at 2.5 Bcf\/d through July, slightly lower than first quarter averages between 2.7 Bcf\/d to 2.8 Bcf\/d. The Bakken had 40 rigs by July 24, the highest count seen since late April of this year and three higher than the same week last year, Commodity Insights data shows. In the Mid-continent region, processed natural gas volumes averaged at 701 Bcf\/d compared to last quarter\u2019s 702 Bcf\/d, with six of 35 rigs currently operating on their acreage. The company connected 24 wells in the second quarter and expects to complete 60 to 70 well connections over the course of the full year. Currently, there are 40 rigs in the Williston Basin with more than 20 on Oneok's dedicated acreage, Swords said. The company connected 106 wells during Q2 in the gas play and expects to connect between 530 to 600 wells in 2024. \"With current commodity prices, we expect producers to continue concentrating activity in the oilier and NGL-rich areas in the region,\" Swords said. \"And as natural gas prices strengthen towards the remainder of the year, we could see rig activity increase in the gassier regions.\" Additionally, in what executives called a \"pleasant surprise,\" Oneok's processed volumes have tripled between 2014 and 2023, despite 40% fewer well connections over the same period. The unique relationship is being driven by longer laterals, according to the company, which claims that there are fewer well connections needed per longer lateral. As the company relies more on three-mile laterals, 10% fewer wells are needed to connect the same lateral footage, the company claims. In example, the company had 581 well connections in 2023 while average length per well in miles was at 2.12. In 2024, well connections have decreased to 565, while average length per well has increased to 2.25 miles. It estimates 30% of laterals in 2024 will be three miles, up from 13% in 2023 and 7% in 2022. Ethane recovery Oneok saw a 17% quarterly increase in NGLs throughput in the Rocky Mountain region to 420,000 b\/d in the second quarter, driven by increased propane plus volumes. The Midcontinent region increased 16% on the quarter to 556,000 b\/d. The company expects modest recovery levels to continue in the Rocky Mountain region throughout 2024 but noted that while the Permian was in \"full recovery,\" the Midcontinent region was in rejection, Swords said. \"Ethane is going to be volatile [and] as we said, it's going to be dependent on natural gas prices. That's why we've always put just a very modest amount of ethane recovery into our guidance as we look forward,\" she added. \"We do see that the petrochemicals are having a very wide spread -- ethane and ethylene, it's very wide right now, so they're wanting to run at high utilization rates,\" Swords said. \"So we anticipate that we will see some recovery in the ethane markets as we finish the remainder of the year.\" Oneok will have greater ability to incentivize ethane recovery in the Bakken when the 135,000 b\/d Elk Creek expansion begins service, which is on track to be operational by the first quarter of 2025. The project would increase Oneok's total NGL capacity from the basin to 575,000 b\/d. Oil and products volumes Oneok shipped 1.5 million b\/d of refined products in the first quarter, 13% higher than in the last quarter when volumes shipped were at 1.4 million b\/d. Crude oil shipments fell in Q2 to 731,000 b\/d from 747,000 b\/d in the first quarter. Additionally, the company announced a 230-mile expansion to its refined product system in Kansas to include the Denver International Airport, with a 35,000 b\/d increase to total capacity. The expansion is expected to be complete by midyear 2026. Following a \"successful\" open season, the additional capacity is fully subscribed with Oneok to go out for a subsequent open season \"if demand continues to grow,\" Swords said. ","headline":"Longer laterals and higher well performance drive Rocky Mountain production: Oneok","updatedDate":"2024-08-06T20:48:52.000"},{"Unnamed: 0":294,"body":" The US Department of Energy plans to buy 3.5 million barrels of crude for the Strategic Petroleum Reserve, executing the Biden administration\u2019s strategy to continue with solicitations when oil prices fall to $79\/b or less, the DOE said Aug. 6. The announcement comes just a week after the DOE finalized a purchase of 4.65 million barrels of sour crude that marked the completion of the administration\u2019s promise to return the 180 million barrels released from the emergency crude stockpile in 2022 to combat energy price hikes spurred by Russia\u2019s invasion of Ukraine. \u201cThese continued purchases underpin the president\u2019s commitment to safeguard and replenish this critical energy security asset,\u201d the DOE said in a statement announcing two new solicitations. The first solicitation seeks up to 1.5 million barrels of sour crude for delivery in January 2025 to the recently renovated Bayou Choctaw site in Louisiana. Bids of no higher than $79.99\/b and of at least 250,000 barrels are due by 11 am CT Aug. 13, and contracts will be awarded no later than Aug. 29, according to the solicitation. The DOE said a second solicitation will be issued Aug. 12 for the purchase of about 2 million barrels. Those barrels will also be for January 2025 delivery but will go to the Bryan Mound site in Texas which is reopening after significant construction tied to the maintenance of the SPR. Bids will be due by 11 am CT Aug. 20. Crude volumes at the SPR stood at 375.1 million barrels the week ended July 26, compared with the 638 million barrels of crude when President Joe Biden took office in January 2021, according to the US Energy Information Administration. The Biden administration\u2019s three-part SPR replenishment strategy has centered on \u201cdirect purchases with revenues from emergency sales, exchange returns that include a premium of oil above the volume delivered, and securing legislative solutions that avoid unnecessary sales unrelated to supply disruptions,\u201d the DOE said. Direct purchases The new solicitations build on direct purchases made in 2023 and 2024 totaling more than 43 million barrels for an average price of $77\/b. \u201cDOE continues to aim for $79\/b or less, significantly lower than the average of about $95\/b DOE received for 2022 emergency SPR sales,\u201d the department said. \u201cDOE will continue to evaluate options to refill the SPR while securing a good deal for taxpayers, taking into account planned exchange returns and market developments.\u201d Analysts at ClearView Energy Partners characterized the solicitations as \u201can opportunistic response to recent WTI price weakness.\u201d NYMEX September WTI settled 58 cents lower at $72.94\/b Aug. 5 as traders weighed recession fears and downward pressure from steep selloffs in global financial markets against mounting geopolitical risks to supply. Crude futures edged higher Aug. 6 -- but only to $73.20\/b -- on expectations of supply disruptions as Libya\u2019s largest oilfield was taken offline for political reasons and market concerns grew over a possible Iranian retaliatory attack on Israel. \u201cOur suspicion is that the White House has little interest in generating market-moving demand at a time when gasoline prices have been retreating and the presidential campaign of Vice President Kamala Harris has been picking up,\u201d according to a ClearView research note. \u201cThat said, to the extent that front-loading the buybacks may push price impacts down the forward curve, we would not be surprised to see further purchase announcements in coming weeks (again, if price weakness persists).\u201d However, continued SPR purchases are likely to run into budgetary constraints that could put an end to them by the second quarter of 2025. ClearView estimates that about $1.38 billion remains in the DOE\u2019s SPR coffers. If the department accepts offers for the full 3.5 million barrels at the threshold price of $79.99\/b, the $1.1 billion left in the SPR account would be depleted in roughly four months, assuming 3.5 million barrels\/month of purchases. \u201cWe do not think the current Congress is likely to provide additional appropriations for SPR procurement,\u201d ClearView said. ","headline":"US DOE seeks to buy 3.5 million barrels of crude for delivery to SPR in January 2025","updatedDate":"2024-08-06T20:36:55.000"},{"Unnamed: 0":295,"body":" The FPSO Maria Quiteria floating production, storage and offloading vessel arrived offshore Brazil in recent days amid efforts by state-led oil company Petrobras to accelerate investments and boost oil and natural gas output. The vessel, which has installed capacity to produce 100,000 b\/d and process up to 5 million cu m\/d, is expected to start production from the Jubarte field in the so-called Parque das Baleias, or Whales Park, complex of offshore fields in the northern portion of the Campos Basin in the second half of 2024, Petrobras said Aug. 5. The FPSO, which can also inject up to 330,000 b\/d of water, will be connected to eight production and eight injection wells. Jubarte, which produces from both subsalt wells and wells above the salt layer, pumped 128,080 b\/d of oil equivalent in June, according to the latest production report from Brazil's National Petroleum Agency, or ANP. Petrobras CEO Magda Chambriard said in June that Petrobras would bring forward the installation of the FPSO Maria Quiteria amid criticisms by Brazil's government about the company's lackluster investment spending in the first half of 2024. Brazilian President Luiz Inacio Lula da Silva and his Workers' Party, or PT, favor a state-led model for economic development that includes heavy domestic investment by mixed-capital and state-controlled entities such as Petrobras. Under Petrobras' $102 billion investment plan for 2024-2028, the FPSO Maria Quiteria was originally scheduled to start production in the first quarter of 2025. The FPSO Maria Quiteria also represents a significant advance in emissions reduction from floating production units, which should reduce greenhouse gas emissions from Jubarte by about 24%, Petrobras said. The FPSO includes a combined cycle generator capable of producing about 100 MW, which is enough electricity to power a city of 230,000. The installation will be one of two FPSOs scheduled for 2024, which represented a slowdown from the five FPSOs that started production between December 2022-December 2023, according to Petrobras. In addition to the FPSO Maria Quiteria, Petrobras plans to install the FPSO Marechal de Duque de Caxias at the Mero field in the Libra production sharing area in the second half of 2024. The floating production unit will be third to start production at Mero, with the FPSO Sepetiba and FPSO Guanabara already in operation. The FPSO Sepetiba pumped first oil on Dec. 31, 2023, while the FPSO Guanabara started operations in April 2022. Like the FPSO Marechal Duque de Caxias, the two FPSOs also have installed capacity to produce 180,000 b\/d and process up to 12 million cu m\/d. The FPSO Marechal Duque de Caxias also represents the first major use of Petrobras' HISEP system, which will be used to separate oil, natural gas and carbon dioxide gas on the seabed, according to Petrobras. The carbon dioxide and natural gas will be reinjected into the Mero field reservoirs in addition to other carbon-capture measures aimed at reducing emissions. Petrobras plans to fully implement the HISEP system starting in 2028, the company said. The company plans to install three FPSOs in 2025, according to the Petrobras 2024-2028 investment plan. That includes the FPSO Almirante Tamandare and the FPSO P-78 at the Buzios field, as well as the FPSO Alexandre de Gusmao at the Mero field. The FPSO Almirante Tamandare can pump up to 225,000 b\/d, while the FPSOs P-78 and Alexandre de Gusmao will each have installed capacity to produce 180,000 b\/d. ","headline":"FPSO Maria Quiteria arrives offshore Brazil, to reduce emissions: Petrobras","updatedDate":"2024-08-06T19:42:18.000"},{"Unnamed: 0":296,"body":" Crude futures edged higher Aug. 6 on the back of expectations of a disruption in supply from the sudden reduction in Libya\u2019s Sharara oilfield production and concerns of further escalation between Israel and Iran. NYMEX September WTI settled up 26 cents at $73.20\/b and ICE October Brent climbed 18 cents higher to settle at $76.48\/b. On Aug. 5, Libya\u2019s largest oilfield was taken completely offline on the direction of Saddam Haftar, the son of military strongman Khalifa Haftar, following news of a Spanish arrest warrant being issued against him, according to sources. Output at the Sharara Field, which had been producing roughly 250,000 b\/d of oil, initially fell to around 100,000 b\/d after protesters against the warrant entered the operations room Aug. 4, sources told S&P Global Commodity Insights, before ceasing by 4 pm Aug. 5. The reduction in Libya\u2019s oil production adds to market concerns about Middle Eastern oil supply caused by the escalation on the Israel-Gaza front. On Aug. 6, the US President met his senior national security team as concerns grew of a possible Iranian retaliatory attack on Israel. A day earlier, US Secretary of State Antony Blinken reportedly told his G7 counterparts that Iran and Hezbollah could attack Israel within 24 to 48 hours. \"Market pricing in energy markets is also pointing to some dislocations, with energy supply risk premia disregarding the substantial and imminent geopolitical risk associated with Iran. An escalation in the conflict can now asymmetrically lead to more upside momentum with CTA short positions now well populated,\" TD Securities Senior Commodity Strategist Daniel Ghali said. NYMEX September RBOB dipped 74 points to $2.3262\/gal and September ULSD declined 28 points to $2.2958\/gal. Global financial markets, meanwhile, showed signs of stabilizing after a volatile start to the week that saw a broad move away from risk assets such as oil futures. \"It seems we've caught a brief respite as some of the falling knives have finally hit the floor,\" said SPI Asset Management managing partner Stephen Innes. Resilient US services data seen Aug. 5 also offered some support for prices and bolstered a broad-based recovery in risk sentiment, IG market analyst Yeap Jun Rong told Commodity Insights. \"Oil prices have been attempting to stabilize from recent rout,\" Yeap said. \"But that is weighed against geopolitical developments in the Middle East, where initial retaliation from Hezbollah has been more contained than what some expect. \"For now, concerns around US growth risks are eased by resilience in US services activities, but it may have to take more to reassure markets of a stronger global demand outlook for oil,\" he said. \"Until then, gains in oil prices may seem more limited.\" ","headline":" Crude edges higher as market stabilizes amid Middle Eastern supply concerns","updatedDate":"2024-08-06T19:35:14.000"},{"Unnamed: 0":297,"body":" The US Energy Information Administration Aug. 6 lowered its 2024 crude price forecasts by just less than $2\/b, tracking lower daily spot prices driven by signals of a global economic slowdown and the prospect of reduced world liquid fuel consumption in 2025 thanks to reduced China demand. \"Although the monthly average Brent spot price was higher in July, daily spot prices fell toward the end of the month driven in part by signals that global economic conditions may be slowing, which has the potential to reduce global oil demand growth,\" the EIA said in its August Short-Term Energy Outlook. \"Although market concerns about the economy have lowered crude oil prices in recent days, we still expect that the most recent round of OPEC+ production cuts will reduce global oil inventories over the next three quarters in our forecast and push oil prices higher.\" The agency predicted the Brent crude spot oil price to increase from current prices in the remainder of 2024, foreseeing $87\/b in December 2024 and $89\/b in the first quarter of 2025. The EIA decreased its 2024 forecast for Brent crude by $1.93 to $84.44 and its 2025 outlook by $2.67 to $85.71. Similarly, the agency forecast WTI crude down $1.82 from its July estimate for the year, while it lowered its expectation for 2025 by $2.67 to $81.21\/b. \"The main source of this upward price pressure is falling global oil inventories resulting from OPEC+ production cuts,\" the EIA said. The agency said it expects global oil inventories to decrease by an average 0.8 million b\/d in the second half of 2024, with further declines in the first quarter of 2025, but anticipated the market would \"gradually return to moderate inventory builds\" in the middle of 2025 after the expiration of voluntary OPEC+ supply cuts. The agency forecast the Brent price to fall to $83\/b by the end of 2025. Despite OPEC+'s policies limiting world oil production growth, growth outside of OPEC+ is expected to remain strong, with a 1.8 million b\/d increase from countries outside OPEC+ offsetting a 1.3 million b\/d decline from OPEC+ -- led by growth in the US, Canada, Guyana and Brazil. EIA said it expects global production of liquid fuels to increase by 2.1 million b\/d in 2025, as market growth combines with an unwinding of voluntary OPEC+ cuts. China diesel demand Among the highlighted changes in the agency's August report is its revised forecast of global liquid fuel consumption. While the EIA still believes global consumption will increase in 2024 and 2025, it revised its 2025 estimate from 1.8 million b\/d to 1.6 million -- largely, it said, as a result of a projected reduction in demand from China. While many non-OECD countries are likely to increase their consumption of liquid fuels in 2024 and 2025, EIA cited weaker-than-expected economic data from China as a reason to expect the world's second-largest economy to slow its consumption of fuel. \"We reduced our forecast of petroleum consumption growth in China for 2024 and 2025 because of slower economic activity as well as updated monthly statistics showing reduced diesel demand, crude oil imports, and crude oil refinery runs in China,\" the EIA said. \"China\u2019s GDP for 2Q24 grew 4.7% from last year, slightly less than the government\u2019s 5% target, reflecting slower investment in the country\u2019s real estate and construction sectors.\" EIA's new forecast suggests China's consumption will grow 0.3 million b\/d in 2024 and 2025, less than its average rate of growth from 2015-2019. Gasoline prices and jet fuel US retail gasoline prices are expected to average $3.38\/gal this year, down 3 cents from the previous estimate. The EIA sees gasoline prices declining to an average of $3.33\/gal in 2025, a 14-cent decrease from last month's estimate. The agency also lowered its expectations for retail diesel prices, putting the fuel at $3.84\/gal this year, down 5 cents from the prior estimate, and at $3.87\/gal in 2025, a 5-cent increase from July's estimate. Those lower estimates are thanks to lower consumption: The EIA estimates the US will consume 4% less gasoline in 2025 than it did in 2019 and 3% less distillate fuel oil. However, jet fuel consumption is rising, thanks to increase in US domestic air travel, with US jet fuel consumption expected to eclipse 2019 levels for the first time since the COVID-19 pandemic. \"We expect more jet fuel will be consumed next year in the United States than before the pandemic in 2019, but we expect gasoline and distillate consumption to remain below 2019 volumes,\" the EIA said. ","headline":"US EIA lowers 2024 oil price outlook by $2\/b, but still predicts increases","updatedDate":"2024-08-06T19:31:44.000"},{"Unnamed: 0":298,"body":" Shell and BP will spend around $15 million covering operating costs at South Africa's Sapref refinery as it transfers ownership to the state-owned Central Energy Fund (CEF), a representative for the government entity confirmed Aug. 6. News broke May 27 that the 180,000 b\/d refinery, which has been shuttered since 2022, would be sold from Shell and BP to the CEF , drawing a line under the companies' involvement in South Africa's ailing refining sector. At the time, South Africa's Department of Mineral Resources and Energy expressed aims to address energy security concerns through the acquisition, which covers the refinery and its associated assets, including pipeline and import infrastructure, yet declined to specify plans for the site. Speaking to S&P Global Commodity Insights Aug. 6, a representative for CEF said that it had secured $15 million from Shell and BP's South African units to support the refinery's operations. Final investment decisions are due to be finalized soon, without providing specifics on funding plans. Neither Shell nor BP were available for comment on the funding or specifics of the deal when contacted for comment Aug. 6. First established in 1963, the Sapref refinery was once South Africa's largest, accounting for 35% of its refining capacity when operational, and still employs 48 permanent staff, Shell said in May. The plant had previously been earmarked by BP for a $250 million upgrade in 2018, however flood damage in 2022 saw plans shelved after the plant's maintenance requirements surged. Speaking July 14, South Africa's Minister of Mineral Resources and Energy Gwede Mantashe hinted at plans to revive operations at the plant, letting local reporters that private investors would be sought to support its activity. \"Minister Mantashe's recent comments have signaled that he wants to bring it back into operation, but this will face financing challenges,\" said Mike Davies, senior advisor on South Africa and Namibia at Horizon Engage, a consultancy, Aug. 6. \"Treasury is increasingly reluctant to fund [state-owned enterprises] SOEs hence Mantashe's recent appeal to private investors, while the deal will also come under scrutiny under the Government of National Unity,\" he said. Lack of investment appetite for the refinery has stoked long-held energy security concerns for South Africa, which has been left with just two active refineries, Astron and Natref in recent years. Engen shut its Durban refinery, Enref, in 2020, after a fire before Sapref closed in 2022, leaving the country with some 218,500 b\/d refining capacity and a growing reliance on growing import volumes to service its fuel demand. In May, South Africa's Department of Mineral Resources and Energy, the DMRE, said it \"has seriously noted with concern the declining local refining capacity\" in the country, and has since expressed intentions to restore domestic production. For Shell, the refinery divestment coincides with plans to exit its South African downstream business , also announced in May, ending over 120 years in the space as it has sought to consolidate its downstream business and focus on areas such as North America and China. Speaking to S&P Global Commodity Insights in May, a Shell spokesperson said the group had already been approached by \"several highly credible parties,\" though a buyer for the business is yet to be announced. ","headline":"Shell, BP to fund South Africa's Sapref refinery operations in government takeover","updatedDate":"2024-08-06T18:53:58.000"},{"Unnamed: 0":299,"body":" State-run refiner Indian Oil cancelled a tender to build a 10,000 metric tons\/year renewable hydrogen plant, a company executive said Aug. 6, a decision that according to an analyst and industry members highlights the difficulties faced by early starters of the energy transition. Indian Oil floated the tender for a renewable hydrogen plant in August 2023, but following a legal challenge, the company revised it and floated it again in March for the plant to be built on the site of its Panipat refinery on a Build-Operate-Own basis. \u201cYes, it has been cancelled,\u201d the company executive said, not wishing to be named. \u201cDiscussions are ongoing on how to go forward.\u201d Indian Oil planned to have the renewable hydrogen plant built in a timeframe of 32 months from the date of the award of the tender, according to the March tender seen online. The last date for submission of the bid was April 22, but the firm extended the last date multiple times owing to limited response from bidders, according to industry members. \"Indian Oil may have encountered initial challenges in initiating the project as the hydrogen market is still evolving,\u201d said Akshay Modi, Senior Analyst \u2013 South Asia Natural Gas, LNG and Hydrogen at S&P Global Commodity Insights. \u201cHowever, by leveraging the learnings from this tender, the company can expedite the release of a new tender as it aims to achieve net-zero by 2046.\" Modi said few bidders could have responded to the tender and since this was a reverse auction tender, Indian Oil would have ideally preferred a higher number of bidders for a better price discovery. Industry members have said inflation, absence of price discovery and lack of targets for mandatory consumption of renewable hydrogen are some of the difficulties plaguing the early renewable hydrogen projects. Conditions Sole bidders or consortiums were invited on the condition that they should have executed a plant having hydrogen handling facilities in refineries, power plants or electrolysis plants, according to the tender. Indian Oil is adopting several methods to decarbonize its operations, such as advancing renewable hydrogen projects and tapping low-carbon energy sources, while maintaining growth in its conventional business, Chairman Shrikant Vaidya told Commodity Insights in an interview in February. The company, with a net-zero target by 2046, has a joint venture, GH4India, with engineering company L&T and renewables company ReNew with plans to build a large-scale renewable hydrogen business for domestic and export sales. Industry sources said the legal dispute last year was related to the participation of GH4India in the tender process, as bidders said it would amount to a conflict of interest. Indian Oil officials did not comment on the matter. The tender also said the bidder should be a renewable power producer operating a plant connected to the grid powered by solar, wind or any other form of renewable energy for one year in order to qualify. Going ahead, since the plant has a very small capacity, it motivates the company to bear an initial loss and take a bigger risk on the project, Modi said. Other Indian refineries may chart their own course for their respective renewable hydrogen production plans and may not necessarily face the same issues as Indian Oil, he added. Platts, part of S&P Global Commodity Insights, assessed Japan hydrogen produced via alkaline electrolysis (including capex) at $6.99\/kg on Aug. 6, up 27.32% on the month. Platts, part of Commodity Insights, assessed Oman hydrogen produced via alkaline electrolysis (including capex) at $5.22\/kg on Aug. 6, same as a month ago. ","headline":"Indian Oil cancels tender to build a 10,000 mt\/yr renewable hydrogen plant","updatedDate":"2024-08-06T18:07:44.000"},{"Unnamed: 0":300,"body":" Brazilian independent oil and natural gas producer Prio registered a 31.7% year-on-year decrease in July's output amid maintenance work, shuttered wells and delays obtaining environmental licenses to make repairs, according to the company's latest production report. Prio pumped an average of 67,666 b\/d of oil equivalent in July, down from 99,094 in July 2023, the company said Aug. 5. That was the third-consecutive monthly retreat in output. July's production also tumbled 23.3% from 88,200 boe\/d in June. Prio continued to face technical issues and equipment problems that shuttered offshore production wells, with repair efforts undermined by an ongoing strike at the Brazilian Institute for the Environment and Natural Resources, or IBAMA, the company said. Workers at IBAMA, which is Brazil's top federal environmental regulator, walked off the job on June 24 and July 1. The strike is delaying efforts to carry out well interventions and swap out failed submerged centrifugal pumps at the Frade field and the Polvo-Tubarao Martelo production hub, Prio said. IBAMA needs to approve environmental licenses in order for Prio to start the work, but the strike halted approvals of drilling permits and other environmental licenses for offshore projects. A federal judge ordered workers involved in licensing and permitting back on the job, but work-to-rule actions implemented in January have remained in place and slowed down the pace of work at the regulatory agency, according to government and industry officials. The work slowdown previously affected Prio in the first quarter, with the company failing to win installation licenses and drilling permits to start development of the Wahoo discovery, according to the company. Prio had expected to start installing subsea systems at Wahoo in the first quarter, but the company never received the required permits. Now, the installation will need to be pushed back into the third quarter, depending on the availability of ships and support ships. Despite the delays, Prio continues to estimate first oil from Wahoo in 2024, according to company officials . The field is expected to produce about 40,000 b\/d from four production wells, which will be tied back to the FPSO Valente floating production, storage and offloading ship anchored at the nearby Frade field. The strike's impact also continued to loom at Frade, where Prio shuttered the ODP3 well in May for a workover, but is still waiting on IBAMA to approve a permit for the work. Prio previously repaired a defective valve at Frade that had undermined output in April. Frade produced 44,469 boe\/d in July, down 20.9% from 56,199 boe\/d in July 2023, Prio said. July's output also fell 3% from the 46,013 produced in June. Prio also could restart production from the MUP3A production well, which was shuttered in September 2023. A restart, however, has been complicated by hydrates that plugged flow lines connecting the well to the FPSO Valente. Albacora Leste shutdown Prio also registered a sharp retreat in July from the Albacora Leste field, which had returned to full production capacity in April, the company said. Prio shuttered production at Albacora Leste for 13 days in June to carry out maintenance work, with output returning gradually during the month. The work was part of a wide-ranging campaign aimed at boosting production from the offshore heavy oil producer. Albacora Leste produced 13,441 boe\/d in July, down 50.3% from 27,019 boe\/d in July 2023, Prio said. July's output also sank 51.9% from the 27,983 boe\/d pumped in June. Prio owns a 90% operating stake in Albacora Leste, which it purchased from state-led oil company Petrobras in January 2023. The remaining 10% equity share is retained by Spanish-Chinese joint venture company Repsol Sinopec. Well troubles also continued to undermine output at the Polvo-Tubarao Martelo production hub, with the TBMT-8H, TBMT-10H and TBMT-4H wells all temporarily shuttered in July after submerged centrifugal pumps failed, Prio said. The pumps are needed to lift the field's highly viscous crude from the seabed to the FPSO on the surface. The cluster also had issues with electricity generation onboard the FPSO Polvo, which were resolved during the month. Similar to Frade, Prio is waiting on IBAMA to issue environmental licenses that will allow the company to swap out the pumps, according to the company. The Polvo-Tubarao Martelo cluster produced 9,757 boe\/d in July, down 38.5% from 15,876 boe\/d in July 2023, Prio said. July's production also fell 31.3% from the 14,204 boe\/d produced in June. ","headline":"Brazil's Prio July oil equivalent output falls 31.7% on maintenance, shuttered wells","updatedDate":"2024-08-06T18:01:51.000"},{"Unnamed: 0":301,"body":" Eni has picked up four exploration blocks offshore Ivory Coast as the Italian major looks to follow its Baleine and Calao discoveries with more finds in the African country, according to an official notice seen by S&P Global Commodity Insights Aug. 6. The Ivorian president\u2019s Council of Ministers said Eni\u2019s local subsidiary had signed production sharing contracts for blocks CI-504, CI-526, CI-706 and CI-708, the notice read. The agreements commit the Italian firm to spend at least $80 million on exploring in the four blocks during the initial three-year exploration period, as per the notice. The licenses frame Eni\u2019s recent Calao discovery , made in March with the Murene-1X well, which is thought to contain up to 1.5 billion barrels of oil equivalent. At the time, Eni said it had encountered \u201clight oil, gas and condensates\u201d in block CI-205, drilling to depths of 5,000 meters in water depths of 2,000 meters. The Italian company did not respond to requests for comment on the new licenses. Eni brought its landmark Baleine field off Ivory Coast online in August 2023, just two years after its initial discoveries \u2013 an extremely fast turnaround by industry standards. Baleine \u2013 which sits on block CI-101 \u2013 is currently producing around 22,000 b\/d, according to Eni, with output expected to ramp up to 60,000 b\/d in the second phase and 150,000 b\/d in the third in 2026. Phase two is expected to begin in December, Eni said in a statement late-July, with refurbished floating storage and offloading units preparing to set sail for Ivory Coast. Eni first invested in the coastal West African country in 2015 and also holds deepwater blocks CI-401, CI-501, CI-801 and CI-802. The country has emerged as one of Africa\u2019s exciting oil and gas frontiers, seeing a flood of investment as IOCs depart from mature producers such as Nigeria, Angola and Equatorial Guinea. Elephant deals The Eni deals come just days after US independent Elephant Oil signed production sharing contracts for three blocks onshore Ivory Coast: CI-520, CI-521 and CI-522. The seven-year contracts set the stage for exploration and production activities by Elephant in cooperation with state-owned Petroci. The US firm will hold an 80% stake to Petroci\u2019s 20%, according to a release by the country\u2019s oil ministry. Oil exploration first began onshore in Ivory Coast in the 1950s, but discoveries have mostly been made offshore in recent years. Elephant also holds onshore oil exploration assets in Benin. London-listed mining company Red Rock Resources holds a 4.64% interest in Elephant Oil. ","headline":"Eni follows Ivory Coast discoveries with four new licenses","updatedDate":"2024-08-06T17:24:08.000"},{"Unnamed: 0":302,"body":" The EU\u2019s soybean meal imports in marketing year 2024-25 (July-June) totaled 1.77 million mt as of Aug. 4, up 8% on the year, European Commission data showed Aug. 6. Poland and Spain were the largest buyers within the bloc over the period at 305,665 mt and 256,185 mt, respectively. Meanwhile, Brazil and Argentina were the largest soybean meal suppliers to the EU with volumes at 848,436 mt and 700,157 mt, respectively. The EU imported 510,996 mt of soybean meal in MY 2023-24, according to the data. The region\u2019s soybean imports dropped 17% on the year to 1.12 million mt in MY 2024-25. Spain and Germany were the largest buyers at 381,275 mt and 213,558 mt, respectively. Brazil-origin products accounted for 71.6% of the EU\u2019s raw soybean inflows, while its share of soybean meal over the period was 47.9%. The EU is the world\u2019s largest soybean meal importer and the second-largest soybean purchaser. The bloc\u2019s soybean oil imports in MY 2024-25 fell 61% year on year to 39,264 mt as of Aug. 4, EU data showed. Ireland and the Netherlands were the largest buyers within the bloc while the United Kingdom and Norway were the largest soybean oil suppliers to the EU. The EU imported 693,725 mt of soybean oil in MY 2023-24, according to the data. The bloc\u2019s sunflower oil imports decreased 19% on the year to 181,342 mt in MY 2024-25. The EU\u2019s rapeseed oil imports fell 89% year on year to 3,351 mt over the period while palm oil inflows were at 228,528 mt, down 33% on the year, the data showed. Platts, part of S&P Global Commodity Insights, assessed soybeans FOB Paranagua June new crop at $405.03\/mt Aug. 5, up $3.4\/mt day on day. ","headline":" MY 2024-25 soybean meal imports rise 8% on year as of Aug 4","updatedDate":"2024-08-06T16:59:53.000"},{"Unnamed: 0":303,"body":" PPC is to buy a 600-MW onshore wind farm in Romania and other green assets as well as a 145 MW project pipeline from a Macquarie-owned developer, the Greek utility said Aug. 6. The agreement values the assets at Eur700 million with the \"overall valuation being in line with precedent transactions on the market,\" it said. Assets are owned by Evryo Group, Czech utility CEZ' former Romania unit, now owned by funds managed by Macquarie Asset Management. The 600-MW wind farm near Constanta close to the Black Sea started operations in 2012 and is one of Europe's biggest onshore wind parks featuring 240 x 2.5 MW turbines. The deal strengthens PPC's strategy in Romania, also adding 22 MW hydro, 6 MW battery storage and 1 MW of solar PV installed capacity. Upon completion of the agreement, expected in the fourth quarter, PPC's operating renewables portfolio in Romania will double, it said. The utility strives to meet an 8.9-GW target in 2026 across its entire group. By end-June, PPC's installed renewables capacity stood at 4.7 GW, up 34% year on year, the utility said in a results statement Aug. 6. A further 3.3 GW are either in construction or ready to build. In its Greek generation unit, lignite output fell 30% to 1.5 TWh for the six months\u2019 period. In the first half of the year PPC\u2019s natural gas- and oil-fired generation both climbed, 33% and 18% respectively year on year to 3.1 TWh and 1.7 TWh, the utility said. ","headline":"Greek PPC to buy a 600 MW Romanian wind farm, portfolio from Macquarie-owned developer","updatedDate":"2024-08-06T16:42:52.000"},{"Unnamed: 0":304,"body":" Commodities trader Vitol can go ahead with its plan to take Saras private after successfully increasing its ownership in the Italian refining business to more than 50%. Vitol first revealed its plan to take the business private in February , when it announced its intended acquisition of an additional 35% stake in the business, which owns the 300,000 b\/d Sarroch refinery on the island of Sardinia. Previously, Vitol had held around 10.46% of Saras shares, while rival Trafigura had a 9.6% stake. The takeover was completed June 18, initially leaving Vitol with a 45.48% majority stake and triggering a mandatory tender offer for remaining shares in the business. In a statement Aug. 5, Saras said that the Vitol-controlled Varas Holding had successfully acquired 51% of the company\u2019s share capital, allowing it to delist the company from the Milan Stock Exchange. Delisting of the business will take place after confirmation that necessary requirements have been met, although failing this Vitol would have the right to delist the company by other means, such as a merger, Saras said in its statement. Vitol, which is yet to provide comment on the move Aug. 6, has previously underscored the strategic advantage of connecting the refinery to its vast global trading network. Private ownership of the business promises to give the trader unique insight into European refining margins, analysts have said. With the ability to process over 30 types of crude, Sarroch is ripe for optimization in a post-Russian feedstock market for Europe, while its location on the Mediterranean provides an opportunity for traders seeking to leverage new oil flows. The addition of Sarroch to Vitol's portfolio takes its refining portfolio to around 800,000 b\/d of capacity across seven refineries, giving it the largest downstream production footprint among its trading peers. The Italian refinery is now the company's largest refining asset, comprising almost 40% of a wider downstream footprint that spans Switzerland, Germany, the Netherlands, Australia, Malaysia and the UAE. The sale was agreed upon at Eur1.60 per share, adjusted down from a previous Eur1.75 under the initial sale agreement Feb 11 to account for dividend distributions. The original deal valued the business at Eur1.7 billion ($1.83 billion). There has been a spate of buying interest among trading houses in the refining sector recently as they seek to leverage back-to-back years of record profits to expand. Trafigura, while seeing its interest in Sarroch come to an end with Vitol's move, expects to complete its takeover of ExxonMobil\u2019s Fos-sur-Mer refinery in the South of France via its joint-venture Rhone Energies by October, it said Aug. 1. ","headline":"Vitol to take Italian refiner Saras private after acquiring 51% stake","updatedDate":"2024-08-06T16:38:38.000"},{"Unnamed: 0":305,"body":" The Mediterranean sweet crude market has so far shown minimal reaction to the total shutdown of the 300,000 b\/d Sharara oil field in Libya, according to market participants. Differentials for key Mediterranean sweet crude grades, including Azeri Light, Saharan Blend and Es Sider, have so far remained steady, sources said, as supply in the region remains plentiful. \u201cNo panic due to Sharara so far,\u201d one trader said. \u201cWTI [Midland] is still everywhere.\u201d WTI Midland, imported from the US Gulf Coast, is a natural competitor to light sweet crudes in the Mediterranean such as El Sharara. According to data from the Platts Periodic Table of Oil, WTI Midland has a 0.2% sulfur content and API gravity of 42. Libya\u2019s El Sharara crude has a 0.08% sulfur content and API gravity of 42.6. Libya\u2019s largest oilfield was taken completely offline Aug. 5, after the son of eastern warlord Khalifa Haftar ordered a shutdown in response to a European arrest warrant. Output at the huge Sharara field, with a capacity to produce up to 300,000 b\/d of crude oil, initially fell to around 100,000 b\/d after protesters entered the operations room on Aug. 4, sources told S&P Global Commodity Insights, before ceasing by Aug. 5. Production at the Sharara field was previously halted for two weeks in January when Libya's National Oil Corp. declared force majeure amid protests. The shutdown in January caused Mediterranean sweet crude prices to spike amid a supply shortage in the region. Azeri Light, Es Sider and Saharan Blend crude differentials all reached 2024 highs on Jan. 23 and Jan. 24. The extent of any possible supply disruption amid the current shutdown remains unclear for now, but traders said on Aug. 5 that they were cautiously optimistic that the suspension of output would be short-lived. ","headline":"Mediterranean sweet crude market shows muted response to Sharara shutdown","updatedDate":"2024-08-06T16:14:27.000"},{"Unnamed: 0":306,"body":" Italian refiner Saras, operator of the Sarroch refinery on the island of Sardinia, said Aug. 6 that the Vitol-controlled Varas Holding has acquired 51% of the company's share capital. In February, Vitol agreed to acquire approximately 35% stake in Saras. In April, the Italian government approved Vitol's bid to acquire a controlling stake in Saras. The sale for the latest package that brought Vitol's share above 50% was agreed at EUR 1.60 per share, down from a previous EUR 1.75 under the initial sale agreement Feb 11 to account for dividend distributions. The acquisition of the 300,000 b\/d refinery, a major supplier of oil products in the Mediterranean, would take Vitol's refining portfolio to around 800,000 b\/d, Vitol has said previously. Saras said July 31 that the Sarroch refinery aims to process 96.5 million-98.5 million barrels (13.2 million-13.5 million mt) of crude, to which approximately 1 million mt (around 7 million barrels) of feedstock will be added in 2024. Light extra-sweet made up the biggest share of the crude slate, at slightly more than 40% in the quarter and first half, followed by light sweet. ","headline":" Vitol acquires 51% in Italian refiner Saras","updatedDate":"2024-08-06T16:04:02.000"},{"Unnamed: 0":307,"body":" The spread between LNG bunker fuel in Rotterdam and its 0.5%S marine fuel equivalent narrowed to a year-to-date low as demand for the former picked up in the Amsterdam-Rotterdam-Antwerp region. Platts, part of S&P Global Commodity Insights, assessed Rotterdam LNG bunkers at $12.488\/GJ Aug. 5, a discount of 31.7 cents\/GJ to 0.5%S marine fuel in the Dutch port, which was at $12.805\/GJ. This was far below the average spread across July which stood at minus $2.035\/GJ, Commodity Insights data showed. Market participants highlighted a combination of factors that had pushed up the LNG bunker price as demand picked up in the region. \u201cWe see a healthy port calling with a mixed bag of product tankers, pure car carriers and cruise ships, it\u2019s getting better,\u201d said an Atlantic LNG bunkers trader. \u201cThere is increasing activity and it's only going to go up and up.\u201d Already this year the Port of Rotterdam reported record high LNG sales for Q2 2024 as LNG sales as a marine fuel reached 242,931 cu m. Moreover, market sources pointed to favorable arbitrage economics in Europe, compared to Asia, with European benchmark TTF gas prices prices lower than their Asian LNG counterpart, the JKM marker. On top of this, the same source noted that infrastructure limitations in Asia had led to vessels opting for European bunkering instead. \u201cThere is a lot of activity in Asia. The Singapore and Malaysia bunkers schedule is filled up, already 30 days in advance. Singapore only has three barges and [there are only] three barges in Malaysia so it\u2019s very small,\u201d said the trader. \u201cIf the spot price is too high vessels will skip the Southeast Asia bunkers call and fill up here [Northwest Europe] instead,\u201d he added. Platts last assessed month-ahead September Dutch TTF at $11.471\/MMBtu Aug. 5, while the JKM marker was assessed at $12.849\/MMBtu. LNG bunkers in Rotterdam were assessed at $13.176\/MMBtu Aug. 5 while Singapore LNG was at $14.772\/MMBtu, putting Rotterdam at a $1.60\/MMBtu discount to its Asian counterpart. In comparison, demand for 0.5%S marine fuel has softened significantly, leading to a sharp decline in prices. This weakness in VLSFO can be largely attributed to the summer season, as the market hits the peak holiday period. \u201cIt\u2019s been very calm since the beginning of August, with many people on holiday. I don\u2019t see any other reason apart from seasonality,\u201d said a local trader. At the end of July, VLSFO prices were seemingly stable, with traders optimistic about a potential rise in demand. \u201cI see demand for VLSFO picking up,\u201d noted one trader. However, the ample supply and peak holiday season have dampened demand, adding further pressure to prices and extending the downward trend that started in July. In August, VLSFO prices dropped by 6%, with buyers waiting for the trend to bottom out to capitalize on the lowest prices. \u201cPeople are holding off on purchases, expecting prices to fall further given the lower trading activity,\u201d a trader said. Moreover, on Aug. 5, the broad selloff in the stock market and fears of a US recession didn\u2019t leave the bunker market, pushing VLSFO prices down by an additional $15\/mt. Platts last assessed 0.5%S marine fuel at $525\/mt Aug. 5. ","headline":"Rotterdam LNG bunkers spread with VLSFO narrows to 2024 low","updatedDate":"2024-08-06T14:52:56.000"},{"Unnamed: 0":308,"body":" YPF, the biggest oil and natural gas producer in Argentina, has agreed to sell 15 maturing conventional blocks to smaller local companies in a move to concentrate its business on the Vaca Muerta shale play for production and export growth. The state-run company sold the blocks in six clusters in the provinces of Chubut, Mendoza, Neuqu\u00e9n and R\u00edo Negro, which all told are producing around 29,000 b\/d of crude and 351,000 cu m\/d of gas, it said in a late Aug. 5 statement. In Mendoza, the company sold a cluster of six blocks in the north of the province to Petr\u00f3leos Sudamericanos and another two in Llancanelo to Petroqu\u00edmica Comodoro Rivadavia, or PCR. On the border of Neuqu\u00e9n and R\u00edo Negro, it sold the Se\u00f1al Picada-Punta Barda block to Velitec, while a cluster of four blocks in the north of Neuqu\u00e9n went to Bentia Energy and Ingenier\u00eda Sima, YPF said. Further south, in the province of Chubut, it sold Escalante\u2013El Tr\u00e9bol and Campamento Central-Ca\u00f1ad\u00f3n Perdido to Pecom. These are the first of 55 fields that YPF wants to sell this year as part of a wider divestment plan that includes noncore assets in Bolivia, Brazil and Chile, as well as a gas distributor in Buenos Aires. The 55 fields have passed their peak production levels, making it less efficient and more expensive for such a big company as YPF to continue developing them. On the other hand, the assets can be developed profitably and efficiently by smaller companies, YPF has said. YPF said it has received more than 60 offers from some 30 local and international companies for the conventional blocks. The company has said it will use the proceeds to invest in boosting output in Vaca Muerta and building takeaway capacity from the play with the goal of taking its portfolio to 80% Vaca Muerta and 20% conventional from a current 50\/50. The most immediate target is to increase shale oil production to more than 160,000 b\/d in 2025 from 97,000 b\/d in 2023 -- and 112,000 b\/d in the first quarter of this year, YPF has said. Increasing oil and gas exports The production growth is building up a surplus for exporting, with the company\u2019s shipments to Chile rising 22% to 23,000 b\/d in the first quarter from the year-earlier level. With production on track to continue rising, YPF is moving forward on the construction of takeaway and export capacity. It recently launched construction of Vaca Muerta Sur, a transport and export system will have an initial 180,000 b\/d of capacity in 2026 before increasing to 360,000 b\/d in 2027 and subsequently 800,000 b\/d. At the same time, YPF is also working with Malaysia\u2019s Petronas on a project to start exporting LNG in 2027 with the shipment of 6 million cu m\/d via a floating liquefaction terminal. The project will increase to 40 million cu m\/d in 2029-30 and 120 million cu m\/d in 2030-31 with an onshore terminal in the province of R\u00edo Negro, the company has said. YPF\u2019s gas production was 36.4 million cu m\/d in the first quarter of this year, in line with the 36.5 million cu m\/d in the year-earlier quarter. Of this, shale gas rose 7.8% to 18 million cu m\/d in the first quarter from 16.7 million a year earlier, helping to compensate for an 8.4% decline in conventional gas output and 3.4% fall in tight gas over the same period, according to YPF's latest financial report. YPF was producing a total of 314,000 b\/d of oil and 33 million cu m\/d of gas in June, according to the latest data from the Energy Secretariat. ","headline":"Argentina\u2019s YPF finds buyers for 15 maturing conventional blocks as it focuses on Vaca Muerta","updatedDate":"2024-08-06T14:39:26.000"},{"Unnamed: 0":309,"body":" Refineries in Nigeria, including the newly launched Dangote and the upgraded Port Harcourt, have been in focus. Dangote denied allegations of a crude distillation unit outage and said it had been reselling barrels of WTI crude oil from the US that were initially intended for processing with the intention of lifting more Nigerian crude. \"Our CDU is working and in perfect condition,\" said company spokesman Tony Chiejina in a statement July 26. A company source said the refinery was reselling the WTI emboldened by assurances from the country's regulator that domestic supply would be made available. The Nigerian government adopted July 29 a proposal for state oil company, Nigerian National Petroleum Co. (NNPC), to sell crude oil to its new Dangote refinery in naira, the local currency. Nigerian crude oil for Dangote was previously predominantly purchased in US dollars due to its location in the Lekki free trade zone in Lagos, designed to help attract foreign investment. However, as the refinery has scaled its operations, it has struggled to secure sufficient crude feedstock, while weakness in Nigeria's naira in the foreign exchange market has made dollar-based transactions increasingly unattractive. In a statement on X, formerly Twitter, Bayo Onanuga, Special Adviser to Nigeria's President Bola Tinubu, said that the Federal Executive Council had adopted a proposal for 450,000 barrels of Nigerian crude oil to be offered in naira to domestic refineries, using Dangote as pilot. Meanwhile, in anticipation of the start of gasoline production, Dangote has curbed its fuel oil and naphtha exports in July as the plant gears toward its first gasoline production, according to sources and ship tracking data. Gasoil, fuel oil and naphtha exports were among the first barrels to depart the refinery since it started up in December, in the absence of an operating fluid catalytic converter, which produces gasoline. When operating, the FCC can process low sulfur straight run, while naphtha was expected to be held back for gasoline blending. A representative for Dangote told S&P Global Commodity Insights July 18 the refinery expected to deliver its first gasoline to the market mid-August, delayed by a month from its latest projections. Ongoing maintenance Refinery Capacity b\/d Country Owner Unit Duration Ras Lanuf 220,000 Libya NOC Restart Pending Indeni 24,000 Zambia Zambia Full Mothballed Engen 125,000 South Africa Engen Fire Conversion Sapref 175,200 South Africa Joint Full Mothballed Tema 45,000 Ghana Tema Full Ongoing Limbe 72,000 Cameroon Sonara Offline 2019 Upgrades Warri 125,000 Nigeria NNPC Overhaul N\/A Kaduna 110,000 Nigeria NNPC Overhaul N\/A Port Harcourt 210,000 Nigeria NNPC Overhaul N\/A Pointe Noire 25,000 Congo CORAF Upgrade 2022 Dakar 24,000 Senegal SIR Expansion N\/A Assiut 90,000 Egypt ASORC Upgrade 2020 Suez 68,000 Egypt Suez company Upgrade N\/A El Nasr 146,000 Egypt EGPC Upgrade N\/A Mombasa 70,000 Kenya Government Conversion NA Sogara 19,000 Gabon Joint Upgrade 2025 SIR 75,000 Cote d'Ivoire SIR Upgrade 2028 Luanda 65,000 Angola Sonangol Upgrade 2026 Launches Dangote 650,000 Nigeria Dangote Ind Launch 2023 Hassi Messaoud 100,000 Algeria Sonatrach Launch 2027 Tiaret 100,000 Algeria Sonatrach Launch 2021-22 Kenya NA Kenya Government Launch NA Takoradi 150,000 Ghana Joint Launch NA Lobito 200,000 Angola Joint Launch 2025 Cabinda 60,000 Angola Joint Launch 2022 Soyo 100,000 Angola Joint Launch 2024 Albert Graben 60,000 Uganda Government Launch 2023 Condensate 200,000 Nigeria NNPC Launch NA Red Sea Coast 200,000 Sudan Government Launch NA Nigeria\/Niger NA Nigeria Government Launch NA Ndola NA Zambia NA Launch 2025 Morocco 100,000 Morocco Joint Launch NA Punta Europa 10,000 Equatorial Guinea Joint Launch NA Cogo 10,000 Equatorial Guinea Joint Launch NA Kamsar 12,000 Guinea Brahms Launch NA Waltersmith 5,000 Nigeria Joint Expansion NA Benin NA Benin Government Launch NA Paloch 40,000 South Sudan Trinity Energy Launch NA Kribi 80,000 Cameroon Joint Launch NA Pointe Noire 50,000 Congo Joint Launch 2023 Moribayah NA Guinea Joint Launch NA Akwa Ibom 200,000 Nigeria Bua Group Launch NA Tema 100,000 Ghana Sentuo Launch 2023 New and ongoing maintenance New and revised entries ** South Africa's Natref refinery was expected to complete its maintenance during July, the company said July 11. The company has previously said the refinery would carry out maintenance set to last seven weeks from May to July. Existing entries ** Sudan's Khartoum refinery has been \"completely destroyed\" after the Sudanese army bombed the idled plant late May 21, according to Sudan's Rapid Support Forces militia. Seized by the Rapid Support Forces in April 2023, Khartoum refinery fully halted processing at the end of July 2023. Since the beginning of the conflict between forces loyal to warring generals in the East African country, the militia was using the refinery to supply its troops with fuel. ** Ghana's Tema refinery remains idled, energy minister Matthew Opoku Prempeh told S&P Global Commodity Insights in March 2024. The plant faced several issues over the past few years, experiencing intermittent outages at its crude distillation unit and fluid catalytic cracker. The refinery was shut January 2017 after an explosion at a furnace attached to the CDU. The CDU was installed the month before and had only just begun processing Ghana's TEN Blend crude grade. ** Cameroon's Sonara is looking for an engineering company that can carry out a feasibility study to reconstruct Limbe facility units destroyed during a fire in May 2019. The study would look into finalizing the units in the Phase 1 modernization project: reconstruction, debottlenecking and revamping of the damaged units and building new conversion units, including hydrocracker, isomerization, hydrotreater and a bitumen unit. The reconstruction was authorized by the country's president in 2022, according to local media Cameroon-Tribune. Previously, the Cameroon government looked to launch a tender in search of companies interested in building a new refinery. Sonara's Limbe facility has been entirely offline since May 2019. Shortly before the explosion it had increased its capacity to 72,000 b\/d from 45,000 b\/d through an upgrade program, which involved the construction of a vacuum distillation unit, a catalytic reformer and a power plant as part of its phase 1 upgrade. ** Libya's Ras Lanuf refinery restarted its ethylene plant, but the refinery remained offline, according to market sources. No time frame was available for the refinery's restart. Initial stages of operation were started May 12 when naphtha was introduced into furnaces and the cracked gas compressor system started, leading to the production phase. The refinery had been closed since 2013 due to an arbitration dispute, which NOC won in March 2021 against the Libyan Emirates Oil. At the time, it was thought the award might lead to the refinery reopening. ** The reopening of Zambia's Indeni Petroleum Refinery remains uncertain following a government decision to compensate more than 300 workers and maintain the ageing refinery under care and maintenance while an appropriate investor is sought, Energy Minister Peter Kapala said. The decision was seen to be disappointing by union chief Mutukelwa Lubita since workers expected the government to revive the plant rather than close it indefinitely. The refinery's operations were suspended in late December 2020 for annual maintenance and never reopened for financial and technical reasons. At the end of 2021, the plant was put under care and maintenance. According to Kapala, Indeni was no longer profitable and fuel pump prices were high due to the refinery's inefficiency. Lubita said the unions and government should work together to \"fix\" the challenges, save jobs and prevent fuel supply issues. The government has started an audit and will come up with the real value of the site while a long-term solution for the refinery is sought, Kapala said. ** South Africa's largest refinery Sapref was to carry out a phased shutdown of its facility, the company said in March 2022. \"We are commencing with a staggered shutting down of our units followed by decontamination phase. There may be flaring and steam venting over the next two weeks,\" the company said. Its owners have been considering the future of the plant including a future sale of the asset, they have said, adding that a restart was possible in the future. ** South Africa's Engen said it would proceed with the conversion of its Durban refinery into a terminal. The refinery has been shut since a fire and explosion in December 2020. The refinery-terminal conversion was expected to be commissioned in the third quarter of 2023. Upgrades New and revised entries ** Nigeria's Old Port Harcourt refinery will restart in August, its owner NNPC said. Speaking to reporters July 15, NNPC CEO Mele Kyari announced the new timeline for revived operations at the plant, which has suffered numerous setbacks since closing for repairs in 2020. In March, NNPC said the plant was stocked with crude oil and would restart operations by the end of the month. In February, Shell said it had supplied the plant with 475,000 barrels of crude oil from the Bonny Terminal in readiness for resumed production at the plant, initially slated for restart December 2023. Existing entries ** Tunisia's STIR was planning to increase its capacity by around 50% by 2030, local media report reported. The refinery will be expanding capacity around 50% to 48,000 b\/d under Tunisia's 2035 energy strategy. Its current capacity is sufficient to cover one-third of Tunisia's oil products demand although around half of STIR's output is exported. Furthermore, the refinery does not operate at full capacity and in 2023 processed around 22,000 b\/d, down 28% on the year, according to the report. ** Angola's Sonangol plans to build new units, such as an RFCC as well as a steam cracker as part of the expansion project for its Luanda refinery, a company source said at the ARDA conference in Cape Town April 24. The company is studying a capacity expansion at Luanda from 60,000 b\/d to 120,000 b\/d, by building a new CDU. In addition, it aims to build a new RFCC and HDS units, as well as a steam cracker and 200,000 mt\/year petrochemical plant. The new units will help improve the specifications and comply with AFRI 5 and 6 standards. It is also planning to build a biorefinery in Luanda as part of its energy transition. The Luanda projects were due to be completed by 2026. Sonangol completed the construction of a new platforming unit at its Luanda refinery in 2022, as a result of which it increased gasoline output fourfold. ** Nigeria's Warri plant, which is undergoing a major overhaul, is nearing restart, according to Mele Kyari, group CEO of Nigerian National Petroleum Company. NNPC said Feb. 5 that the Warri refinery would be mechanically ready by the end of the first quarter. The repairs were being handled by a consortium of Italian engineering firms Saipem and Saipem Contracting and were to be completed in three phases spread over a total 77-month period. ** Nigeria's northern Kaduna refinery will resume production by end-2024 after four years of closure, the country's Minister of State for Petroleum Resources, Heineken Lokpobiri, said in October. The 110,000 b\/d Kaduna refinery, like other three state-owned oil refineries, was shut in late 2020 for a major overhaul after years of neglect that meant the refinery only operated sporadically. State energy company NNPC said that it contracted South Korean engineering group Daewoo to carry out a quick fix of Kaduna refinery, as opposed to a long-term complete overhaul, as Nigeria sought to urgently restore local gasoline supply. The Kaduna refinery would initially be refining 60,000 b\/d of crude when it resumes operations at the end of 2024. Nigeria wants to fix its refineries, including the 210,000 b\/d Port Harcourt refineries and the 125,000 b\/d Warri refinery. ** Republic of Congo is looking to upgrade its existing Pointe Noire refinery and also build a new refinery, the country's Minister of Hydrocarbons Bruno Jean-Richard Itoua said at an industry event June 1. The upgrade and expansion of the Pointe Noire refinery, which will enable it to be more profitable, will depend upon securing financing, the minister said. ** Cote d'Ivoire's SIR refinery is aiming to increase its capacity and improve the quality of its products and energy efficiency in the next few years. The refinery expected to start an EPC in January 2024 and commission the unit, which will enable it to produce 10 ppm diesel, in 2028. It is also working on a project aimed at reducing the benzene content of gasoline to 1% in volume from 4%-5% currently, the feasibility study for which is underway with the project due to be completed in 2028. Separately, it is expanding the CDU capacity from 75,000 b\/d to 100,000 b\/d. The project is in the FEED phase and is expected to be completed in 2028. It will also build a new reformer with a 100 mt\/hour capacity, expected to start operations in 2028. A feasibility study is also currently underway. In 2026, SIR expects to launch new sea terminals and is considering building new storage. It is doing a feasibility study on the cogeneration of electricity and steam from natural gas, expected to be completed in 2025. As part of its energy transition strategy, SIR is looking to replace fuel oil with natural gas for refinery operations and electricity generation and plans to install a mini solar power station and start biofuel production, as well as look at CO2 capture and potential hydrogen projects. ** Sogara, Gabon's sole refinery, is considering building a new hydrocracker to process the residue, which currently accounts for up to 55% of its output. The hydrocracker will allow Sogara to produce 10 ppm diesel and meet Africa's objective of moving to cleaner fuel that complies with both AFRI 6 and Euro-V emission standards and reduce residue output to around 30%. Sogara can process up to 1.2 million mt\/year but typically processes about 980,000 mt\/year. ** Senegal's SAR Dakar refinery plans to increase its capacity to 5 million mt\/year (100,000 b\/d) by 2028 and move to producing fuels that comply with both AFRI 6 and Euro 5 emission standards, a company source said. Work on the expansion project at Senegal's sole refinery is set to start around 2025-26. The refinery underwent an upgrade in 2022 during which it increased its capacity from 1.2 million mt\/year to 1.5 million mt\/year. It also increased storage capacity for crude oil and oil products, built a new preflash column and furnace which allowed it to increase capacity to 180 mt\/hour from 150 mt\/hour, and expanded catalytic reformer capacity to 18 mt\/hour from 14 mt\/hour. The upgrade was also part of the refinery's switch to being able to process Senegalese crude oil. ** Egypt's Assiut Oil Refining Co. aims to establish a crude distillation complex, with a production capacity of 5 million mt\/year and a gas recovery project for production of diesel, gasoline and butane. Separately, construction of the hydrocracker complex at Egypt's Assiut was expected to be completed in Q4 2023. The contract includes process units such as vacuum distillation, diesel hydrocracker, delayed coker, distillate hydrotreater and a hydrogen production facility. The project also includes other process units as well as interconnecting. It will transform lower value products into about 2.8 million mt\/year of cleaner products, such as Euro 5 diesel. The upgrade at Assiut includes the installation of 880,000 mt\/year continuous catalytic reforming and isomerization complex, a 400,000 mt\/year vapor recovery unit and a 2.3 million mt\/year hydrocracker. ** Expansion of Egypt's Suez refinery is being carried out, with the aim of achieving continued safe operation of production equipment in the coke complex in order to maximize output of products such as diesel, butane and gasoline for local market. ** Egypt's Nasr petroleum refining in Suez has a distillation project (CDU) and gas recovery project underway. The CDU is being established with a feeding capacity of 1.2 million mt\/year of condensate to produce naphtha, kerosene and butane. Launches New and revised entries ** Niger will shortly start a project for the construction of a new refinery, local media said citing President Abdourahmane Tchiani's televised speech. No further details were announced. The country currently has the 21,000 b\/d SORAZ refinery in Zinder. In 2018, the Niger government reached an agreement with neighbor Nigeria to build a refinery in a border town between Niger and Katsina State in northern Nigeria. However, there has been no further news on that project. Existing entries ** The new 5 million mt\/year refinery at Hassi Messaoud in Algeria will start production at the end of 2027 after the project for the facility was revived following coronavirus-related delays, local media reported July 2024, citing a Sonatrach official. Hassi Messaous will produce an additional 2.7 million mt\/year of diesel and 1.2 million mt\/year of gasoline, said the company's vice president for refining, Slimane Slimani, without providing further details. In late 2023, Algerian president Abdelmadjid Tebboune called for the refinery project at Hassi Messaoud to be revived. Algerian state-owned Sonatrach had previously expected the refinery to start operations in 2024 after construction work started at the beginning of 2020. Sonatrach has contracted the Technicas Reunidas-Samsung Engineering consortium to build the new plant. There is already a 1.1 million mt\/year simple refinery at Hassi Messaoud, which started operations in 1972. Hassi Messaoud, Biskra and Tiaret were part of the government's 2021-2024 oil sector plan, with each refinery intended to have a 5 million mt\/year capacity. The technical, architectural and land development studies for the facilities were completed in 2017. Investment decisions on the refinery's projects in Biskra and Tiaret will not be made before 2025. ** Angola's greenfield refinery in Cabinda, which is currently under construction, is expected to be commissioned by December, a company source said on the sidelines of the ARDA conference in Cape Town April 22. Local media has also suggested the plant would go online at the end of 2024. Previously, mechanical completion was expected at the end of 2023, with the first phase of 30,000 b\/d expected to be commissioned in Q1 2024. The second and third phases will see processing capacity expanded to 60,000 b\/d and the addition of a catalytic reformer, catalytic cracker and hydrotreater. Angola's new Lobito refinery will help the country reach self-sufficiency of oil-product supply and also supply nearby countries, including Zambia and South Africa, a company official said. The Lobito project, which started in 2010 and was suspended in 2016, resumed in 2023. Sonangol is still discussing with potential investors with shared ownership considered as an option. The new refinery will be technologically advanced, highly optimized and is configured to maximize production of Euro V diesel. It is aimed to process Angola's medium\/light crudes. It will be a full conversion single train refinery with a hydrocracking technology aimed to maximize diesel production. Mechanical completion is expected by the end of 2026 and production aimed for Q2 2027. In March 2024, KBR said it has been awarded a project management contract by Sonangol for the design and construction of the Lobito refinery. Separately, completion of Angola's another greenfield project, the Soyo refinery, is expected in 2027. ** South Sudan will build roads so that the Bentiu refinery is fully operational in 6-8 months, local Ecofin agency reported in April, citing a government official. The country has been looking to reopen Bentiu, the country's sole oil refinery, in order to mitigate the fuel crisis resulting from floods and linked to the fighting in neighboring Sudan. Last October, Bentiu halted output as floods made roads impassable for trucks to pick up products. The refinery will be increasing capacity to 7,000 b\/d before potentially ramping up to 10,000 b\/d. ** The secondary units at Nigeria's Dangote were \"99% complete\" and undergoing checks, a person with close knowledge of the refinery said in April. The person also said he expected the refinery's residual fluid catalytic cracker to be producing finished-grade gasoline at a steady state \"earlier\" than expected. He said that once the RFCCU is producing on-spec product, it will be able to \"reach capacity quickly.\" Dangote Industries said January 2024 that its 650,000 b\/d oil refinery had started production, starting with diesel and jet fuel and later gasoline. ** The investor selected by Uganda for the construction of its new Albertine Graben refinery has finalized all necessary agreements with Uganda's government and is expected to make a final investment decision, according to an official in April 2024. The UAE's Alpha MBM investments, which was selected in January, is in a fast-track mode to move ahead, Uganda's minister of energy and mineral development Ruth Nankabirwa told an oil and gas conference. The investor has finalized agreements including a stakeholder agreement, agreement with the host government and a crude purchase agreement. The three commercial agreements were a pre-condition before the FID could be undertaken and now the investors are working on it. The refinery's planned startup, set initially for 2023, was delayed several times, with the latest timeline setting expected commissioning for 2027. ** The new China-built Sentuo refinery in Tema, Ghana is running at just 30,000 b\/d, energy minister Matthew Opoku Prempeh told S&P Global in March 2024. Earlier, Ghana's National Petroleum Authority suspended sales of gasoline from the newly commissioned Sentuo oil refinery due to high vapor pressure. The NPA said that during a \"monitoring and verification exercise\" on Feb. 16 it noted that the product exhibited vapor pressure above the maximum requirement of the Ghana Standard of Petrol. The new refinery was officially commissioned Jan. 26 after being initially expected to start up in 2021. It started test operations last August. During the first phase, it will process 40,000 b\/d (2 million mt\/year), which will subsequently be increased by 60,000 b\/d, bringing total capacity to 100,000 b\/d (5 million mt\/year). All types of crude will be processed after Phase 2, with an output of 3.2 million mt\/year of products, including gasoline, kerosene and diesel above Euro IV standard. ** South Sudan will require several options to provide oil products including building other refineries, according to officials. A joint venture project between Safinat and the national oil and gas corporation of South Sudan, or Nilepet -- Bentiu -- is one of the five refineries with a targeted total refining capacity of 127,000 b\/d. Trinity Energy was in advanced preparations to start building a 40,000 b\/d refinery near the Palouch oil fields in the Upper Nile. One of the refineries is set to be based in Tharjiath. Nilepet is already building another refinery with the South African company Central Energy Fund to further enhance the country's refining capacity, sources said. ** Nigeria first small-scale oil refinery, the Waltersmith modular plant, will double its output capacity to 10,000 b\/d by the first half of 2025, the plant owners said December 2023. The Waltersmith modular refinery, located in the southeast Imo state, is owned jointly by local company Waltersmith Petroman Oil and the Nigerian Content Development and Monitoring Board and came on stream in October 2020, with capacity to refine 5,000 b\/d of crude. The refinery, which is being built in phases, would eventually raise capacity to 45,000 b\/d, Waltersmith said previously. ** Republic of Congo plans to have a new refinery by 2026, the country's Minister of Hydrocarbons Bruno Jean-Richard Itoua said at an industry event June 1. Works on the new plant, whose first phase is expected to be operational within two years, will start later this year. Around half, or 2 million-2.5 million mt\/year of the refinery's capacity, which is part of the first phase, will be aimed at covering domestic consumption while the remaining 2.5 million mt\/year would be aimed at producing oil products for exports. A decision had recently been taken to double the new plant's capacity, which is a private enterprise, from 2.5 million mt\/year to 5 million mt\/year. The new refinery will also be built near Pointe Noire and potentially could be combined with the existing CORAF refinery, depending on whether it is kept in operation. ** Libya has awarded Honeywell UOP a contract to help develop a 30,000 b\/d refinery at a cost of Eur600 million ($646 million), officials said in March 2023. Zallaf Libyan Oil & Gas Co, a unit of state-owned National Oil Corp, signed the contract with Honeywell UOP to develop the South Refinery, a project which has been in the works for over 30 years, the NOC said. The refinery, located in the southern city of Awbari, will process crude from El Sharara field to produce gasoline, diesel, kerosene and LPG for the domestic market, the NOC said. The project includes two phases, an initial one that consists of front end engineering and design, or FEED, to be implemented by Honeywell UOP, and a second phase for construction. ** Canadian producer Decklar Resources Inc. and Edo Refinery and Petrochemical Company Ltd. announced March 2023 an agreement to deliver an additional 150,000 barrels of crude oil to the modular Edo refinery located in southern Nigeria. Under the agreement, Decklar Resources will increase crude feedstock supply to the Edo refinery from an initial 30,000 barrels, to meet the expansion of the refinery's capacity billed to be completed in March this year, Decklar said in a statement. Edo Refinery and Petrochemical Company Ltd. said in January that the second phase of the expansion of the facility would, on completion in March, add 12,000 b\/d to raise production to 21,000 b\/d. The modular refinery can produce 50% of diesel at 500,000 liters, 25% of naphtha at 300,000 liters and 20% of Low Pour Fuel Oil at 200,000 liters. ** Nigeria's two modular facilities -- the 10,000 b\/d plant in Port Harcourt, Rivers State and the 10,000 b\/d modular refinery Ibigwe, in Imo State, -- are at various stages of completion, according to officials. ** Chad's government is considering the construction of a second refinery in the country in order to secure better domestic supply. The government \"will work to finalize feasibility studies for a second refinery and launch its construction,\" local media cited the Prime Minister Saleh Kebzabo as saying. The 20,000 b\/d N'Djamena is the only refinery operating in Chad. ** KBR has been awarded a front-end engineering design for Bua Group's new, modern refinery facility in Nigeria. Bua Group plans to build a 200,000 b\/d integrated refinery and petrochemical plant in Akwa Ibom, according to its website. The plant aims to produce Euro 5 fuels and polypropylene for the domestic and regional markets. ** Nigerian National Petroleum Corp. is close to taking a final investment decision with some investors to build a 50,000 b\/d condensate refinery. NNPC signed the front-end engineering design for the construction of the plant -- which will be in the Niger Delta -- with engineering firm KBR. NNPC first announced in August 2018 plans to build a condensate refinery with capacity to refine 200,000 b\/d of the condensate oil produced by the country. ** Nigeria has reached an agreement with neighbor Niger to build an oil refinery in a border town between Niger and Katsina state in northern Nigeria. ** The Ministry of Hydrocarbons of Guinea has signed a memorandum of understanding with logistics company United Mining Supply to set up an oil refinery. UMS has said it will conduct a feasibility study to construct a refinery in Moribayah. ** Africa Finance Corp. has signed an agreement with Brahms Oil Refineries Ltd. to co-develop a refinery and storage terminal in Guinea. AFC will work on the development and subsequent financing of a petroleum storage and associated refinery project in Kamsar, Guinea. That will include a 12,000 b\/d modular refinery, a 76,000 cu m crude oil storage terminal, a 114,200 cu m storage terminal for refined products, and ancillary transportation infrastructure. Guinea currently has no refineries. ** The construction of Republic of Congo's Atlantic Petrochemical Refinery project has begun. The government signed a deal with China's Beijing Fortune Dingsheng Investment to construct a 2.5 million mt\/year refinery in the port city of Pointe Noire. The Chinese company is also keen on launching a petrochemical complex in the country. The African oil producer has only one refinery, the 27,000 b\/d CORAF plant, also in Pointe Noire. ** Cameroon is looking to build a new refinery in the southern port city of Kribi, with a capacity of 4 million mt\/year after operations at its sole refinery in Limbe were crippled due to a major fire in 2019. Kribi has been chosen as the site as it is already home to the country's main crude export terminal. ** Equatorial Guinea's 5,000 b\/d modular oil refinery project at Punta Europa was expected to receive an FID. The government is hoping to build two modular refineries in the country, one at the Punta Europa complex on Bioko Island and the other at Cogo on the mainland. ** Benin is looking to launch the construction of a new refinery. A committee will look at the feasibility studies for the project and will also analyze the market prospects until 2030. The project will be developed as a public-private partnership. ** Russian state development bank VEB has signed investment cooperation deals with African organizations on financing a refinery in Morocco. The memorandum on the oil refinery in Morocco was signed with the Russian Export Group and Morocco's MYA Energy, part of the Marita Group. The refinery has a planned capacity of up to 5 million mt\/year. Morocco's sole refiner Samir was forced to halt processing at the Mohammedia plant in 2015 after crude oil deliveries were delayed due to financial problems. Since then, attempts to resume operations or find an investor have been unsuccessful. ** A consortium of Russian investors is planning a $4 billion project for a new refinery in northern Zambia at the site of the country's aging state-owned Indeni plant. ** Russian state-owned exploration company Rosgeologia may build a Red Sea Coast refinery in Port Sudan, which would supply landlocked countries in Africa. Sudan had started discussions to develop a 200,000 b\/d refinery on its Red Sea coast. The project's timeline has not been disclosed. The only refinery operating in the country is the Khartoum, after the Port Sudan refinery closed in 2013 and was decommissioned. ** Ghana's government has set its sights on building a 150,000 b\/d refinery in Takoradi. ","headline":" Nigerian plants in focus","updatedDate":"2024-08-06T13:54:23.000"},{"Unnamed: 0":310,"body":" Valero Energy reported flaring from Complex 1 and Complex 3 at its 195,000 b\/d McKee refinery in Sunray, Texas, as it started a planned maintenance on several units at the refinery, an Aug. 2 filing made with state regulators said. The flaring began Aug. 2 and ended Aug. 4, and was due to \"planned shutdowns for maintenance in Complex 1 and Complex 3,\" according to the filing with the Texas Commission for Environmental Quality. Among the units listed on the filing was a gasoline-making fluid catalytic cracking unit. Market sources said the scope of the work also included a crude distillation unit. Maintenance is expected to be completed by the end of August. A company spokesperson was not immediately available for comment. The McKee refinery is located on the Texas Panhandle and provides refined products to markets in Texas, New Mexico, Arizona, Colorado, Oklahoma, and Mexico via pipeline and rail. ","headline":" Valero shuts CDU, FCCU at McKee refinery for planned work","updatedDate":"2024-08-06T13:53:42.000"},{"Unnamed: 0":311,"body":" Kazakhstan is extending its ban on the export of oil products, including to the Eurasian Economic Union, for another six months, according to a draft published on the energy ministry's website Aug. 6. The ban, which first started in 2019 and covers exports of gasoline, jet fuel, diesel and gasoil by truck, was introduced to safeguard domestic supply during agricultural works and refinery turnarounds. The Eurasian Economic Union includes Russia, Belarus, Kazakhstan, Kyrgyzstan and Armenia. ","headline":"Kazakhstan extends ban on oil products exports by truck for six months","updatedDate":"2024-08-06T13:28:40.000"},{"Unnamed: 0":312,"body":" The physical Hi-Lo spread has widened to a three-month high amid prompt demand for low sulfur (1%S) fuel oil within the Mediterranean and a dearth of cargoes. The physical Hi-Lo spread \u2013 the premium of 1%S FOB NWE cargoes above their 3.5% FOB Rdam Barge counterpart \u2013 was last assessed at $16.75\/mt Aug. 5, representing the highest level since April 30. Within the paper markets, Platts, part of S&P Global Commodity Insights, assessed the front month paper Hi-Lo at $23.50\/mt Aug. 5, rising $1.25\/mt on the day to the highest level since April 24. Market participants said the otherwise thinly traded market has seen an increase in activity recently. One trader said \u201cright now [1% strength] is due to prompt demand... there is a tightness of 1% cargoes in the Mediterranean.\u201d A second trader source said the generally quiet market has seen an uptick in activity amid higher demand from utilities to meet their power generation requirements. Within the Platts Market on Close assessment process, Alkagesta has been bidding since early August for a 25,000-mt LSFO cargo on a CIF Malta basis but was unable to find a seller, further highlighting the tightness for LSFO within the region. ","headline":"Physical Hi-Lo spread hits 3 month high amid prompt LSFO demand","updatedDate":"2024-08-06T12:03:23.000"},{"Unnamed: 0":313,"body":" The Middle East sour crude complex saw cash differentials for key sour crude markers fell to fresh lows during the Singapore Platts Market on Close assessment process Aug. 6, though spot activity was thin with the October-loading cycle still in early days. Platts, part of S&P Global Commodity Insights, assessed October cash Dubai and cash Oman at a premium of 54 cents\/b to the same-month Dubai futures at the market close, all down 11 cents\/b on the day. October cash Murban was assessed at a premium of 55 cents\/b to the same-month Dubai futures, down 10 cents\/b on the day. Differentials for all the three markers were hovering at lows not seen since the end of June. During the Platts MOC process, 29 October Dubai partials of 25,000 barrels each traded. The sellers were Phillips 66, Mitsui, Reliance, Trafigura, PetroChina, ExxonMobil, BP and Unipec, and the buyers were Vitol, Glencore and Gunvor. No convergences were reached during the Platts MOC process. A convergence occurs when 20 partials are traded between two counterparties, resulting in a full 500,000-barrel physical cargo being declared from the seller to the buyer. Activity remained muted in the broader market with traders awaiting Aramco's September crude oil allocations, as well as the release of more producer official selling prices. ","headline":" Middle East sour crude cash differentials slip to fresh lows","updatedDate":"2024-08-06T10:52:50.000"},{"Unnamed: 0":314,"body":" Nigeria\u2019s state oil firm announced the introduction of a new export grade \u2013 the Utapate crude blend \u2013 on Aug. 5, taking the country\u2019s total number of crude grades to 31. In a statement, the Nigerian National Petroleum Company said exports of Utapate crude started in July from Oil Mining Lease (OML) 13, operated by NNPC\u2019s upstream subsidiary NEPL and a subsidiary of local company Sterling Oil. \u201cLocated offshore Akwa Ibom State in Nigeria, Utapate\u2019s current crude oil production is at 28,000 b\/d, with the potential to increase it to 50,000 b\/d,\u201d the state firm added. The sulfur content of the new crude is 0.0655%. \u201cSpanish oil giant Repsol won the tender for the initial cargo of 950,000 barrels of the new crude blend, which is comparable to the much sought-after Amenam crude,\u201d NNPC said. \u201cGulf Transport and Trading, another leading crude oil dealer, has also secured\u2026 tenders for August and September 2024.\u201d A source from Sterling said that OML 13 was producing \u201c25,000 b\/d and gradually increasing\u201d as of early July. The Nigerian company is owned by the Sandesara brothers, who had fled India in 2017 following allegations of defrauding public sector banks in the country. According to the Nigerian Upstream Petroleum Regulatory Commission, Utapate production was 10,000 b\/d in May and 19,000 b\/d in June. The introduction of the new grade follows the launch of Nembe crude oil, produced from OML 29 by NNPC and local company Aiteo, in 2023. \u201cSimilar to the Nembe crude oil grade, the Utapate crude oil blend has a low sulfur content and low carbon footprint due to flare gas elimination, fitting perfectly into the required spec of major buyers in Europe,\u201d NNPC said. Utapate is sweeter than Nigeria\u2019s flagship Bonny Light crude grade, which typically has a sulfur content of around 0.14%. Bonny Light was last assessed by Platts \u2013 part of S&P Global Commodity Insights \u2013 at $78.74\/b on Aug. 5, at a $2.80\/b premium to key benchmark Dated Brent. NNPC said the launch of Utapate demonstrates its ambition to boost Nigeria\u2019s crude oil production and grow the country\u2019s reserves through the development of new assets. The country has the capacity to produce some 2.2 million b\/d of crude but production has fallen since 2013 due to field maturation, technical issues, rampant oil theft by gangs in the Niger Delta and inadequate exploration activity. With majors including ExxonMobil and Eni agreeing to sell onshore and shallow water assets, local firms like Sterling, Oando and Seplat are taking over key projects. Sub-Saharan Africa\u2019s biggest producer pumped 1.5 million b\/d of oil in June, according to the latest Platts OPEC Survey from Commodity Insights. ","headline":"Nigeria launches new Utapate crude grade, first cargo heads to Spain","updatedDate":"2024-08-06T10:12:18.000"},{"Unnamed: 0":315,"body":" Tupras' refinery output in the second quarter of 2024 rose 15.2% on the quarter and on the year to 7.8 million mt, data released Aug. 5 by Turkey's largest refiner showed. The company\u2019s refinery capacity utilization was 93.5% in Q2, of which 88% was crude utilization and 5% intermediate products. This was up from Q1\u2019s utilization of 82%, of which 76% was crude oil and 6% intermediate products, and up from 83% in Q2 2023, of which 71% was crude and 12% intermediate products Production for the first half of 2024 was 12.7 million mt, up 16.5% on the year, and against a full year target of 26 million mt. Tupras said its crack refining margin for H1 2024 was $12.9\/b, above its target of $12\/b for 2024 but down from the $14.3\/b it reported for Q1. The company did not give a separate figure for Q2. Previously, the company had announced net refining margins of $9.6\/b for H1 2023 and $16\/b for 2023. Tupras said the white product yield from its Q2 output was 78.5% or 6.8 million mt, up from the 75.3%, or 5.9 million mt produced in Q1 and 73.5%, or 5.9 million mt, in Q2 2023. Of the 6.8 million mt, 32% was diesel, 22% gasoline, 16% jet, 10% bitumen and 10% fuel oil, compared with 34% diesel, 20% gasoline, 19% jet, 12% bitumen and 4% fuel oil in Q2 2023, Tupras said. Maintenance Tupras reported maintenance work at three of its four refineries during 2024. At its 227,000 b\/d Izmit plant, it reported the periodic maintenance at its Fuel Oil (residue) Conversion Unit -- scheduled for 13 weeks during Q1 -- had been completed as had the periodic maintenance of the FCC unit scheduled for six weeks in Q2. However, the company said the planned periodic maintenance of the crude oil and vacuum unit and desulfurizer -- both scheduled to take five weeks in Q4 -- had both been postponed. At its 239,000 b\/d Izmir plant, Tupras reported the completion of a periodic maintenance of the crude oil, vacuum and HYC units, scheduled to take seven weeks in Q1. A revamp of the FCC unit at Izmir slated to take 21 weeks during Q3-Q4 is still planned. Seasonal work scheduled to take 10 weeks during Q2 and Q4 on the crude oil and vacuum units at Tupras 28,000 b\/d Batman refinery, which refines Turkey's domestically produced crude, is still ongoing, the company said. Sales Tupras said its total sales in Q2 were 7.8 million mt, up 11.4% from the previous quarter, and up 6.9% on the year. Of this, 5.7 million mt was domestic sales, up 11.8% quarter on quarter and down 3.3% year on year, while exports totaled 2.2 million mt, up 15.8% on the quarter and 57.1% on the year. Half-year sales were reported at 14.8 million mt, up 8.8% on the year, with domestic sales of 10.8 million mt, down 1.8% on the year, while exports totaled 4.1 million mt, up 57.7% on the year. Tupras noted that the sharp rise in export sales compared with the same period last year was driven by a high demand for gasoline and HSFO. Tupras said it had imported 1.547 million mt of diesel and 758,000 mt of fuel oils in Q2, compared with 800,000 mt and 488,000 mt, respectively, in Q1, but did not state the origins of the imports. In its forecast for 2024, Tupras said it expected its own refining margin to be around $12\/b, down from the $14\/b it predicted for 2024 in its Q1 report, with capacity utilization of 85%-90%, compared with 87.5% reported for 2023. Tupras said it expected 2024 production at its four refineries to be 26 million mt, relatively steady from 24 million-25 million mt in 2023. It expects full-year sales at 30 million mt, slightly down from the 30.1 million mt reported for 2023. The company added that during 2024, it plans to invest a total of $256 million in polypropylene splitters for its Izmit and Izmir refineries and in a propane polypropylene storage and sales system for Izmit. Tupras said the aim of the investments is to produce high value added chemical products and to reduce the company's scope 3 emissions. Power production Tupras said power sales from the 528.6 MW generation portfolio operated by its power subsidiary Entek Elektrik in Q2 totaled 640 GWh, up 86% from Q1 and up 101% on the year. The company's portfolio consists of a 264.3 MW hydro plant, a 116 MW wind plant, a 112 MW combined-cycle gas turbine plant and a 7 MW solar plant. The company said that out of 653MW of pre-licenses it has been awarded, development of 155 MW is ongoing and \"progressing rapidly\". In June, Entek had completed a share purchase agreement for a 214 MW solar power plant in Romania currently under development. Tupras production data for Q1 2024 (million mt) Q2 2024 % change on Q1 % change on Q2 2023 Total production 6.8 15.2 15.2 Capacity Utilisation 93.5 11.4 10.5 Tupras Tupras sales data for Q1 2024 (million mt) Sales Q2 2024 % change on Q1 % change on Q2 2023 Total 7.8 11.4 6.9 Domestic 5.7 11.8 -3.3 Exports 2.2 15.8 57.1 Source: Tupras company data ","headline":" Turkish Tupras Q2 output rises 15% on the quarter and year","updatedDate":"2024-08-06T10:10:44.000"},{"Unnamed: 0":316,"body":" China\u2019s independent refineries cut crude oil imports originating from Iran in July while boosting Russian ESPO inflows in the wake of higher outflows of the grade from Russia, data collected by S&P Global Commodity Insights showed Aug. 6. Despite that, Iranian barrels remained the top choice for the independent refineries in July. The refineries, mainly the small ones in Shandong province, imported 5.48 million mt (1.3 million b\/d) of Iranian crudes in July, falling 10.1% from an eight-month high of 6.1 million mt in June. Iranian imports are usually reported as Malaysian barrels when the refineries declare inflows to the customs. ESPO imports surged 56.7% to 1.7 million mt (402,000 b\/d) in July from a 37-month low of 1.08 million mt in June. The volume excluded CNOOC\u2019s 400,000 mt of ESPO inflows via the Dongying port in Shandong, some or all of which were intended for refilling the strategic petroleum reserve. In July, the Far East Kozmino port loaded 34 Aframax cargoes bound for China, an increase from the 30 ships loaded in June. Higher loadings supported a rise in deliveries to the independent sector. ESPO blend crude is one of the most favorable barrels for Chinese state-owned and independent refiners. However, despite a rebound in ESPO volumes, the independent refineries' total feedstock imports from Russia fell 7.9% month on month and 41.7% year on year to 2.18 million mt in July. The refineries cut their combined feedstocks imports to a three-month low of 3.65 million b\/d (15.45 million mt) in July amid low utilization rates. Yulong Petrochemical's new 400,000 b\/d refinery is expected to receive three Aframax cargoes of ESPO and a cargo of Sokol in September as it prepares for startup, according to trade sources. The barrels were purchased in end-July and early-August, with ESPO cargoes transacted at discounts of 80-90 cents\/b to ICE Brent, DES Shandong, and Sokol at ICE Brent plus 50 cents\/b on the same basis. Fuel oil slumps, bitumen blend jumps The independent refiners\u2019 fuel oil imports slumped 77.7% month on month to a four-month low of 371,000 mt in July, Commodity Insights data showed. Trade sources said high imported fuel oil costs pushed some independent refineries, which do not have government permission to import crude oil, to switch to bitumen blend. As a result, bitumen blend imports -- originating from Venezuela -- jumped 14.3% month on month to an eight-month high of 1 million mt. Over January-July, bitumen blend imports were still 27.5% lower from a year earlier at 5.16 million mt, while fuel oil imports slipped 1.2% during the period to 8.52 million mt. The importers reported a combined 6.82 million mt of feedstocks from Malaysia in July, declining 4.2% from June. These barrels included Mal Blend crude, Nemina crude, fuel oil and bitumen blend, which were mainly barrels produced by Iran and Venezuela, according to trade sources. Commodity Insights collects information from trade and independent refinery sources, Kpler shipping data, shipping brokers, port sources and S&P Global Commodities at Sea , and corroborates that information with sources with direct knowledge of the matter. Top feedstock suppliers for China's independent refiners ('000 mt) Jul-24 Jun-24 Change Jul-23 Change Malaysia 6,822 7,118 -4.2% 6,256 9.0% Saudi Arabia 2,680 3,071 -12.7% 1,530 75.2% Russia 2,181 2,369 -7.9% 3,744 -41.7% Brazil 1,087 281 286.8% 685 58.7% Iraq 839 1,342 -37.5% 830 1.1% UAE 655 180 263.9% 2,192 -70.1% Kuwait 550 425 29.4% 420 31.0% Angola 280 143 95.8% 395 -29.1% US 280 129 117.1% - - Canada 80 80 0.0% - - Total* 15,454 15,413 0.3% 17,114 -9.7% Jan-Jul 2024 Jan-Jul 2023 Change Malaysia 43,269 40,360 7.2% Russia 22,956 34,054 -32.6% Saudi Arabia 19,884 12,466 59.5% Iraq 7,030 7,327 -4.1% UAE 6,176 13,111 -52.9% Brazil 4,074 3,751 8.6% Kuwait 2,139 2,230 -4.1% Angola 1,358 1,062 27.9% Qatar 675 - - US 671 1,251 -46.4% Total* 109,918 122,077 -10.0% Top feedstock imports for China's independent refiners ('000 mt) Crude Jul-24 Jun-24 Change Jul-23 Change Mal Blend 5,364 6,099 -12.1% 2,209 142.9% ESPO 1,696 1,082 56.7% 2,300 -26.3% Arab Light 1,241 1,102 12.6% 135 819.3% Arab Heavy 1,124 978 14.9% 716 57.0% Basrah Heavy 699 564 23.9% 280 149.6% Khafji 550 425 29.4% 140 292.9% Sepia 543 141 285.1% 203 167.5% Upper Zakum 390 110 254.5% 1,552 -74.9% Nemina 272 - - 239 14.0% Tupi 270 - - 203 33.0% Subtotal* 14,083 13,599 3.6% 14,675 -4.0% Bitumen Blend 1,000 875 14.3% 775 29.0% Fuel Oil 371 939 -60.5% 1,664 -77.7% Total feedstock* 15,454 15,413 0.3% 17,114 -9.7% Crude Jan-Jul 2024 Jan-Jul 2023 Change Mal Blend 30,169 19,391 55.6% ESPO 13,149 18,976 -30.7% Arab Light 8,619 2,885 198.8% Arab Heavy 6,378 6,962 -8.4% Basrah Medium 3,952 3,134 26.1% Basrah Heavy 3,078 3,078 0.0% Sokol 3,018 1,221 147.2% Arab Extra Light 2,796 1,219 129.4% Upper Zakum 2,460 8,917 -72.4% Arab Medium 2,091 1,680 24.5% Subtotal* 96,237 106,332 -9.5% Bitumen Blend 5,163 7,122 -27.5% Fuel Oil 8,518 8,623 -1.2% Total feedstock* 109,918 122,077 -10.0% *Includes imports from other countries, and other grades Source: S&P Global Commodity Insights ","headline":" Independent refineries\u2019 Iranian crude imports fall in July, ESPO inflows rebound","updatedDate":"2024-08-06T10:08:15.000"},{"Unnamed: 0":317,"body":" Independent commodity trader Gunvor has agreed to purchase TotalEnergies\u2019 50% stake in Total PARCO Pakistan, a fuel marketing company, the companies said Aug. 6. Total PARCO Pakistan is a 50\/50 joint venture between TotalEnergies Marketing and Services and Pak-Arab Refinery Limited (PARCO) in Pakistan with a retail network of more than 800 service stations, fuel logistics and lubricants activities. \"The transaction reflects the selective strategy of TotalEnergies in Marketing & Services focused on core geographies with growth and transitioning opportunities,\" TotalEnergies said in a statement. Following the transaction, the new entity will continue its retail business under the existing \u201cTotal Parco\u201d brand and its lubricants business under the \u201cTotal\u201d brand for five years in Pakistan. No financial details of the transaction were given. ","headline":"Gunvor acquires TotalEnergies' 50% stake in Pakistan retail fuel business","updatedDate":"2024-08-06T09:18:23.000"},{"Unnamed: 0":318,"body":" Coal is poised to remain a dominant power fuel in India for nearly two decades despite popular belief that renewables will be fueling majority of power in Asia, and primarily India, as huge investment required to build green capacities and intermittent nature of renewables will likely remain a roadblock, according to Vuslat Bayoglu, managing director of South African mining company Menar. \"Rate of population growth in India commands higher-than-ever energy requirements, and to meet such heightened demand coal has to remain the mainstay for decades to come, even as renewables will see their fair share of growth. However, baseload power cannot be neglected, and coal will continue to drive that in India as the question revolves around not just energy needs but also reliability and uninterrupted supply, which unfortunately cannot come from renewables that easily in countries like India,\" Bayoglu said. According to Bayoglu, transition to renewables has a different meaning when put in an Asian context. \"It is a requirement, of course, but it should not come at a cost of depriving people of basic energy needs,\" he said, adding that Asian economies will be equipped to deal with it, but there should not be a timeline pressure, as affordability is a big concern in deploying renewable energy sources. Meanwhile, investments that have gone into coal cannot be done away with without a proper realization of returns, he said, referring to coal-based plants across Asia that are newly built and are far from their lifecycle-end. \"There should also be talks around how to lower emissions from coal-based power and non-power sectors as they are the ones securing supply for many years to come, and how coal will always remain a baseload fuel even if renewables grow at an expected rate in Asia.\" India to drive energy sector spending Menar, which has interests in coal, nickel, gold, and manganese, among others, looks at India as having an even higher say in overall energy commodities' pricing structure as well as driving the demand fundamentals, particularly for coal in the international waters. Menar's coal production capacity stands at about 7 million mt\/year through subsidiaries and investments. \"A growing India is beneficial for the entire world, as demand centers will be the ones shaping a global trade narrative, especially when geopolitical risks have become a norm. Over the next few years, India will likely compete with China even more strongly as far as trade dominance is concerned,\" Bayoglu said. While India's crude oil import bill fell in the last fiscal 2023-24 (April-March) due to lower international prices in the post-war stabilization year, import dependency hit a new high of over 87.7%, according to Petroleum Planning and Analysis Cell (PPAC) data, amid rise in population, rapid economic growth, and scaling up of infrastructure and industrial sectors. Coal imports also rose to a record over 260 million mt last fiscal, keeping overseas reliance to over 25% of the total consumption, and gradually narrowing the gap with Chinese coal imports that stood at over 450 million mt last year. South Africa's logistics snag on recovery path While South African coal is preferred in markets like India, Pakistan, parts of Europe and China, domestic transportation trouble with state-owned freight operator Transnet, frequent rail line disruption, and issues of theft and burglary have collectively contributed to supply-chain inefficiency over the years, leading to underutilized export potential. Bayoglu, however, believes the government along with other relevant stakeholders are working on plans to improve the logistics shortcomings, including increasing the number of trains, fixing line efficiency and bolster security. \"Logistics problems are a part of every country, and while I agree it has impacted South Africa more, I see improvement on the ground and in about 2-3 years, we'll be able to get rid of many transportation and allied problems to be able to ship more products outside of the country,\" he added. ","headline":" Coal to remain a dominant power source in India: Menar MD","updatedDate":"2024-08-06T09:05:27.000"},{"Unnamed: 0":319,"body":" Crude oil futures hung on to early gains through midafternoon Asian trade Aug. 6 after a volatile trading session though analysts warned that prevailing demand concerns are likely to cap gains. At 3:15 pm Singapore time (0715 GMT), the ICE October Brent futures contract was up 41 cents\/b (0.54%) from the previous close at $76.71\/b, while the NYMEX September light sweet crude contract rose 57 cents\/b (0.78%) at $73.51\/b. Global financial markets attempted to stabilize after a volatile start to the week that saw a broad move away from risk assets such as oil futures. \"It seems we've caught a brief respite as some of the falling knives have finally hit the floor,\" said SPI Asset Management's managing partner, Stephen Innes. The rebound Aug. 6 was broadly attributed to supply-side concerns following the shutdown of Libya\u2019s largest oilfield and geopolitical developments in the Middle East. Resilient US services data overnight also offered some support for prices and bolstered a broad-based recovery in risk sentiment, IG's market analyst, Yeap Jun Rong, told S&P Global Commodity Insights. \"Oil prices have been attempting to stabilize from recent rout ... but that is weighed against geopolitical developments in the Middle East, where initial retaliation from Hezbollah has been more contained than what some expect,\" he continued. \"For now, concerns around US growth risks are eased by resilience in US services activities, but it may have to take more to reassure markets of a stronger global demand outlook for oil. Until then, gains in oil prices may seem more limited.\" Overarching worries over demand from China, the world's largest importer of crude, continued to cap gains to crude prices, ING's commodity analysts said Aug. 6. \"Investors have been exiting commodities in recent weeks, highlighted in positioning data and this has continued in recent days,\" they added, noting a steady decline in open interest in ICE Brent futures contracts since mid-June that reflected a souring speculative appetite. Investors await China's trade data due Aug. 8 which will be the next key Asian economic data point this week for commodity markets. The country's crude inflows had slipped 10.8% on the year in June with poor refining margins and soft refined product demand said to cap gains through July, sources said. Dubai crude Dubai crude swaps and intermonth spreads were mixed in midafternoon Asian trading Aug. 6 from the previous close. The October Dubai swap was pegged at $75.13\/b at 2 pm Singapore time (0600 GMT), up $1.29\/b (1.75%) from the previous Asian market close. The September-October Dubai swap intermonth spread was pegged at 43 cents\/b, down 2 cents\/b over the same period, and the October-November intermonth spread was pegged at 31 cents\/b, up 1 cent\/b. The October Brent-Dubai exchange of futures for swaps was pegged at $1.93\/b, up 11 cents\/b. ","headline":" Crude price holds steady as demand expectations cap gains","updatedDate":"2024-08-06T07:16:44.000"},{"Unnamed: 0":320,"body":" Term contractual ex-wharf 380 CST high sulfur fuel oil at the UAE\u2019s bunker hub of Fujairah for August were inked at premiums of around $6-$8\/mt to Mean of Platts Arab Gulf 180 CST HSFO assessments, traders said Aug. 6, as some sellers were keen to draw down stockpiles. Some of the August-loading term contract HSFO ex-wharf cargoes were also concluded at premiums around the low-teens, according to traders, while intense competition among suppliers around the UAE\u2019s bunker hub of Fujairah also pressured downstream valuations. Previously, most of the HSFO ex-wharf term contract barrels for July were signed at higher premiums of around $8-$15\/mt premiums, traders said. \u201cHSFO [cargo] availabilities are okay. There can be wide range of premiums seen often due to various origins and strategies that suppliers employ to procure cargoes,\u201d a Fujairah-based trader said. The Platts-assessed Fujairah-delivered 380 CST HSFO bunker premium to FO 380 CST 3.5% FOB Arab Gulf cargoes declined to an average of $23.92\/mt in July and has inched up to $25.37\/mt so far in August, but still far below the $31.79\/mt average in June. \u201cMore players are getting into the HSFO space,\u201d a Fujairah-based bunker supplier said, suggesting that downstream competition has intensified in the region. According to local traders, some flat price sellers have reportedly offered aggressively to capture inquiries consisting of substantial requirements, undercutting the rest of their competitors with by fairly wide margins. \u201cRecently, competition has been tough, we have even lost all inquiries today,\u201d another bunker supplier said, adding that deals were inked at low premiums even for prompt refueling dates. In addition to the ample HSFO inventories, downstream barging schedules for early refueling requirements were mostly available within same-day to three-day lead times, as buyers could secure bunkers promptly. Supply adequate, healthy demand Higher HSFO inflows in H2 July kept inventories well-supplied, while at least two cargoes totaling approximately 734,000 barrels, or 116,000 mt, of HSFO reportedly hailing from Iran and Russia, were expected to land in Fujairah around early-August period, according to industry sources. HSFO consumption from regional utility sectors rose during the peak summer season in the Middle East to strengthen valuations for part of Q2 and Q3 period, though traders in the region also said that the demand and supply dynamics were \u201cbalanced\u201d since July, compared to tighter stockpiles earlier in Q2. Stockpiles of heavy residues around Fujairah hub, consumed for power generation purposes and as ship fuel, climbed 3% on the week to a two-week high of 9.702 million barrels in the week ended July 29, latest data from the Fujairah Oil Industry Zone showed. HSFO demand around Fujairah were seen rather decent, or above-average, on most trading days recently, as discounts against prices at Singapore widened significantly owing to tighter-than-usual barging schedules around the world\u2019s largest bunkering hub, bunker suppliers said. As a result, traders in Singapore also noted that some volumes of spot HSFO inquiries were lost to competitive offers available in Fujairah, especially for tankers with the option to refuel in the Middle East or plying along the Arab Gulf-Asia routes. \u201cSuppliers [in the UAE] are facing a difficult market and high level of competition\u2026 Nevertheless, buyers are winners in these conditions,\u201d a second trader said. Spreads between Singapore delivered marine fuel 0.5%S prices versus the same delivered grade at the UAE\u2019s bunker hub of Fujairah most recently widened to an over four-month high of $27\/mt July 30, before narrowing to $18\/mt Aug. 5, Commodity Insights data showed. Prior to July 26, this HSFO delivered spread between both hubs were last assessed wider at $29\/mt March 14 earlier this year. Moreover, HSFO delivered price spreads between both key hubs averaged $19.33\/mt Aug. 1-5, compared with $15.52 in July. Platts is part of S&P Global Commodity Insights. ","headline":"Fujairah\u2019s HSFO August HSFO ex-wharf premiums slip; stocks adequate","updatedDate":"2024-08-06T07:05:38.000"},{"Unnamed: 0":321,"body":" Japan's US crude imports in March more than doubled year on year and nearly quadrupled from February to 3.01 million barrels, according to preliminary data released April 30 by the Ministry of Economy, Trade and Industry, at a time when US barrels were competitive against Middle East supplies and as the country increases its efforts to diversify supply. Imports from the US jumped in March as Japan's dependency on Middle East crude slid to 94.7% from 96.6% in March 2023, marking the sixth year-on-year decline, led by reduced imports from Saudi Arabia, Kuwait and Qatar, according to METI data. Japan imported from the US in March 2.05 million barrels of WTI Midland crude and 966,761 barrels of Mars crude for a total of 3.01 million barrels, or 97,257 b\/d. US supply accounted for 4.1% of Japan's total crude imports and was the fourth-largest supplier in the month. On a CFR North Asia basis, US WTI Midland crude's premium over the UAE's Murban crude averaged 22 cents\/b in December, when North Asian refiners were purchasing March-arrival cargoes, a relatively narrow spread that likely allowed some system barrel sellers to move some cargoes to Japan, according to S&P Global Commodity Insights data. Japan's ENEOS Holdings said Feb. 9 it was exploring procuring crude from the US as well as from Central and South America as part of efforts to diversify its sources of crude supply, given its high dependency on Middle East crudes and amid heightened tensions in the region. Feedstock managers at two major refiners and trade sources at a Japanese integrated trading company said that since the country relies heavily on Middle Eastern sour crude, the recent tensions ignited by Iran's attack on Israel earlier in April was a major feedstock security concern and they would consider reaching out to their regular US crude suppliers and trading firms for a potential increase in spot purchases, at least through the next few trading cycles. \"Events like these should seriously kick-start supply diversification efforts, perhaps starting off with more US crude buying,\" a crude and condensate trader at a Japanese integrated trading firm said. Ecuador was the sixth-largest crude supplier to Japan in March, with inflows of the country's Napo crude in March up 13.9% year on year at 699,986 barrels, or 22,580 b\/d, according to METI data. The UAE remained Japan's top crude supplier in March, with imports from the country averaging 1.055 million b\/d, up 9.8% year on year, followed by Saudi Arabia, down 7.2% year on year at 989,492 b\/d. Imports from Kuwait and Qatar, respectively the third- and fifth-largest suppliers of crude to Japan in March -- dropped 22.1% and 67.8% year on year to 171,858 b\/d and 50,272 b\/d. Yen depreciation Meanwhile, middle distillate marketers were assessing how the marked weakness of the yen could affect jet fuel sales in the short to medium term. The currency's weakness could significantly reduce overseas travel demand as the global purchasing power of local consumers has deteriorated. However, tourist arrival numbers could see a big boost as foreign holiday seekers and travelers aim to make most of the weak local currency, a product sales and marketing source at Cosmo Oil said. \"A weak yen does not bode well for [Japanese] refiners' feedstock crude purchases but it would work in favor of jet fuel sales and middle distillate exports,\" he said. \"It would be interesting to see major city airports' inbound overseas passenger numbers throughout the second quarter.\" Japan's jet fuel sales in March slid 16.2% year on year to 73,433 b\/d, while sales of kerosene, which has similar specifications to jet fuel, surged 37% to 322,452 b\/d as a result of below-average temperatures in the month. Jet fuel exports in March fell 9.6% year on year to 130,868 b\/d, while gasoline exports rose 6.4% to 117,392 b\/d. Gasoline imports averaged at 47,549 b\/d in March, more than triple the 14,135 b\/d of March 2023, while domestic gasoline sales inched up 0.5% year on year to 742,114 b\/d. Japan's top 10 crude suppliers: Countries Mar 2024 (b\/d) Share (%) Mar 2023 (b\/d) % chg on year Feb 2023 (b\/d) % chg on month United Arab Emirates 1,055,483 44.1 961,274 9.8 1,077,822 -2.1 Saudi Arabia 989,492 41.3 1,066,321 -7.2 938,265 5.5 Kuwait 171,858 7.2 220,512 -22.1 183,933 -6.6 United States of America 97,257 4.1 43,599 123.1 27,092 259.0 Qatar 50,272 2.1 156,287 -67.8 134,344 -62.6 Ecuador 22,580 0.9 19,828 13.9 41,722 -45.9 Australia 6,963 0.3 0 n\/a 0 n\/a Oman 1,982 0.1 0 n\/a 32,243 -93.9 Brunei 0 0.0 9,683 n\/a 10,807 n\/a Bahrain 0 0.0 16,149 n\/a 0 n\/a Other 0 0.0 13,293 n\/a 0 n\/a Total 2,395,888 100.0 2,506,946 -4.4 2,446,227 -2.1 Countries Jan-Mar 2024 Jan-Mar 2023 % chg on year United Arab Emirates 1,049,586 943,353 11.3 Saudi Arabia 955,948 1,149,885 -16.9 Kuwait 178,801 262,078 -31.8 Qatar 88,922 152,217 -41.6 United States of America 86,248 48,499 77.8 Ecuador 28,609 21,530 32.9 Oman 16,419 27,713 -40.8 Australia 5,332 2,583 106.4 Bahrain 5,211 16,750 -68.9 Brunei 3,444 6,670 -48.4 Other 4,872 18,864 -74.2 Total 2,423,392 2,650,144 -8.6 Japan's oil product sales (Unit: b\/d): Mar-24 Mar-23 % Change Feb-24 % Change Gasoline 742,114 738,422 0.5 720,623 3.0 Naphtha 581,341 689,610 -15.7 681,703 -14.7 Jet Fuel 73,433 87,629 -16.2 75,972 -3.3 Kerosene 322,452 235,367 37 372,312 -13.4 Gasoil 536,566 541,985 -1 535,622 0.2 Fuel Oil A 203,741 205,799 -1 206,543 -1.4 Fuel Oil B, C 100,611 146,025 -31.1 114,678 -12.3 Total 2,560,259 2,644,896 -3.2 2,707,453 -5.4 Jan-Mar 2024 Jan-Mar 2023 % chg on year Gasoline 717,892 729,056 -1.5 Naphtha 646,856 679,626 -4.8 Jet Fuel 71,861 70,101 2.5 Kerosene 361,679 367,928 -1.7 Gasoil 514,490 526,303 -2.2 Fuel Oil A 198,884 212,944 -6.6 Fuel Oil B, C 112,763 188,253 -40.1 Total 2,624,425 2,774,390 -5.4 Japan's oil product imports (Unit: b\/d): Mar-24 Mar-23 % Change Feb-24 % Change Gasoline 47,549 14,135 236.4 30,200 57.4 Naphtha 424,415 443,949 -4.4 441,635 -3.9 Jet Fuel 0 n\/a n\/a 2,547 n\/a Kerosene 20,830 18,988 9.7 52,592 -60.4 Gasoil 4,502 5,585 -19.4 6,238 -27.8 Fuel Oil A 0 n\/a n\/a 0 n\/a Fuel Oil B, C 5,615 33,029 -83 7,134 -21.3 Total 502,911 515,806 -2.5 540,347 -6.9 Jan-Mar 2024 Jan-Mar 2023 % chg on year Gasoline 46,772 22,786 105.3 Naphtha 433,341 428,266 1.2 Jet Fuel 812 3,231 -80.0 Kerosene 50,321 55,882 -10.0 Gasoil 7,524 5,419 38.9 Fuel Oil A 0 0 n\/a! Fuel Oil B, C 9,306 42,257 -78.0 Total 548,076 557,690 -1.7 Japan's oil product exports (Unit: b\/d): Mar-24 Mar-23 % Change Feb-24 % Change Gasoline 117,392 110,331 6.4 105,733 11.0 Naphtha 1,187 n\/a n\/a 1,035 14.8 Jet Fuel 130,868 144,766 -9.6 126,025 3.8 Kerosene 2 19,963 -100 3 -53.2 Gasoil 141,533 129,018 9.7 79,811 77.3 Fuel Oil A 141 1,986 -92.9 123 14.7 Fuel Oil B, C 170,258 148,567 14.6 158,290 7.6 Total 561,381 543,974 3.2 471,021 19.2 Jan-Mar 2024 Jan-Mar 2023 % chg on year Gasoline 100,560 120,909 -16.8 Naphtha 1,538 0 n\/a Jet Fuel 132,772 121,902 8.9 Kerosene 4 19,963 -100.0 Gasoil 103,271 150,364 -31.3 Fuel Oil A 135 2,898 -95.4 Fuel Oil B, C 154,462 147,952 4.4 Total 492,742 560,936 -12.2 Source: Ministry of Economy, Trade and Industry ","headline":" US crude imports more than double in March as Middle East dependency eases","updatedDate":"2024-08-06T05:32:05.000"},{"Unnamed: 0":322,"body":" The volume of Dubai crude oil futures contracts traded on the Tokyo Commodity Exchange rebounded 5.89% on the month to 124,754 lots in July, the latest TOCOM data showed. The traded volume of the contracts in June was the lowest on record, according to TOCOM data going back to July 2020. The uptick followed the return of Asian refineries from maintenance season, which restored some capacity despite poor margins and tepid domestic demand. Reflecting the weak backdrop, July's traded volume was still 12.4% lower than the 142,406 lots traded in July 2023, the data showed. Nevertheless, the Dubai complex saw some support from a largely closed arbitrage window for light, sweet US crudes to Asia, while a wider Brent-Dubai exchange of futures for swaps spread also hindered the flow of Brent-linked crudes from West Africa, Europe and the Mediterranean into the region. The Brent-Dubai EFS spread, meanwhile, widened in the first half of July, reaching a four-month high of $2.48\/b on July 19. The spread was last wider March 4, when it was assessed at $2.54\/b. On the physical front, 53 Dubai partials traded during the Platts Market on Close assessment process over the first three trading sessions in August, a significant increase from the 9 partials traded during the same period the previous month. The M1 Dubai swap settled at $84.99\/b at the start of July and ended the month 7.25% lower at $78.83\/b, S&P Global Commodity Insights data showed. Platts assessed the September Brent-Dubai EFS at $1.61\/b on July 31, up 23 cents\/b, or 16.67%, from July 1, the data showed. Dubai crude oil futures traded on TOCOM: July '24 June '24 M-o-M Change July '23 Y-o-Y Change Dubai crude oil 124,754 117,817 6,937 5.89% 142,406 -17,652 -12.40% Source: Tokyo Commodity Exchange ","headline":"Dubai crude futures traded volume on TOCOM rebounds in July from record low","updatedDate":"2024-08-06T03:49:45.000"},{"Unnamed: 0":323,"body":" Spot prices traded on the Japan Electric Power Exchange retreated for the first time in three days for Aug. 7, with the 24-hour day-ahead price dropping 8.4% on the day to Yen 14.70\/kWh as temperatures are forecast to ease. The JEPX 24-hour day-ahead price fell to Yen 16.05\/kWh for Aug. 6 after rising for the second consecutive day, following drops over the weekend when power demand is lower than on weekdays. Tokyo is forecast to experience maximum 32 degrees Celsius for Aug. 7, with cloudy skies and occasional rain, compared with 33 C for Aug. 6, according to the Japan Meteorological Agency. The temperatures in Tokyo, which has been a driver for incremental power demand in so far this summer, are down from occasional levels above 35 C in recent weeks. Lower temperatures have also boosted TEPCO Power Grid's supply capacity over demand in recent days. The company expects its Tokyo area demand to peak at 50.88 GW with a supply capacity of 56.24 GW, resulting in a 10% surplus during an hour to 2 pm local time (0500 GMT) Aug. 6. The country's power demand, meanwhile, is also slated to slow with the upcoming Obon summer holidays next week. Japan's LNG stocks held by major utilities retreated 8.5% on the week to 2.15 million mt as of July 28, the Ministry of Economy, Trade and Industry said July 31, marking the first drop in three weeks. ","headline":"Japan's spot electricity price retreats 8% as temperatures ease","updatedDate":"2024-08-06T02:40:13.000"},{"Unnamed: 0":324,"body":" Hong Kong's imports of refined oil products rose 31.96% on the month but edged 2.12% lower on the year, to 1.42 million kiloliters, or 226,475 barrels, in June, with the gains led by jet fuel\/kerosene, the most recent Census and Statistics Department data showed. The Census and Statistics Department publishes data in kiloliters, which S&P Global Commodity Insights converts to barrels using a factor of 6.2898. Hong Kong\u2019s jet fuel\/kerosene inflows climbed 34.51% on the month, and 4.69% on the year, to 556,993 kiloliters in June. The rise in jet fuel\/kerosene imports tracks expansion in Hong Kong's flagship carrier Cathay Pacific Airways\u2019 passenger traffic, which rose 9.52% on the month, and 18.7% on the year, to 1.84 million travelers in June, the company said. \u201cFollowing a slightly quieter month in May, travel sentiment rebounded in June with leisure travel on both long-haul and short-haul routes performing well,\u201d Cathay's Chief Customer and Commercial Officer Lavinia Lau said in a statement. Notably, Cathay Pacific, along with its low-cost carrier HK Express, carried about 92,000 passengers combined on June 30, marking the highest daily number of travelers since the pandemic. The increase in passenger numbers contributed to the slight strengthening of the regional jet fuel\/kerosene complex, with the Platts-assessed FOB Singapore jet fuel\/kerosene outright price averaging $97.33\/b in June, rising from $95.43\/b in May, S&P Global Commodity Insights data showed. Meanwhile, Hong Kong\u2019s gasoline imports fell 30.87% on month, and 33.15% on year to 28,171 kiloliters in June, the data showed. The fall in Hong Kong\u2019s gasoline inflows was likely due to the holiday period, with most people travelling out of Hong Kong during the monsoon season in June, market sources said. Platts assessed FOB Singapore 92 RON at an average of $87.93\/b in June, down from $91.13\/b in May, S&P Global data showed. Imports of gasoil, diesel and naphtha slipped 2.42% on the month and 7.20% on the year to 301,610 kiloliters, amid an uptick in prices. Naphtha prices surged slightly higher on the back of lower arbitrage volumes into Asia in June. The Platts-assessed C+F Japan naphtha price rose slightly to an average of $681.30\/mt in May, up $5.03\/mt from the average of $676.27\/mt in May, S&P Global data showed. The benchmark Platts FOB Singapore 10 ppm sulfur gasoil outright price at an average of $98.09\/b in June, up from $97.32\/b in May, according to S&P Global data. Gas inflows reach 11-month high Hong Kong imported 395,524 mt of natural gas in June, an 11-month high, but 12.61% higher from a year earlier and up 2.12% from May, the data showed. LPG inflows, on the other hand, were up 12.75% on the month but slumped 20.34% on year in June at 24,043 mt. Platts assessed CFR North Asia propane at an average of $629.45\/mt in June, up from $620.02\/mt in May, Commodity Insights data showed, while CFR North Asia butane was assessed at an average of $612.50\/mt in June, from $610.79\/mt in May. Hong Kong's gas imports are likely to continue their upward trend during the summer months which start from early-May to late-September when demand for LPG and natural gas is typically strong for electricity generation to power air conditioners. Hong Kong's Census and Statistics Department releases LPG and natural gas data in metric tons. ","headline":" June oil product imports surge 32% on month to 226,475 barrels","updatedDate":"2024-08-05T23:12:38.000"},{"Unnamed: 0":325,"body":" Rio Grande LNG developer NextDecade signed an engineering, procurement and construction contract with Bechtel for a proposed Train 4 expansion of the Texas facility that it expects to commercially sanction by the end of 2024, the companies said Aug. 5. Under the lump sum turnkey EPC contract, NextDecade agreed to pay Bechtel about $4.3 billion for the work on Train 4 and related infrastructure, the companies said. Total estimated project costs are expected to be $6 billion-$6.2 billion, including $1.7 billion-$1.9 billion owner\u2019s costs, contingencies, financing fees and interest during construction. NextDecade also maintained its target for reaching FID on Train 4 by the end of the year, having built significant commercial momentum in recent months. The three-train first phase of the Rio Grande LNG terminal is already under construction in Brownsville, Texas, after NextDecade reached a final investment decision on the 17.6 million mt\/year project in July 2023. Bechtel is also NextDecade\u2019s EPC contractor for that project. A total of five trains have been proposed, which would bring the terminal\u2019s production capacity to about 27 million mt\/year at full construction. In May, NextDecade struck an equity and offtake deal with the UAE\u2019s ADNOC covering 1.9 million mt\/year of volumes from Train 4. It was the first binding sale and purchase agreement tied to the expansion project. The US developer in June signed a preliminary deal with Saudi Aramco that called for negotiating a binding agreement with the state-run oil giant for 1.2 million mt\/year. NextDecade has said it is targeting deals covering about 4.5 million mt\/year from each of the expansion trains in order to reach FID. The company in June said it expects France's TotalEnergies will exercise its option for 1.5 million mt\/year from Train 4, meaning the deal with Aramco, if finalized, \"would give us sufficient commercial support for a Train 4 FID.\" ","headline":"NextDecade signs contract with Bechtel to build Rio Grande LNG expansion","updatedDate":"2024-08-05T21:39:02.000"},{"Unnamed: 0":326,"body":" Kosmos Energy had its share of operational stumbles in the second quarter, with a delayed startup of the Winterfell field in the US Gulf of Mexico and an underperforming well in Ghana, although the company is confident it will make its year-end goal of 90,000 b\/d of oil equivalent, Kosmos' top executive said Aug. 5. \"Two years ago we announced a target to grow production by around 50%, driven largely by the delivery of three important projects \u2013 Jubilee Southeast in Ghana, Winterfell in the Gulf of Mexico and GTA,\" an LNG project on the Mauritania-Senegal border, Kosmos CEO Andy Inglis said in a Q2 earnings conference call. \"We're around halfway to achieving that target with the successful startup of Jubilee Southeast and Winterfell alongside production enhancement projects in the Gulf of Mexico,\" he said. Also, later this year Inglis said startup of the first phase of the GTA \u2013 Greater Tortue Ahmeyim LNG project \u2013 is expected while the infill drilling campaign in Equatorial Guinea should contribute to Kosmos' year-end output goal of around 90,000 boe\/d of oil. GTA represents a 2.3 million mt\/year offshore LNG export project, with estimated reserves of 15 Tcf. First LNG is expected in Q4, Kosmos said. The company's Equatorial Guinea project at the Ceiba and Okume fields are also expected to contribute to higher Q4 production as an infill drilling campaign in that country has now begun, Inglis said. Added Equatorial Guinea wells should raise output Two infill wells at those Equatorial Guinea fields, one already drilled, should add around 3,000 b\/d of oil net to Kosmos' 2024 exit rate. And an infrastructure-led prospect, Akeng, should also spud after those two wells, with results expected by year-end 2024. Kosmos' second quarter net production from Equatorial Guinea was about 8,500 b\/d of oil, about flat with 8,400 b\/d in the same year-ago quarter. The company's total production in Q2 2024 was 62,100 boe\/d, up 7% year over year. Kosmos' Q2 2024 production was about the same as it was in Q2 2022 when it set its year-end 2024 output target. The year-over-year growth in Q2 2024 reflects higher production in Ghana following completion of a three-year infill drilling campaign, although this was offset by lower US Gulf production from planned downtime and a delay to startup of Winterfell, where a third well is slated to come online by the end of Q3. The three initial Winterfell wells are expected to deliver total gross production of roughly 20,000 boe\/d, according to Kosmos, which has a 25% stake in the field. Winterfell didn't come online until early July \u2013 following a \"slight delay\" in work after drilling the first two wells and subsea hookup in April 2024, Inglis said during the project's debut. Two more Winterfell wells eyed Two additional Winterfell wells are planned for Phase 1 of the project, where the partners have targeted around 100 million boe of gross recoverable resource. Beacon Offshore Energy operates the field. Kosmos' Q2 net US Gulf production was 11,700 boe\/d, down 26% from the same 2023 period. In addition, an underperformance from the J-69 well at Ghana's Jubilee field in Q2 caused a slower-than-expected ramp-up in the field, as did a temporary reduction in water injection, Inglis said. A new production well drilled during Q2 should boost output in that region, along with new 4-D seismic to be shot in early 2025 which should identify better wells for the 2025-2026 drilling campaign. Also, a Jubilee water injector well was drilled in Q2 to remedy the reduced output in water injection. In Q2, Kosmos' net production in Ghana averaged around 42,000 boe\/d, up from 33,700 boe\/d in the same three months of 2023. \"Not every well will match expectations and J-69 has certainly had an impact on this year's production level,\" Inglis said. \"But the three-year [drilling] program was done on 4-D seismic data that is now almost eight years old,\" Inglis said. \"Technology has moved on massively over time,\" he said. \"I\u2019m confident that there will be a significant uplift in the seismic data which will allow us to drill [a] high-quality set of development wells when we restart the program in 2025.\" ","headline":"Kosmos sees 2024 total output of 90,000 boe\/d, despite Q2 operations thorns: CEO","updatedDate":"2024-08-05T20:52:58.000"},{"Unnamed: 0":327,"body":" Dated Brent was assessed at two-month lows Aug. 5 as various contracts in the Brent complex dropped value on the day, amid a wider patch of economic weakness. Platts, part of S&P Global Commodity Insights, last assessed Dated Brent at $76.70\/b, down $2.26\/b on the day, its lowest level since June 5, when the global crude benchmark was assessed at $75.92\/b. This follows dives in other key oil prices, including ICE Brent futures and front-month Cash BFOE -- the latter of which reached a six-month low Aug. 5. Platts last assessed M1 Cash BFOE at $76.45\/b, its lowest level since January 8, when the contract was assessed at $75.66\/b. Cash BFOE represents the price of cargoes of Brent, Forties, Oseberg, Ekofisk, Troll and WTI Midland trading in the two- to four-month ahead forward market, and is a key component in the Brent complex. ","headline":"Dated Brent reaches two-month low Aug. 5 as physical, derivatives prices slide on day","updatedDate":"2024-08-05T19:13:27.000"},{"Unnamed: 0":328,"body":" Alaska North Slope production was up marginally in July over June, but otherwise reflected normal seasonal dips along with a long-term decline expected in mature producing fields, according to production data from the Alaska Department of Revenue available Aug. 5. Production totaled 445,995 b\/d on average from North Slope producing fields in July, up from 439,255 b\/d in June, but down from 460,616 b\/d in May. A summertime dip in production is typical on the North Slope because oil and gas processing plants are less efficient as temperatures warm from colder winter months. In January, output from the slope averaged 475,081 b\/d, for example. Comparing performance of four producing regions in the revenue department data -- the regions roughly correlating to larger producing fields -- the Prudhoe Bay field operated by Hilcorp Energy showed an increase of 6,740 b\/d in July over June. The Kuparuk River producing region, west of Prudhoe Bay, also showed a rise in July of 5,835 b\/d on average over June, according to the data. This includes the Kuparuk River field, but also the smaller Oooguruk and Nikaitchuq fields. ConocoPhillips is operator at the Kuparuk field, while Eni Oil and Gas is operator at Oooguruk and Nikaitchuq. Eni is in the process of selling the Oooguruk and Nikaitchuq fields to Hilcorp Energy, the companies have announced . In contrast, the Alpine field, owned and operated by ConocoPhillips, lost production in July, down 3,444 b\/d from June on average. Alpine is the farthest west of the larger North Slope producing fields and is adjacent to the Colville River, the boundary between state-owned lands and the federal National Petroleum Reserve-Alaska. The small Lisburne field, operated by Hilcorp Energy, also dropped slightly in July, down 3,444 b\/d from June. Lisburne is to the east near the Prudhoe Bay field and with its reservoir underlying that in the larger Prudhoe field. While the currently-producing North Slope fields appear to be holding steady, the data also reflects a long-term, gradual decline that is typical of oil and gas fields. For example, the North Slope production average in June of an average 439,255 b\/d reflects a drop in June output from an average 476,395 b\/d five years ago, in June 2018; 500,526 b\/d in June, 2014, 10 years ago, and from 591,665 b\/d in June, 2009, 15 years ago. The gradual decline raises questions as to how far slope production can drop before operating problems develop for the Trans Alaska Pipeline System, or TAPS, which was built in the 1970s and is designed to move 2 million b\/d from northern Alaska to the Valdez Marine Terminal in the south coast of Alaska. TAPS moved that volume for its first 10 years until the fields went 'off plateau' in 1988, with the onset of the gradual decline. Studies by Alyeska Pipeline Service Co., which operates TAPS, show the system could operate down to about 300,000 b\/d in its current configuration, although the per-barrel transportation costs would rise. However, with new North Slope projects set to begin production in 2026 and 2029, the decline of TAPS throughput to the 300,000 b\/d threshold will now be delayed. Pikka, a new project in construction by Australia-based Santos, Ltd. and its minority partner Repsol, is now in construction with its first phase set to begin production in mid-2026 at 80,000 b\/d. ConocoPhillips\u2019 new Willow project, also in construction, is set to start up in 2029 at 180,000 b\/d. Pikka and Willow will offset the North Slope decline, but the effect will be temporary unless other new oil finds are made. In its long-term Alaska production forecast, the state Department of Revenue\u2019s economic analysis group expects a modest increase in slope production over the next 10 years with the new fields adding output and the older, larger fields on the slope continuing to decline. ","headline":"Alaska North Slope crude output up in July, but long-term decline continues","updatedDate":"2024-08-05T18:46:32.000"},{"Unnamed: 0":329,"body":" The balance-month -- currently August -- Dated to Frontline contract was assessed Aug. 5 at its lowest level since June after losing 34 cents\/b from its Aug. 2 close amid a weakening in European sweet crudes. The DFL represents the difference between ICE Brent futures and Dated Brent. Platts, part of S&P Global Commodity Insights, assessed the balance-month DFL contract at minus 3 cents\/b Aug. 5, the lowest since June 14. It is also the first time since June 18 that the balance month and month 1 DFL contracts have been assessed in contango. Platts assessed the month 1 -- currently September -- DFL contract at 5 cents\/b Aug. 5. The weakening in the balance-month DFL contract is considered a bearish signal for the physical crude market. Platts last assessed the global Dated Brent benchmark at $78.265\/b Aug. 2, the lowest since June 5. ","headline":"Balance-month DFL contract slips to seven-week low in bearish sign for physical crude fundamentals","updatedDate":"2024-08-05T17:37:31.000"},{"Unnamed: 0":330,"body":" Local authorities in the Erbil governate of Iraq's semiautonomous Kurdistan region have shut 138 illegal topping plants and ordered dozens of licensed refineries to implement environmental protection requirements or face closure. The move was prompted by complaints of pollution and worsening air quality in the Kurdistan capital of Erbil, local media reported Aug. 4. It also comes amid a surge in the black market trade in crude and refined products in Kurdistan, since the closure of the region's main export pipeline to the Turkish port of Ceyhan in March 2023. S&P Global Commodity Insights previously reported the rise of hundreds of small refineries, including simple topping plants, many of which are illegal, which now benefit from landlocked Kurdish crude that is sold at a major discount to international prices. Kurdish crude production has now rebounded to as high as 300,000 b\/d from nearly zero when the pipeline was shuttered, sources have told Commodity Insights. Besides emissions from the facilities, the trade in local crude and refined products has also resulted in greatly increased road traffic from trucks carrying the oil, prompting local protests over safety and pollution. The topping plants usually produce fuel oil and low quality gasoil that is sold locally and delivered by truck to traders in Iran and Turkey. In June, a massive fire broke out at an oil refinery located on the Erbil-Gwer road. The licensed refineries in Erbil will be given a grace period of 10 days to adhere to environmental requirements and rectify all violations, or they will be legally charged, Erbil Governor Omed Khoshnaw said in a press briefing. Associated industries, such as tar manufacturers and electricity generators, are also required to clean up their operations and their owners will face arrest if they use \"bad\" gasoil. The governor threatened to arrest the owners of these plants \u201cafter increased complaints of smoke [and] fog that engulfs and chokes.\" A committee has been formed under the chairmanship of the deputy governor to protect Erbil's environment and to follow up and monitor the implementation of these guidelines and decisions. Kurdistan Regional Government authorities could not be reached for comment on whether it is searching for additional illegal refineries or cracking down on illicit fuel trade. ","headline":"Iraqi Kurdistan officials order crackdown on illegal refineries over pollution","updatedDate":"2024-08-05T16:53:01.000"},{"Unnamed: 0":331,"body":" Barge navigation on the Rhine and oil logistics in southern Germany face rising costs next week as water levels are expected to drop below levels required for transporting maximum loads. Passable water levels at Kaub in Germany, one of the narrowest stretches of the strategic waterway, stood at 236 cm midday Aug. 5, data from German water authority WSV showed, down from a recent high of over 600 cm in June, when floods caused closures along stretches of the Rhine as barges were unable to sail under some bridges. But low rainfall means Rhine river flows have slipped a quarter to 1,253 cu m\/second -- the largest week-on-week drop since June 10-16 -- as flows reached 4% below their long-term average of 1,304 cu m\/second. Average water flows were last below their long-term average in mid-May. According to WSV's two-week forecast, Kaub levels are likely to dip below 180 cm next week before recovering slightly but remain under 200 cm by Aug. 19. Rhine levels at Kaub below 200 cm typically force oil barges to short load, leading to associated increases in transport costs. When the water level is 135 cm, many barges can only be half loaded, effectively doubling the cost of river transport. The Rhine is used to transport millions of tons of commodities through inland Europe, including oil products, chemicals, iron ore, and coal in addition to goods on container barges. In the summer of 2022, navigable water levels on Europe's key transport waterway fell to multi-year lows of 31 cm, effectively shutting the waterway to flows of commodities and container ships. ","headline":"Rhine barge cargo navigation limits set to kick in amid dryer weather","updatedDate":"2024-08-05T16:00:15.000"},{"Unnamed: 0":332,"body":" Bolivia has been returning its diesel supplies to normal following shortages, bringing in the first of four delayed shipments from a Chilean port. This move came as the country seeks to increase local oil production to reduce import reliance, said Franklin Molina, Hydrocarbons and Energy Minister, on Aug. 3. After visiting service stations, Molina said in a statement that a total of 27 million liters were unloaded, a volume that will increase over the next few days. \u201cOur commitment is to guarantee a stable and continuous supply of diesel throughout the year, thus ensuring that the sectors that depend on this resource can operate without interruptions,\u201d he said. Molina spoke after the country ran up a 28% deficit in diesel supplies, sparking protests and long lines at service stations. The shortages happened largely because of supply chain disruptions, with a storm surge delaying the unloading of four ships with a total of 160 million liters of diesel at the Port of Arica in Chile, while low water levels on rivers stalled deliveries from neighboring countries. This pushed YPFB, Bolivia\u2019s state oil company, to scramble to import supplies by truck from the neighboring countries of Argentina, Brazil, Paraguay and Peru. The official said the unloading of the rest of the supplies from the ships will improve diesel supply in Bolivia. Rebuilding oil production Looking ahead, Molina said that, to avert a repetition of these shortages, a key is to step up oil exploration to rebuild production after a decade of decline. \u201cThe supply problem has an explanation: the reduction in the production of liquid hydrocarbons and gas, caused by the lack of investment in exploration,\u201d Molina said. Oil output tumbled 59% to 21,000 b\/d in April from a peak of 51,100 b\/d in 2014, while gas output shrank 44% to 33.8 million cu m\/d from a record 60.8 million cu m\/d over the same period, according to data from the state statistics institute INE. Molina said that a $1.4 billion exploration program launched in 2021 will eventually turn this decline around as discoveries are made. YPFB made the first large find last month in Mayaya Centro-X1, a well in an undeveloped basin to the north of La Paz with 1.7 Tcf of potential reserves. More discoveries like this will make it possible have accessible energy supplies at a low cost, helping to reduce imports, Molina said. ","headline":"Bolivia returns diesel supplies to normal following shortages","updatedDate":"2024-08-05T15:57:51.000"},{"Unnamed: 0":333,"body":" Methanol producer OCI remains optimistic on the decarbonization-led drivers of demand for methanol, primarily in the maritime industry, according to its earnings report Aug. 2. That is amid \u201cincreasing regulation placing greater pressure on carbon emissions reduction,\u201d its said, with the extension of the emissions trading scheme [ETS] coverage including the maritime sector from January 2024. The FuelEU maritime initiative will mandate a reduction in GHG intensity of marine fuels from 2025, buoying the uptake of lower carbon fuels such as methanol and potentially ammonia. The company said that 301 methanol dual fuel newbuild\/retrofit ships are on order for delivery over 2024-2028, representing up to 7 million mt\/year of potential additional demand for methanol, compared with current demand in the maritime sector of 350,000 mt and a current global merchant market of around 32 million mt. The recently adopted Fit-for-55 framework targets including RED III for road, FuelEU Maritime for marine, ReFuelEU Aviation for aviation and RepowerEU for biomethane are mandating greater reductions in carbon emissions. The company suggested that total fuel-based demand for green methanol from road, marine and aviation could reach up to 9 million mt\/year in 2030 compared with less than 200,000 mt\/year currently, according to industry projections. The European Commission will impose provisional tariffs on Chinese biodiesel of 12.8%-36.4% in August, after figuring that it is being sold in the EU markets at unfairly low prices, the company added, with that implementation set to support European biodiesel prices and boost the \"willingness-to-pay\" for OCI\u2019s key product, bio-methanol, and benefiting OCI's HyFuels business. \u201cThe EU\u2019s investigation continues, and definitive duties could be announced in early 2025,\u201d its said. OCI also said that demand experienced an uptick amid higher oil prices which supported methanol affordability for MTOs as well as energy applications such as gasoline blending. Overall, the company reported revenues from its methanol division falling 8% on the year to $231 million in Q2 amid lower sales volumes. Total own produced methanol sales declined 14% on the year to 344,000 mt due to a planned shutdown at Natgasoline, where OCI-produced sales were 50% lower on the year. According to Commodity Insights data, Platts' average quarterly European methanol prices climbed roughly Eur20\/mt from Q1 to Eur310.80\/mt in Q2, amid tighter supply caused by global turnarounds or supply disruptions in Norway, the Americas and Egypt. ","headline":"OCI optimistic about methanol demand driven by decarbonization efforts","updatedDate":"2024-08-05T14:59:37.000"},{"Unnamed: 0":334,"body":" Mitsubishi Power will supply a M701F gas turbine capable of 30% hydrogen co-firing to a 500 MW gas turbine combined cycle plant in Malaysia, with commencement planned in 2027, the company said Aug. 5. Low carbon hydrogen\/ammonia-fired power plants are expected to play a significant role in energy transition due to their ability to reduce carbon footprint of utility scale electricity generation. Singapore, Japan and Australia have recently started initiating similar plants. \"This project, equipped with our hydrogen-ready M701F gas turbine, reaffirms our commitment to supporting Malaysia's journey towards net-zero by 2050,\u201d Akihiro Ondo, CEO and Managing Director of Mitsubishi Power Asia Pacific, said. Located in Miri in northeastern Sarawak, the project is owned and operated by PETROS Power, a subsidiary of Sarawak-owned oil and gas company Petroleum Sarawak Berhad, or PETROS, Mitsubishi said. PETROS is developing the GTCC power plant, supported by Sinohydro as the engineering, procurement, construction and commissioning contractor, alongside Mitsubishi Power, it said. Upon completion, the GTCC plant will be able to provide energy security for northern Sarawak while providing sufficient energy capacity for Sarawak's future power demand and growth, according to PETROS. The GTCC is expected to be a key state facility in a major natural gas hub of Sarawak, and is being developed under the Sarawak Gas Roadmap, which supports Sarawak's aspiration of being a high-income state by 2030. The Sarawak Gas Roadmap details leveraging gas to drive sustainable development across four strategic hubs -- Kuching, Bintulu, Samalaju and Miri in Malaysia -- according to the PETROS website. Each of these hubs have clean energy projects alongside conventional energy. For example, Kuching and Samalaju each have GTCC project in addition to Miri, while Bintulu has a clean ammonia project. Service agreement Mitsubishi Power has also secured a long-term service agreement with PETROS to ensure the operational performance of the Miri power plant, Mitsubishi said. The generators for the power plant will be manufactured by Mitsubishi Generator, which was formed on April 1, 2024, through integrating power-generator systems businesses of Mitsubishi Heavy Industries and Mitsubishi Electric Corporation. Mitsubishi Power and its parent Mitsubishi Heavy Industries will continue to focus on advancing the adoption of power generation technologies for projects that contribute to decarbonization, the company said. Mitsubishi Heavy Industries and Thailand's largest power producer Electricity Generating Authority of Thailand signed a memorandum of understanding for research for the introduction of hydrogen co-firing technologies for gas turbine power generation, Mitsubishi said June 5. South Australia has a facility , due to be operational in 2026, that will use the state\u2019s excess renewable energy to produce renewable hydrogen, which will be stored and used to fuel a 200-MW power station, the state has said. Platts, part of S&P Global Commodity Insights, assessed Japan hydrogen produced via alkaline electrolysis (including capex) at $6.67\/kg on Aug. 5, up 21.49% month on month. Platts assessed New South Wales hydrogen produced via alkaline electrolysis (including capex) at $9.58\/kg on Aug. 2, up 46.26% on the month, Commodity Insights data showed. ","headline":"Mitsubishi to supply turbine for 30% hydrogen co-firing in Malaysia power plant","updatedDate":"2024-08-05T14:28:28.000"},{"Unnamed: 0":335,"body":" European LNG prices saw increments through the week as supply-side concerns kept the market jittery despite fundamentals painting a bearish picture. Platts, part of S&P Global Commodity Insights, assessed the DES September Northwest Europe price at $11.60\/MMBtu Aug. 2, up $1.118\/MMBtu, or 10.7%, on the week. This marks the largest week-on-week change in NWE prices in 10 weeks. Meanwhile, the September JKM was at $12.772\/MMBtu on Aug. 5, 3 cents\/MMBtu lower on the week. NWE, Med The recent supply-side worries have contributed to the price bullishness by raising the upside risk ahead of winter procurement. These worries are about the risk of impending maintenance at Norwegian facilities, the increase of hostilities in the Middle East, and supply delays originating from Asia. In Europe, the basic demand structure has remained bearish, even despite the bullishness around prices. Subdued demand for LNG is being seen in Northwest Europe, in part because of robust inventories and Norwegian supply, and in part because LNG is more expensive than local gas hubs. \u201cImports have dropped due to a combination of weak demand, robust Norwegian supplies and lower liquefaction utilization,\u201d said David Lewis, LNG Analyst at Commodity Insights. \u201cSo Europe needs less LNG at a time when there is less LNG globally.\u201d Mediterranean demand has seen some uptick in comparison to the previous months, but it is still below seasonal norms. This has led to the widening of spreads between the LNG prices in the Mediterranean and their Northwest European counterpart. The West Mediterranean was assessed at an 8 cents\/MMBtu premium to Northwest Europe, while the East Med marker was assessed at a 25 cents\/MMBtu premium. These are the strongest premiums versus NWE for Med since April 2023 and since April 2024 for the EMM. Americas In the US, following Freeport\u2019s outage July 7, last week finally saw stable feedgas demand at the facility, indicating that the Texan facility is back in operation with all three trains running. ExxonMobil delayed the startup of the Golden Pass LNG export terminal to late 2025, roughly six months later than planned, due to the bankruptcy of lead contractor Zachry Group. The revised timeline follows a federal bankruptcy court's approval of a settlement, allowing remaining contractors to continue construction despite the project's earlier cost overruns and challenges. The Platts Gulf Coast Marker for US FOB cargoes loading 30-60 days forward was assessed at $10.82\/MMBtu Aug. 2, up $1.42\/MMBtu on the week. In Latin America, the past week saw Calamari LNG, Colombia\u2019s sole LNG importer, awarded a one-cargo buy tender Aug. 2. Calamari LNG was seeking a partial cargo of 44,000 cu m for delivery between Aug. 13-19 Platts assessed DES Brazil for deliveries 15- to 45-days forward at $11.535\/MMBtu, or at a 6.5 cents discount to September NWE. LNG swaps The focus of the market has shifted from the prompt months to the forward months, primarily to ensure winter supply security. \u201cFocus is now on winter,\u201d said an Atlantic-based trader. \u201cThen watch for impact of decline of the global economy but that's down the road.\u201d However, the limited liquidity in the market is spilling over to the forward months too. The market is also weighing the impact of the Russia-Ukraine transit deal expiry, which would potentially leave the region looking for alternative cargoes. This is adding to the winter bullishness. Platts assessed the September DES Northwest Europe derivative at $11.596\/MMBtu on Aug. 2, with October at $11.745\/MMBtu, November at $12.505\/MMBtu and December at $12.754\/MMBtu. In addition, Asia is expected to continue pulling cargoes even going into September, which is aiding the supply anxiety among market participants. LNG bunker Atlantic LNG bunker prices continued an upward trajectory on the week amid growing LNG bunkering buying interest. Platts assessed LNG bunker Rotterdam and Barcelona at $13.342\/MMBtu and $13.444\/MMBtu respectively Aug. 2, both up 86.6 cents\/MMBtu on the week. Rotterdam LNG bunker sales saw record-high results in the second quarter as the port published sales of 242,931 cu m. \u201cMore container vessels, car carriers and tankers are being delivered and receiving supply in Rotterdam,\u201d an Atlantic-based trader said, adding there had been no problems with supply tightness so far. Across the Atlantic, LNG bunker fuel was assessed at $12.13\/MMBtu Aug. 2 , up 60.6 cents\/MMBtu on the week. ","headline":" Key market indicators for Aug. 5-9","updatedDate":"2024-08-05T14:03:31.000"},{"Unnamed: 0":336,"body":" The European gasoline complex fell sharply Aug. 2 on the back of a much lower crude oil price, with traders pointing to a sharp shift in blending economics as a result of the selloff. The Eurobob front-month FOB AR swap fell below a six-month low Aug. 2 to be assessed at $762.25\/mt, having dropped 8.6% on the day, according to assessments by Platts, part of S&P Global Commodity Insights. A global selloff in equities on the back of weak economic data saw crude oil prices also fall sharply, with Platts assessing Dated Brent down $3.56\/b on the day. Around 70% of the outright gasoline price is widely considered to be simply the crude oil price. The resulting fall in the gasoline flat price also resulted in a sharp drop in the spread between the Eurobob swap and the equivalent naphtha swap, with Platts assessing the spread at $130.25\/mt Aug. 2, also a six-month low. The spread between gasoline and naphtha is a key indicator for blending economics, and determines the relative incentives for blenders to select certain components. In mid-morning trading London time Aug. 5, the September gasoline-naphtha spread had fallen even further, trading around $115\/mt. Barge trading activity jumped on the day, with traders saying this was the result of the fall in the spread, which was not tied to arbitrage economics. During the Platts Market on Close assessment process, there were nine trades for finished-grade 10 ppm barges. \u201cThe gas-nap is moving, the flat price came off, so people may change their plans on what to blend,\u201d said one trader in Europe. Another source in the region said: \u201cThe August gas\/nap has come off over $20\/mt, I would not be surprised if plans change.\u201d During the week sources had pointed to a tighter market for reformate, a key high-octane blendstock. A lower gasoline-naphtha spread could further disincentivize reformate production. Meanwhile, although the supply tightness in the naphtha market in July was no longer as strong, the backwardation structure in the European naphtha market faced upward pressure as demand for naphtha to go into both petrochemical production and gasoline blending remained persistently strong. This opposing trend further pressured the gas-nap spread on the day. \"The naphtha market looks tight at the moment as there is not much [product] available and the buying interest is significant on physical,\u201d said a European petrochemical trader. \"Producers and blenders are building [naphtha] stocks before the turnaround season.\u201d Platts assessed the August\/September time spread for Platts CIF NWE naphtha swap at $11.50\/mt on Aug. 2, up $1.75\/mt on the day. ","headline":"Eurobob swap, gas-nap spread falls below 6-month low amid crude selloff","updatedDate":"2024-08-05T13:34:47.000"},{"Unnamed: 0":337,"body":" Petrochemicals demand continues to remain generally slow over the summer holiday period with many market participants on holiday and consumer plants being taken offline for maintenance. Aromatics Liquidity in the European benzene and styrene markets is expected to slow down after August contract price settlements, with market participants being absent amid the summer. Demand was not expected to pick up, however, tightness in the European styrene market may continue. Demand for toluene in Europe is expected to continue to remain strong amid ongoing supply tightness and cracker issues in northwest Europe, while demand for mixed xylene may remain softer in comparison. Meanwhile, activity in the orthoxylene and paraxylene spot markets may remain subdued, with demand for additional material expected to weaken due to sufficient supply in downstream markets. Olefins Supply of ethylene on the ARG (\u00c4thylen Rohrleitungsgesellschaft) pipeline remained constrained across the week to Aug. 2 following restocking activity through July and some steam cracker issues, according to market sources. Market participants were heard seeking to secure volumes and stock up balances ahead of September, when three steam crackers in Germany -- BASF, LyondellBasell and BP -- are expected to go into a planned turnaround. European propylene markets will see residual tightness across the week ahead, driven by production constraints and some restocking demand for material ahead of a turnaround season in mid-to-late Q3. Despite this, underlying market conditions will remain muted, with downstream demand weak. Butadiene availability will remain balanced to tight in Europe amid several unplanned outages, while demand will be supported by traders looking for additional export volumes loading in late August\/early September. European glycol sentiment is expected to stay weak through August as a number of downstream production units are already beginning shutdowns. As demand in August is typically weak, some consuming units will shut their plants for the entire month for maintenance amid lower order intakes. Buyers are left with ample supply as a result. Methanol and MTBE European methanol prices remain elevated amid ongoing global supply disruptions in the Americas, Europe and Egypt. Prices have marginally eased over the prior weeks due to slow summer demand, which is expected to persist throughout August, according to market participants. The European MTBE market remains healthy in terms of supply despite sources noting a closed arbitrage from China, with most volumes from the country now focused on the domestic market. Polymers The European high density polyethylene markets have been seeing a rise in spot prices amid tighter supply. Supply of HDPE grades tightened further, with continued limitations in imports from the Middle East amid production issues in the region and output rates among European producers low. Meanwhile, trading activity in the European linear low density polyethylene market was muted. In the European low density PE market, tight material availability continued, with continued low domestic production rates and limited imports into Europe. Market sources cited supply constraints for LDPE grades both in the spot and contract markets, while producers cited limited availability of additional volumes. European polypropylene markets will focus on contractual negotiations across the week ahead, with mixed views among participants on the expected direction of pricing across the month. The week ahead is also likely to see some supply uncertainty amid an outage, which will likely weigh against against the summer holiday period in the continent, particularly in southern Europe. European PVC prices ended the previous week stable, but with monomer costs moving higher, producers and other market participants had intentions of increasing both spot and contract prices in August to help restore margins that were hit by weak demand over the past year. Although a clear demand recovery is still some way off, producers are confident that a reduction in imports due to higher freight costs and antidumping duties applied on US and Egyptian imports will likely aid some demand recovery as consumers are concerned of not having sufficient security stocks as a number of producers start scheduled maintenance shutdowns, which are at risk of overrunning or being subject to delays. The European polyethylene terephthalate market may experience stable-to-weak fundamentals, with demand expected to soften due to summer shutdowns. Meanwhile, supply availability is also expected to improve, driven by material arriving from Asia and improved feedstock PTA availability in Europe. The polystyrene market remained weak with low demand amid announcements of price increases by producers in the range of Eur100-135\/mt. Ample supply was seen within the market, with producers running at low output rates. Asian imports were not heard arriving into Europe due to elevated freight costs. Sentiment in the ethylene-vinyl acetate market was mixed in the week. Although offers were seen higher through July amid healthy demand from the agricultural film and general packaging segments, demand in August is expected to ease and even weaken towards the end of the month. The nylon market is expected to continue seeing quiet spot activity. Demand for nylon in the construction and automotive sectors is expected to remain weak. Market participants are now looking towards the September period for some recovery in demand. Recycled plastics In the week ahead, the European recycled PET market is expected to maintain stable fundamentals, paired with a seasonal downturn due to summer shutdowns. Meanwhile, bale availability is anticipated to continue rising, and prices across regions are expected to start softening due to improved supply. The focus of European recycled polypropylene markets will remain on their virgin counterparts across the week ahead, with appetite for material clipped across the sector due to a seasonal downturn, and remaining fully contingent on cost competitiveness against fossil-based PP. Geographic divergence in fundamentals will be seen across the week, with differing levels of market activity seen across different regions of the continent. The European recycled high density polyethylene market may start seeing activity pick up slightly later this week as some participants may start to return from holiday. While demand for the packaging grade was seen to be stable and firm in recent weeks, market participants will start to assess the impact of an upward settlement of virgin feedstock monomer ethylene for August. A potentially narrowing spread between recycled and virgin HDPE should weigh on consumers\u2019 minds if virgin HDPE follows through and starts factoring in virgin feedstock\u2019s pricing trend. The European recycled low density polyethylene market may see some activities re-emerging later this week following the summer holiday. As the market reopens, the impact of an upward settlement in virgin ethylene\u2019s contract price, as well as cheaper feedstock bales for the recycled grade, may partially counterbalance each other. The European recycled polystyrene and ABS market may see varying performances across geographic markets as some participants may be more affected by subdued demand during the peak summer period while others may continue to see the market being stable and resilient against weak virgin demand trend. Intermediates and solvents The European acrylates market continues to contend with poor demand and ample or stable supply for butyl acrylate and glacial acrylic acid, resulting in prices remaining flat to somewhat pressured. Meanwhile, the European market for 2-ethylhexyl acrylate remains tight amid unconfirmed supply disruptions in Europe, with market participants concerned this could worsen over August and early September due to planned summer maintenances. Acrylonitrile markets will continue to see quiet spot activity across the week, with reasonable demand from downstream markets covered by contractual commitments. Arbitrage opportunities, despite strong pricing in Europe, will remain thin on the ground due to ongoing logistical delays and strong freight rates. The hydrocarbon solvents market is expected to see weak trading activity due to the holiday season which continues to place downward pressure on prices. Demand from the gasoline blending and chemical sector is expected to remain relatively unchanged, rolling over weak demand in previous weeks. On hexane, some market participants expect to see an uptick in demand as the oil extraction season gets underway. European acetic acid and vinyl acetate monomer markets remain muted over the summer period with many participants on holiday, leading to ample supply and weaker prices. Participants said they expect demand and market activity to recover in September. ","headline":" Key market indicators for Aug 5-9","updatedDate":"2024-08-05T13:17:44.000"},{"Unnamed: 0":338,"body":" Supply tightness will likely dominate the light end markets in the week to Aug. 9 despite relatively stable demand fundamentals. Gasoline ** The Gasoline markets were highly volatile on the week to Aug. 2 amid the monthly roll. The Eurobob M1 crack spread fell to $15.15\/b Aug. 2 from $16.38\/b July 26, but spiked to $17.5\/b July 31. Traders pointed to a large volume of paper positions rolling into the front-month on the last day of the month, before the market corrected back down by the end of the week. ** Aug. 2 saw the outright crude price dropping over $2\/b amid global economic worries. The Eurobob Sep swap was assessed down 4.72% to $762.25\/mt, bringing the flat price past a six-month low. Sources said blending economics changed sharply as a result, with more barges trading hands on the day. However, the arbitrage remained shut amid a stock build in the US. ** Looking forward, traders pointed to a mostly closed arbitrage to both the US and West Africa. However, stocks in PADD 1, while higher on the week, remain close to five-year lows. Traders highlighted a situation where any major supply disruptions could see a large volume of cargoes fixed for TA destinations. Naphtha ** In the European naphtha market, backwardation will likely steepen as the market factors in the upcoming refinery turnaround season. ** Platts, part of S&P Global Commodity Insights, assessed the August\/September time spread for Platts CIF NWE naphtha at $11.50\/mt on Aug. 2, up $1.75\/mt on the day. Stable demand for naphtha to go into both petrochemical pool and gasoline blending combined with expectations of lower supply keep the backwardation structure elevated. ** According to a European broker source, the market looks \u201ctight in the ARA and Mediterranean\u201d due to upcoming refinery turnaround season and \u201crestocking\u201d by market participants with Agerian origin naphtha looking \u201cstill very expensive\u201d. The source added that overall \u201cdemand is good and cracking looks pretty tight\u201d for naphtha. ** Steeper naphtha backwardation on the week has also led to lower ARA stocks. Naphtha stocks in the Amsterdam-Rotterdam-Antwerp hub fell 2.38% in the week to Aug. 1 to 410,000 mt, according to Insights Global data. LPG ** The European propane market diverged on the week, as pockets of strength in crude oil bolstered large cargo values while subdued demand inland weighed heavily on fundamentals. ** Short supply in the large vessel markets have restricted spot trading activity as players struggle to locate product, sources said. Meanwhile, refinery exports for the inland complex were up on the month as supply outpaces demand for barges and railcars. ** Platts assessed the CIF NWE large cargo market at $584.75\/mt Aug. 2, up $11.50\/mt on the week, while the propane coaster market climbed $24\/mt to $630\/mt. The FOB barges and FCA railcar and trucks markets stood at a $54.75\/mt and a $2.75\/mt discount to the CIF large cargo market, respectively. ** The European butane market was volatile throughout the week, trailing moves in the naphtha market. Butane remains in favor for flexible steam crackers keeping buying appetite elevated slightly in the market. ** Meanwhile, supply continues to be constrained for the coaster and large cargo markets as North Sea maintenance and reduced US tons tighten fundamentals. ** In the barge market, the closure of the Shell\u2019s steam cracker in the Netherlands could see more volumes forced into the complex, players added. In outright terms, the FOB seagoing butane coaster market was assessed by Platts at $543\/mt Aug. 2 down $6\/mt on the week or 83% as a proportion to naphtha. The CIF coaster market dropped $5\/mt on the week to be assessed at $491\/mt or 75% as a proportion to naphtha. ** The West Mediterranean butane market dropped on the week amid an uptick in selling appetite. Sources had pointed to tighter fundamentals after US imports fell to near three-year lows for July, S&P Global Commodities at Sea data showed. ** High US terminal costs are keeping arbitrage dynamics thin, with US barrels continuing to point into the far East market. Meanwhile, Algeria\u2019s Sonatrach kept its butane CP steady for August and increased propane prices slightly for the month. ** The West Mediterranean FOB butane market was down $31.75\/mt on the week to $508.25\/mt Aug. 2 or 77.75% as a proportion to naphtha. The FOB West Med propane market stood at $679.75\/mt Aug. 2, up $11.50\/mt on the week. ","headline":" Key market indicators for Aug 5 \u2013 9","updatedDate":"2024-08-05T12:34:46.000"},{"Unnamed: 0":339,"body":" Cargoes of high sulfur fuel oil are expected to reach European shores from Latin America and North America in the week ahead, with the market set to receive a deluge of supply. HSFO The European high sulfur (3.5%S) fuel oil markets are continuing to see healthy bunkering demand in Europe and from the Middle East for power generation purposes. Elevated prices have meant that cargoes continue to arrive from the Americas with new cargoes expected to land in Northwest Europe in the first half of August. However, traders said there is good demand in the Mediterranean which could pull some of these cargoes from the Rotterdam region. LSFO The low sulfur (1%S) fuel oil market has seen a recent increase in activity following a recent tightness of cargoes in the Mediterranean and strong prompt demand. Traders indicated that high August temperatures have meant that utility shorts in the Mediterranean are in the market for LSFO to meet their high power generation needs. In the very low sulfur (0.5%S) fuel oil market, bunkering demand remains weak due to stronger demand for HSFO from larger scrubber-fitted ships. The front-month paper fuel oil hi-lo ended the week at $22.25\/mt, having widened by $6.75\/mt, while the front-month paper Hi-5 narrowed by $75\/mt to $86\/mt. Bunkers The bunker market is expecting another week of low demand while healthy supplies continued to push prices lower. In both Northwest Europe and the Mediterranean, the holiday season has kicked in, leaving trading activity sluggish. Prices have tumbled in both basins, while suppliers struggle to keep their premiums. In Gibraltar, premiums over Rotterdam have been rangebound, while Las Palmas\u2019 premiums have also narrowed, following the general weakening of the market. Feedstocks Vacuum gasoil and low sulfur straight run fuel differentials remained weak in the week to Aug. 2. Market participants continued to cite decreasing demand for feedstocks, attributed to end-product cracks weakening for products like diesel. Traders will be watching end-product crack developments, which will continue to affect demand levels for VGO and LSSR. ","headline":" Key market indicators Aug 5-9","updatedDate":"2024-08-05T12:26:14.000"},{"Unnamed: 0":340,"body":" Crude oil volumes sent from Azerbaijan to Turkey through the Baku-Tbilisi-Ceyhan pipeline averaged 630,533 b\/d in June, up by 8.1% month on month but down 3.8% year on year, according to data from Turkish pipeline operator Botas published Aug. 5. BTC flows over the first half of the year averaged 605,230 b\/d, down 3.7% on the same period in 2023, the Botas data showed. According to data released July 11 by Azerbaijan's energy ministry, its crude and condensate production in June averaged 603,400 b\/d, up 5.0% on the month but down 2.0% year on year, with exports of 493,333 b\/d rising 3.3% on the month and falling 4.8% on the year. January-June exports at 483,846 b\/d were down 6.6% on the same period in 2023. The BTC pipeline mainly carries crude from the BP-operated ACG oil field and condensate from the BP-operated Shah Deniz gas field but also carries crude from other non BP-operated Azeri fields as well as crude from Kazakhstan and Turkmenistan. In late 2022, Kazakh state-owned KazMunaiGaz and Azerbaijan's Socar reached a transit agreement under which 1.5 million mt\/year (around 30,000 b\/d) of crude from Kazakhstan's Tengiz field would be exported via the BTC pipeline. The move was seen as a response to the threat posed to lifting crude from the Black Sea terminal of the CPC pipeline, which carries the bulk of Kazakhstan's crude exports, by the ongoing Russia-Ukraine war. In March, KMG said it had reached an agreement with Socar for a phased increase in the volume of Kazakh crude exported through Azerbaijan by 50% to 2.2 million mt\/year, or around 180,000 mt\/month. KMG said July 25 that last year 1.057 million mt had been shipped under the deal, with more than 700,000 mt shipped over the first half of 2024. Last month, sources said Azerbaijan was unlikely to resume exports of Azeri Light via the Baku-Supsa pipeline and could assign the route for Kazakh crude, supporting a Kazakh push to diversify export routes. Meanwhile, there were no crude flows through the pipeline to Ceyhan from Iraq for a 15th consecutive month in June. The halt on the line followed an international arbitration court ruling that Iraq said upheld its sovereignty over oil exports from the semi-autonomous Kurdistan region. Despite efforts by Ankara and other external players, talks between the Iraqi central government, the Kurdistan regional government (KRG) and the region's producers have as yet failed to agree a formula to restart exports. On June 9 Baghdad hosted a meeting with KRG officials and oil company representatives, with reports indicating that oil companies operating in the region could consider allowing their contracts to be modified. However, as yet no agreement has been reached, with recently agreed OPEC production limits meaning that the Iraqi central government would be obliged to cut production from its own fields if production from those in the Kurdistan region restarted. Batman-Dortyol flows down 13% on month Flows of crude produced by Turkish upstream operator TPAO and some small private operators through the Batman-Dortyol pipeline averaged 86,667 b\/d in June, down 13.1% on May but up 4.2% year on year, with H1 flows up 29.2% year on year. The sharp rise in H1 volumes is believed to be at least in part due to lower-than-normal flows from Feb. 20 onwards last year, following the series of devastating earthquakes which hit the region of Turkey through which the line passes. The annual rise may also have been caused in part by increased production by TPAO from Turkey's recently discovered Cudi and Gabar fields. Turkish energy minister Alparslan Bayraktar said July 13 that production from the Gabar field had reached 45,000 b\/d -- up from a previous peak of 42,500 b\/d in May. In previous statements Bayraktar has said that production is expected to top 50,000 b\/d in June, and 100,000 b\/d by the end of the year. An energy ministry official confirmed to S&P Global Commodity Insights last month that previously announced talks with Baghdad concerning the construction of a 37 km spur pipeline to allow crude from the field to be transited to Ceyhan via the Iraq-Turkey oil pipeline were ongoing. Flows through the Dortyol-Ceyhan pipeline carrying crude from the smaller Dortyol oil terminal to the main Ceyhan terminal averaged 105,167 b\/d in June, up 22.6% on May and up 6.7% year on year. The reason for the sharp monthly rise is unclear but it follows 24.4% fall in May compared to April. The line was commissioned in April 2023 to offer flexibility to companies exporting crude from Turkish fields. Crude transit from Botas's Ceyhan terminal and onward to Tupras's Kirikkale refinery averaged 104,233 b\/d in June, up 16.0% on May and up 5.7% year on year. Similarly, the reason for the sharp monthly rise is unclear but it follows a sharp fall of 17.8% in May. The annual rise follows a 26.9% annual rise in May. Flows in May 2023 were unusually low due a to a combination of the impact of the earthquakes and maintenance work. ","headline":" June crude flows via BTC pipeline up 8.1% on month","updatedDate":"2024-08-05T11:53:27.000"},{"Unnamed: 0":341,"body":" Market participants are watching the wheat crop harvest progress in the Black Sea and Europe. Meanwhile, in the sunflower oil market sources expect reduced destination demand from India. Wheat Platts assessed FOB Russia wheat down $1\/mt on the week at $222\/mt. The FOB CVB 12.5 and 11.5% rose 75 cents\/mt on the week to $229.75\/mt and $224.75\/mt respectively. The Russian agriculture ministry set its variable export tax for wheat for Aug. 7-13 at Rb444\/mt ($5\/mt) Aug. 2, down Rb462\/mt (or $10\/mt) from the previous seven-day period. Ukraine has so far harvested 19.4 million mt of wheat (92% of total completion) with a yield of 4.35 mt\/ha. Meanwhile in France, 61% of wheat has been harvested, up 41% from last week. Corn Platts assessed FOB Ukraine corn up by $8\/mt on the week at $201\/mt, and FOB Constanta Varna Burgas corn up by $6\/mt at $212\/mt on the week. In Ukraine, farmer sales are anticipated to remain low in the coming week despite approaching harvest possibly due to the low-yield prospects of new crops. Traders are looking forward to hearing trading prices for the new crop corn, which is anticipated to reach earlier in the market than usual, attributable to the expected early harvest of the crop in the region. In the destination market, the competitiveness of the US and Brazilian corn is anticipated to affect the demand for Ukraine corn. Market participants are expecting the US Gulf to be a more competitive origin for Spain's corn imports. Sunflower oil Platts assessed FOB Black Sea sunflower oil steady on the week at $949\/mt on Aug. 2. India is expected to reduce its imports of Ukrainian sunflower oil in the marketing year 2024-25, according to Anil Bagani, head of commodity markets research at Sunvin Group India. Bagani indicated that imports of crude sunflower oil from Ukraine are projected to fall to 3.4 million mt, down from 3.5 million mt in the MY 2023-24. India will likely source more sunflower oil from Russia, Argentina, and possibly Europe to meet its domestic demand. The decrease in Ukrainian supply is attributed to adverse weather conditions that impacted the sunflower harvest, which is estimated to be around 12.5 million mt, with a reduced oil content. Rapeseed oil Platts assessed rapeseed oil FOB Dutch Mill front run down Eur10\/mt on the week at Eur981\/mt on Aug. 2. Europe's rapeseed harvest is still underway after rains in France and Germany delayed progress, which could lead to crop losses and reduced quality, said GrainTrade. In the oilseeds sector, rapeseed has been harvested from nearly 1.2 million hectares, or 95% of the target area. ","headline":" Key market indicators for Aug 5\u20139","updatedDate":"2024-08-05T11:53:21.000"},{"Unnamed: 0":342,"body":" Crude oil futures were down in the mid-morning Aug. 5 trade, as the global financial markets faced a selloff with weakness seen across many key asset classes. A decline in global stock markets was largely caused by main players exiting their positions in previously robust stakes and the US macroeconomic data suggested higher risks of a recession. However, escalating tensions in the Middle East kept the pressures elevated on the supply side thus limiting the fall in crude oil futures. At 1206 GMT, the October ICE Brent crude oil futures contract was at $75.77\/b, down $1.04\/b from the previous settlement at $76.81\/b, while the October WTI Crude Futures contract was at $71.59\/b, down $1\/b from the previous settlement at $72.59\/b. On Aug. 5, the financial markets opened under a stronger market selloff with Nasdaq falling nearly 4% and Dow and S&P500 futures falling around 1.5% while Japan\u2019s Nikkei 225 decreased by more than 12%, its biggest fall since 1987. This fall in main stock indexes continues the downward trend of the previous week after macroeconomic data showed weakness in the manufacturing and construction industries. The released data from the US Jobs Report, which showed a 4.3% US unemployment rate and limited payrolls growth, added to the mounting fears of an economic slowdown. \u201cWith demand indicators looking soft and jobless claims on the rise, the risks are skewed towards unemployment increasing more rapidly\u201d, which in turn increases the \u201clikelihood of recession\u201d, said James Knightley, the chief US economist at ING. However, the fall in crude oil future was limited on the news of escalating Middle Eastern tensions with wider conflict in the region leading to higher risks of disruptions in global oil supply. Warren Patterson, ING\u2019s Asia Head of Commodity strategy, said, \u201cRising geopolitical tensions in the Middle East\u201d are likely to make the market keep a \u201chigher risk premium for oil\u201d. ","headline":" Crude oil faces downward pressure amid wider weakness in financial markets","updatedDate":"2024-08-05T11:52:34.000"},{"Unnamed: 0":343,"body":" Australia\u2019s Woodside Energy has entered into a binding agreement to acquire chemical firm OCI Clean Ammonia Holding\u2019s low carbon ammonia project in the US which starts production next year and integrates with Carbon Capture and Storage operations the following year, Woodside said Aug. 5. the US\u2019 landmark climate and energy law, the Inflation Reduction Act, with an estimated $800 billion to $1.2 trillion in tax credits over 10 years, has driven global investors to set up new energy plants in the US, drawn by the prospects of attractive costs and access to global markets. \u201cThis transaction positions Woodside in the growing lower carbon ammonia market,\u201d said Meg O\u2019Neill, CEO of Woodside. \u201cGlobal ammonia demand is forecast to double by 2050, with lower carbon ammonia making up nearly two-thirds of total demand.\u201d The project is located in Beaumont, Texas, on the US Gulf Coast and can serve customers domestically and internationally, Woodside said. Phase one has a design capacity of 1.1 million mt\/year and is under construction. Initial ammonia production, derived from natural gas, will start in 2025, while the low carbon ammonia, derived from natural gas, paired with CCS will follow in 2026, Woodside said. Nitrogen and low carbon hydrogen feedstocks, needed to produce the low carbon ammonia, will be sourced primarily from Linde, Woodside said. The Linde feedstock facility is currently under construction, targeting completion in early 2026, Woodside said. Ahead of completion, early supply of feedstock will come from multiple suppliers. CCS services will be provided to Linde by ExxonMobil and are expected to be available in 2026, it said. The deal was sealed by Woodside for an all-cash consideration of approximately $2.350 billion. Phase two The facility is designed to accommodate a second 1.1 million mt\/year production train (phase two). Phase two remains in pre-final investment decision state and Woodside will target FID readiness for it in 2026. \u201cThis acquisition is a material step towards delivering our scope three investment and abatement targets,\" Woodside said. \"Phase one has the capacity to abate 1.6 million mt\/yr of CO2-e and with the addition of phase two, the project has the capacity to abate 3.2 million mt\/yr CO2-e, or over 60% of scope three abatement target.\u201d The project\u2019s competitive advantages includes gross equity scope one and two emissions of less than 0.1 million mt\/year CO2-e, with potential to further lower emissions with renewable power. The existing global ammonia market stands at 200 million mt\/year, traded on a blend of spot and medium-term contracts, Woodside said. Woodside\u2019s project is in a favorable location on the US Gulf Coast with access to multiple sources of feedstock and a deepwater port for international export, it said. Demand The project will target conventional ammonia customers initially and will target low-carbon ammonia customers in Europe and Asia when CCS is operational, Woodside said. \u201cThe potential applications for lower carbon ammonia are in power generation, marine fuels and as an industrial feedstock, as it displaces higher-emitting fuels,\u201d O'Neill said. Meanwhile, Woodside said April 19 that its US liquid hydrogen project H2OK will continue to make progress even as the US government\u2019s final guidelines on hydrogen production tax credits under IRA are awaited, for a likely announcement in the second half of 2024. Woodside's other renewable hydrogen projects include the H2Perth in Kwinana in Australia, the H2Tas in Tasmania, and the Southern Green Hydrogen in New Zealand. Woodside's most advanced CCS project, the Angel CCS joint venture off the northwestern coast of Western Australia, signed a memorandum of understanding with Yara Pilbara Fertilisers to study the feasibility of using CCS with the decarbonization of Yara Pilbara\u2019s existing operations near Karratha in Western Australia, the company said on April 19. Platts, part of S&P Global Commodity Insights, assessed US Gulf coast ammonia at $475\/mt basis CFR USGC on Aug. 2, up 14.45% month on month. It assessed Northwest Europe blue ammonia at $582.55\/mt basis CFR Aug. 2, up 14.47% from a month ago. ","headline":"Woodside to acquire OCI\u2019s low carbon ammonia project with CO2 capture in US","updatedDate":"2024-08-05T11:04:16.000"},{"Unnamed: 0":344,"body":" NextChem, a subsidiary of Italian Energy transition firm Maire, has secured a feasibility study for a new Sustainable Aviation Fuel project in Indonesia, in collaboration with PT Tripatra Engineers and Constructors, the company said in a statement Aug. 5. The project, located in Sei Mangkei, Indonesia, aims to establish a small-scale modular plant with a production capacity of 60,000 mt\/year of SAF. The facility will utilize regionally sourced feedstocks, including used cooking oil and palm oil mill effluent. According to the statement, Maire's proprietary technologies -- NX PTU and NX SAF BIO -- will play a crucial role in the plant's design and configuration. These SAF production process involve pre-treating the feedstocks through the NX PT technology and refining them into SAF using hydrogen via the NX SAF BIO technology. This method promises to produce ultra-low carbon SAF, potentially reducing aviation emissions by up to 95% compared with conventional fossil fuels. \u201cThis agreement underscores our dedication to leading the energy transition. By leveraging our integrated approach, we can effectively decarbonize high-impact sectors such as aviation,\" said Alessandro Bernini, CEO of Maire. SAF is expected to account for 0.61% of global aviation fuel consumption in 2024, up from 0.31% (20,000 b\/d) in 2023, according to S&P Global Commodity Insights. This is expected to rise to 3.24% in 2040 and 24.06% in 2050. Platts, part of Commodity Insights, assessed SAF production costs (palm fatty acid distillate) in Southeast Asia at $1,613.3\/mt Aug. 1, up $2.97\/mt from the previous assessment. ","headline":"Maire secures feasibility study for sustainable aviation fuel project in Indonesia","updatedDate":"2024-08-05T10:50:02.000"},{"Unnamed: 0":345,"body":" The Middle East sour crude complex saw cash differentials for key sour crude markers plunge during the Singapore Platts Market on Close assessment process Aug. 5, tracking a broader sell-off in the financial markets and as Aramco's September crude oil official selling prices came in below expectations. Platts, part of S&P Global Commodity Insights, assessed October cash Dubai, cash Oman and cash Murban at a premium of 65 cents\/b to same-month Dubai futures at the market close, all down 31 cents\/b on the day. The slump in sour crude differentials comes amid a broader sell-off across financial markets, with trading curbs triggered in some regional stock exchanges during the Aug. 5 Asian session. Platts assessed the M+2 October Dubai swap at $73.84\/b at the Aug. 5 Asian close, down 5.7% from the prior Aug. 2 close and reaching its lowest for the year. Aramco's September OSPs, issued early in the Aug. 5 session, also came in sharply below some traders' expectations. The OSPs reflected an Asian end-user market that is still struggling with poor refining margins and weak domestic demand. An impending hike in OPEC+ output, after the group in an Aug. 1 meeting opted to stand pat on its policy to unwind voluntary production cuts from October, was likely also a contributing factor, traders said. \"Very bearish signal,\" a trader said. During the MOC, 20 October Dubai partials of 25,000 barrels each traded. The sellers were PetroChina, Trafigura, Unipec, Phillips 66 and Mitsui, and the buyers were Vitol, Gunvor and Glencore. No convergences were reached during the MOC. A convergence occurs when 20 partials are traded between two counterparties, resulting in a full 500,000-barrel physical cargo being declared from the seller to the buyer. ","headline":" Middle East sour crude cash differentials plunge on risk-off sentiment","updatedDate":"2024-08-05T10:36:31.000"},{"Unnamed: 0":346,"body":" Low sulfur fuel oil storage available for lease in China\u2019s largest bunker hub of Zhoushan rose for the third straight month to a record high as of Aug. 5, Zhejiang Mercantile Exchange data showed, as supplies decline and a slight cut back in production is expected in August. LSFO ullage rose 4.6% on the month to 2.06 million cu m, while the total ullage across all oil products edged higher by 0.6% on the month to 8.72 million cu m. LSFO ullage soared 170.4% year on year, while total ullage surged 124% during the period. Crude oil storage availability remained unchanged on the month at 2.89 million cu m as of Aug. 5, while gasoline storage posted the biggest decline, decreasing 2% on the month to 980,000 cu m, and naphtha dropping 1.9% from a month earlier to 1.01 million cu m. Diesel storage availability was unchanged on the month at 1.26 million cu m, and jet fuel steady at 520,000 cu m. A major local refiner indicated plans to reduce LSFO production for the month by about 100,000 mt, to 1.2 million-1.3 million mt, translating to a 7%-8% decrease in output. A gradual decline in fuel oil export quota volumes for the rest of the third quarter is expected to support the downstream LSFO premium at the Zhoushan bunkering hub, as market participants await the next batch of quotas. The previous quota was released in early May. A Zhoushan-based bunker supplier said the next tranche of fuel oil quotas could be possibly smaller. \u201cThe refineries will have to cut back [on LSFO production].\u201d The premium for Zhoushan-delivered marine fuel 0.5% bunker over FOB Singapore marine fuel 0.5% cargo values averaged $12.91\/mt in July, rising from June\u2019s average of $4.19\/mt, Platts data from S&P Global Commodity Insights showed. Platts assessed the premium at $23.34\/mt on Aug. 2, rising $2.68\/mt on the day. LSFO tank utilization rates in Zhoushan rose 3.16 percentage points month on month to 40.68% as of Aug. 5, as leased storage rose to 5.98 million cu m, from 5.21 million cu m a month earlier, and total capacity increased to 14.7 million cu m, from 13.9 million cu m, according to ZME data. ","headline":"Zhoushan LSFO storage availability rises for 3rd month in Aug, hits record high","updatedDate":"2024-08-05T10:26:24.000"},{"Unnamed: 0":347,"body":" Oil storage reserves in southern Russia's Kamensky district became the latest target of the Ukrainian military on Aug. 3, after six drones targeted the site in Rostov. \"Tanks with fuel were damaged, followed by a fire on the territory of base No. 7,\" Vladimir Savin, head of the Kamensky District, said via Telegram Aug. 3. Savin later confirmed that the fire had been extinguished at around midday local time, almost 10 hours after first responders were first called to the site after the attack. Rostov regional governor Vasily Golubev confirmed that the incident marked part of a massive attack on Aug. 3 that saw 55 Ukrainian drones launched over the territory. Both the Kamensky and Morozovsky districts sustained damage from the strike, with Morozovsky declaring a state of emergency in response to the activity. The weekend activity, which also damaged fuel storage in Russia's Belgorod region near the front line, underscored an ongoing threat to its oil infrastructure from Ukrainian drone strikes. Because recent drone strikes have mostly focused on strategic fuel reserves crucial for Russia's military rather than refinery infrastructure, Russia has been able to restore most of its refining capacity damaged by previous drone strikes, though the 240,000 b\/d Tuapse refinery was targeted July 22 . In response, Russia is targeting power infrastructure in Ukraine, leading to widescale blackouts and forcing it to increase imports from the EU. ","headline":"Oil storage in Russia's Rostov region hit by drone strike","updatedDate":"2024-08-05T10:17:27.000"},{"Unnamed: 0":348,"body":" Flows of Nigerian crude into the Netherlands tallied 10.5 million barrels in July, the highest monthly figure since August 2019 when volumes topped 10.7 million barrels, according to the latest ship tracking data from S&P Global Commodities at Sea on Aug. 5. Peak summer demand season in Europe was cited by traders as the catalyst for increased appetite for Nigerian barrels, which saw an in-tandem strengthening in prices across the July trading cycle. The Netherlands took receipt of 2.2 million barrels of Forcados crude in July, another multiyear high, with the grade\u2019s assessment by Platts rising from at parity to Dated Brent to a $1.70\/b premium between June 1 and July 1, S&P Global Commodity Insights data showed. Forcados was last assessed at a $3.70\/b premium on Aug. 2, with earlier August trading cycle moves indicating a continuation of strong demand for Nigerian oil exports. Nigerian crude typically trades on a free-on-board basis several weeks prior to loading. In line with Europe\u2019s larger cut, one of Nigeria\u2019s usual customers India saw imports of July cargoes limited to just 2 million barrels, the lowest monthly figure since May 2023, CAS data showed. Traders in the region noted the arbitrage into India was hard to work with longer-haul voyages impacted by backwardation in Brent market structure. \u201cWest African crude is currently expensive, levels are not coming down and structure is up,\u201d said an Indian refinery source in the July trading cycle. \u201cIt\u2019s difficult for arbitrage buyers.\u201d Forcados retained its spot as the highest volume export grade in Nigeria, with 5.3 million barrels shipped internationally, though down from June\u2019s figure of 7.8 million barrels. Forcados was followed closely by Qua Iboe and Escravos at 4.8 million barrels and 3.9 million barrels, respectively. Nigeria loaded 44.8 million barrels of crude in July, with 6 million barrels in total already discharged or currently in transit to the mega Dangote refinery, according to CAS, representing a near 13% of all loadings through the month. ","headline":" Nigerian crude exports to Netherlands top 5-year high in July","updatedDate":"2024-08-05T10:09:58.000"},{"Unnamed: 0":349,"body":" The Vietnamese government has granted Hai Linh Co. Ltd. the license to import and export LNG, making it the second company or the first private firm in the country to trade LNG, according to documents seen by S&P Global Commodity Insights Aug. 5. Last year, the Ministry of Trade and Industry of Vietnam issued the first LNG import and export license to PetroVietnam Gas, the country\u2019s state-owned oil and gas company. On May 8, Hai Linh announced the targeted operating start date of the Cai Mep LNG terminal in September 2024, together with Singapore-headquartered Atlantic, Gulf and Pacific LNG, or AG&P LNG, a subsidiary of Nebula LNG, at the Cai Mep LNG Terminal Commissioning Symposium. The Cai Mep LNG Terminal in Vietnam\u2019s southern province of Ba Ria-Vung Tau will provide integrated LNG supply solutions through AG&P LNG and Hai Linh's downstream joint venture -- Vietfirst Gas, which had secured a 1 million mt\/year LNG offtake agreement with HPP power plant and another agreement with one of the demand aggregators in Vietnam. The market was expecting a tender from Hai Linh, following an expression of interest issued in May for a commissioning LNG cargo to the terminal. The company has not issued any LNG tender to date, market sources said. Platts on Aug. 2 assessed the September JKM at $12.915\/MMBtu and the September Southeast Asia Marker -- reflecting the value of cargoes delivered into Southeast Asia -- at 27.7 cents\/MMBtu discount to the September JKM, Commodity Insights data showed. ","headline":"Vietnam\u2019s Hai Linh receives license to import, export LNG","updatedDate":"2024-08-05T09:47:49.000"},{"Unnamed: 0":350,"body":" Japan\u2019s Idemitsu Kosan may restart its naphtha-fed steam cracker in Tokuyama on Aug. 11, multiple trading sources close to the matter said Aug. 5. Idemitsu Kosan was unavailable for comment. The cracker was initially shut on July 15 due to some problems, a company source said July 18. The unit is able to produce 623,000 mt\/year of ethylene and 450,000 mt\/year of propylene. The company also supplies crude C-4 to its external customers for butadiene production. The cracker shutdown has led to reduced crude C-4 feedstock supplies and a butadiene shortage of 4,000 mt, S&P Global Commodity Insights previously reported. Platts, part of Commodity Insights, assessed the CFR Northeast Asia butadiene marker down $10\/mt on the day at $1,540\/mt at the Asian market close Aug. 2. The Platts-assessed CFR China propylene price was at $865\/mt the same day, down $10\/mt on the week but unchanged on the day. ","headline":"Japan's Idemitsu could restart Tokuyama steam cracker on Aug 11","updatedDate":"2024-08-05T09:28:16.000"},{"Unnamed: 0":351,"body":" Indonesia\u2019s biodiesel production in June was up 3.7% year on year at 1.06 million kiloliters (222,250 b\/d), taking production for the first half of 2024 to 6.57 million kiloliters (227,062 b\/d), up 12.7% from 5.83 million kiloliters (202,600 b\/d) in the same period of 2023, trade body Indonesia Biofuel Producer Association or APROBI said Aug. 5. APROBI said consumption was pushed higher by increased biodiesel mandates, which are set to rise further next year. Indonesia already has the world\u2019s highest biodiesel blending mandate, set at 35% of gasoil consumption, as Jakarta looks to reduce energy imports as well as support its domestic palm oil industry. The blending mandate, popularly known as B35, was raised from 30% to 35% in February 2023, with nation-wide implementation starting later in the year from August. Domestic biodiesel consumption in the January-June 2024 period rose to 6.21 million kiloliters, up 9.3% from 5.68 million kiloliters in H1 2023. In 2023, Indonesia produced 13.15 million kiloliters of biodiesel and consumed 12.24 million kiloliters, APROBI data showed. The Southeast Asian country has completed automotive trials of its 40% blend of biodiesel and could implement it by the middle of next year, Eniya Listiani Dewi, the director general of Director General of New, Renewable Energy and Energy Conservation at the energy and mineral resources ministry, said June 29. For 2024, Indonesia -- the largest producer and exporter of palm oil -- has raised its allocation for palm oil-based biodiesel by 1.9% from 2023 to 13.41 million kiloliters, according to the energy and mineral resources ministry. To achieve a 40% blending rate, the ministry estimates that 16 million kiloliters of palm oil-based biodiesel will be needed. Looking further ahead, President-elect Prabawo Subianto expressed support for the biodiesel program during his election campaign, pledging to implement 50% biodiesel fuel (B50) and 10% bioethanol fuel (E10) mandates by 2029. Exports shrink Meanwhile, Indonesia\u2019s biodiesel exports shrunk to 22,411 kiloliters in H1 2024, compared to 112,803.3 kiloliters in H1 2023, APROBI data showed, Indonesia\u2019s biodiesel exports have fallen sharply in recent years from over 1 million kiloliters in 2018 and 2019 as the world\u2019s largest biofuel buyer, the EU, phases out palm oil-based biodiesel. Platts, a part of S&P Global Commodity Insights, assessed the price of Biodiesel FOB Southeast Asia at $1,059\/mt Aug. 2, up 2.3% from the start of the month. Indonesia biodiesel supply and demand June 2024 June 2023 Change (m-o-m) Jan-June 2024 Jan-June 2023 Change (y-o-y) Production 1.064 1.033 3.7% 6.57 5.83 12.7% Consumption 0.987 1.026 -3.8% 6.214 5.68 9.4% Exports 0.001 0.005 -80% 0.022 0.112 -80.1% All figures in million kiloliters Source: APROBI data ","headline":"Indonesia's biodiesel output up 12% in H1 on increased domestic mandates: APROBI","updatedDate":"2024-08-05T09:20:18.000"},{"Unnamed: 0":352,"body":" China\u2019s independent refineries cut their combined feedstocks imports to a three-month low of 3.65 million b\/d (15.45 million mt) in July amid low utilization rates, data from S&P Global Commodity Insights showed on Aug 5. Their July feedstock imports, comprising of imported crudes, fuel oil and bitumen blend, fell 2.97% from 3.77 million b\/d (15.41 million mt) in June and fell 9.7% year on year, the data showed. The small independent refineries with capacity between 40,000-214,000 b\/d, most of which are located in Shandong province, were the main contributor to the reductions due to their ongoing low operating rate amid the weak refining margins, sources said. Those independent refineries imported a combined of 2.16 million b\/d (9.03 million mt) of feedstocks, down 5.8% on the month, Commodity Insights data showed. The small Shandong-based independent refineries operated at average 49.1% of their capacity in July, two percentage points lower from June as refining margins fell from Yuan 248\/mt to Yuan 218\/mt in July, according to data from local information provider OilChem. On a year-on-year basis, the refining margins fell 74.9%, and the utilization rate was down 12 percentage points from last July, OilChem data showed. The year-on-year utilization drop also led the small independent refineries to lower their feedstock imports by 21.2% year on year to 2.13 million b\/d. Shandong's independent refineries typically serve as a key indicator of China's oil demand, as they operate more autonomously than their state-owned peers in the refining sector. Mega refiners boost imports The small independent refineries' reduction exceeded the month-on-month gain from the mega private peers' imports, although combined volume of that rose 4.8% from June to their four-month high of 6.43 million mt in July, Commodity Insights data showed. Zhejiang Petroleum & Chemical, was the leading importer to bring in 3.67 million mt of crudes, up 10.2% from a month earlier. ZPC in July received its first Canada AWB crude of around 550,000 barrels, transmitted via the Trans Mountain Expansion oil pipeline (TMX), the first of such by a private refiner. The company will continue to receive AWB cargoes in the coming months, according to sources. In the previous trading cycle, ZPC\u2019s parent company Rongsheng Petrochemical was heard to have bought four AWB Aframax cargoes for October arrival at discounts of $6\/b to December ICE Brent, DES Zhoushan, Commodity Insights reported previously. \"The popularity of Canadian crudes, mainly AWB, is mainly due to the competitive prices for promotion as TMX starts operation. But the sustainability will eventually depend on the market price of the crudes and freight,\" a refining engineer with Sinopec said. Top feedstock importers for independent sector ('000 MT) Jul-24 Jun-24 Change Jul-23 Change Zhejiang Petroleum & Chemical 3,671 3,332 10.2% 3,021 21.5% Hengli Petrochemical 1,575 1,297 21.4% 1,321 19.2% Shenghong Petrochemical 1,180 1,504 -21.5% 1,310 -9.9% Kedama 1,085 1,075 0.9% 524 107.1% Dongming 810 920 -12.0% 983 -17.6% Hebei Xinhai 677 300 125.7% 250 170.8% ChemChina 550 625 -12.0% 1,612 -65.9% Fengli 520 260 100.0% - - Hualian 412 400 3.0% 330 24.8% Jincheng 340 670 -49.3% 500 -32.0% Total* 15,454 15,413 0.3% 17,114 -9.7% Total* (Mil B\/D) 3.654 3.766 -3.0% 4.047 -9.7% *Includes imports of other recipients Source: S&P Global Commodity Insights ","headline":" Independent refiners' July feedstocks imports hit 3-month low at 3.65 mil b\/d","updatedDate":"2024-08-05T08:19:40.000"},{"Unnamed: 0":353,"body":" Premiums of Singapore's August term ex-wharf marine fuel 0.5%S barrels rose on the month and were signed around $7-$13\/mt to the benchmark FOB Singapore marine fuel 0.5%S cargo values, traders said Aug. 5, above the most inked $5-$8\/mt premiums for July-loading barrels previously. Despite adequate inventories overall, the downstream low sulfur fuel oil market in Singapore, the world\u2019s largest bunker hub, recently strengthened significantly as fewer suppliers could secure barge reloading in late July amid deferred loading schedules toward early August through the first half of August onward, traders said. Recent spikes in bunker premiums curbed overall demand to moderate levels at best, while buoyed LSFO arbitrage flows toward Singapore for August arrivals could weigh on near-term valuations. A few upstream LSFO suppliers deferred ex-wharf physical deliveries reportedly due to off-specification cargoes, momentarily limiting stockpiles of the bunker-grade compliant product, and thinned barge availabilities for very prompt refueling requirements, according to industry sources. However, traders\u2019 bullish sentiments were recently moderated with reportedly more resumptions of barge reloads at local terminals, with more suppliers securing ex-wharf loadings, thus likely to ease the tighter-than-usual barging schedules gradually for the near term. \u201cSuppliers are now playing catch up with [the loss in] all the July sales,\u201d a Singapore-based bunker supplier said, referring to downstream sellers affected by the deferred barge reloading schedules. The Platts Singapore-delivered marine fuel 0.5%S bunker premium over the benchmark FOB Singapore Marine Fuel 0.5%S cargo value climbed to a near six-month high of $30.66\/mt Aug. 1, before inching down to $29.34\/mt Aug. 2, and was last assessed higher at $34.15\/mt Feb. 8, S&P Global Commodity Insights data showed. \u201cEx-wharf premiums were still strong as of late July. Buying interests and offers shifted toward H2 August already,\u201d a Singapore-based fuel oil trader said, citing limited offers previously available for H1 August loading dates. Suppliers grappling with lackluster downstream margins could also see some momentary relief, as spreads between Singapore\u2019s delivered marine fuel 0.5%S price versus the ex-wharf grade, or barge spreads, widened to average $6.04\/mt across July, above the $4.26\/mt in June. Most recently, the spreads jumped to a near six-month high of $19\/mt Aug. 1, before narrowing to $18\/mt Aug. 2, Commodity Insights data showed. \u201cLSFO volumes transferred are still relatively small, and we have [the] option to switch bunkering ports if Singapore\u2019s premiums are too high\u2026 These days, premiums [have] been higher for near dates,\u201d a shipping company source said Aug. 5, indicating some diversion in demand to manage procurement costs. August arbitrage replenishments rise Asian LSFO fundamentals, which garnered support since late July amid tight prompt supplies and some loading delays in the downstream bunker market, are expected to come under pressure in August as higher arbitrage arrivals from the West adds to already increasing regional supplies, market sources said. Aided by viable arbitrage economics in recent weeks, the Singapore hub is now expected to receive around 2.5 million-2.6 million mt of LSFO from the West in August, up from about 2.2 million-2.4 million mt scheduled for July, Commodity Insights reported earlier. Alongside the low sulfur straight run fuel oil barrels from Nigeria\u2019s Dangote refinery coming into Asia, traders said regional supplies from countries such as Indonesia and Thailand have also been rising in recent weeks. The market is also expecting potentially more exports from Kuwait\u2019s Al Zour refinery in coming weeks after they issued two recent spot tenders for July and August loadings, despite the peak summer months with seasonally strong power generation demand, several traders said. In addition to growing supplies, Singapore\u2019s LSFO bunker sales have persistently remained sluggish this year as scrubber-installed ships, undertaking longer routes due to the ongoing Red Sea crisis, have propelled demand for HSFO grades, sources said. Platts assessed the Singapore marine fuel 0.5%S cargo's differential over Mean of Platts Singapore marine fuel 0.5%S assessment at a premium of $4.42\/mt at the Asian close Aug. 2, down from $5.75\/mt in the previous session, and sinking to its lowest in four weeks, Commodity Insights data showed. Near-term LSFO supplies are looking quite ample, especially on the back of such a sizable arbitrage inflow from the West, said a second Singapore-based trader. \u201cI am expecting the cash premiums and overall LSFO market fundamentals to come off gradually.\u201d ","headline":"Singapore\u2019s Aug ex-wharf term LSFO premiums rise, demand moderate","updatedDate":"2024-08-05T07:58:20.000"},{"Unnamed: 0":354,"body":" Crude oil futures were lower in midafternoon Asian trade Aug. 5, paring early gains on recession fears and the rising risk of an escalation in Middle East tensions. At 3:18 pm Singapore time (0718 GMT), the ICE October Brent futures contract was down 63 cents\/b (0.82%) from the previous close at $76.18\/b while the NYMEX September light sweet crude contract fell 70 cents\/b (0.95%) at $72.82\/b. Risk assets retreated aggressively through Asian trade as volatility surged through the session, leading to a slump in crude oil prices that were already described as oversold against underlying fundamentals. \"Rising volatility forces investors to cut exposure across the board, hence the spillover to commodities from the current rout in equities,\" said Ole Hansen, Saxo's head of Commodity Strategy, Aug. 5. Trading curbs were activated in South Korea for the first time in four years after equities tumbled through early trade. Japanese stocks also sank into a bear market. \"The talk of the town has been the contagion effect of this multi-pronged bear assault, which now seems to have shifted into a self-perpetuating mode,\" said SPI Asset Management Managing Partner, Stephen Innes. \"The global markets are facing a barrage of crises, making any hopes of a Monday recovery rally seem like a distant fantasy,\" he said, echoing multiple analysts of the view that the US Federal Reserve may now be behind the curve in their interest rate cut cycle. Markets watchers also continued to monitor the tensions in the Middle East where the US has warned that Iran could strike Israel in the coming days, regional media reported Aug. 5. \"Markets are weak ... economic data last week stressed markets and geopolitical stress in Middle East amplified the concerns,\" Priyanka Sachdeva, senior market analyst at Phillip Nova, told S&P Global Commodity Insights Aug. 5. \"Missing clarity on the Fed's take on rate cuts is [also] keeping a cap on economic growth prospects.\" Meanwhile, Asian services activity data offered some support to crude prices with the services Purchasing Managers' Index data from China and Japan reflecting an expansion in activity. \"China\u2019s Caixin services PMI beat estimates, helping to alleviate fears about China\u2019s economic outlook,\" Saxo's Hansen added. China's services economy has been a key pillar of crude demand amid a dearth in activity in the country's energy-intensive manufacturing sector. Over the weekend, China's State Council published a communique of plans to boost domestic demand, focusing particularly on the \u201ceat, drink, and play\u201d categories, which have support transportation and tourism segments. Dubai crude Dubai crude swaps and intermonth spreads were narrower in midafternoon Asian trading Aug. 5 from the previous close. The October Dubai swap was pegged at $74.16\/b at 2:40 pm Singapore time (0640 GMT), down $4.11\/b (5.25%) from the previous Asian market close. The September-October Dubai swap intermonth spread was pegged at 50 cents\/b, down 12 cents\/b over the same period, and the October-November intermonth spread was pegged at 32 cents\/b, down 13 cents\/b. The October Brent-Dubai exchange of futures for swaps was pegged at $1.96\/b, up 20 cents\/b. ","headline":" Crude slumps as market volatility rages on recession, Middle East risks","updatedDate":"2024-08-05T07:22:12.000"},{"Unnamed: 0":355,"body":" Pakistan\u2019s high sulfur fuel oil exports surged nearly threefold on the year to 820,484 mt in the financial year ended June 30, as refineries ramped up shipments to reduce inventories at their terminals in the wake of a shift to cheaper power generation alternatives, latest data from the Oil Companies Advisory Council showed. The country also exported 276,979 mt of low sulfur fuel oil during the financial year, compared with no volumes the year before. The government has been discouraging power generation companies from using fuel oil while encouraging cheaper sources like nuclear, coal, hydel and LNG, said Muhammad Awais Ashraf, research director at AKD Securities, a Karachi-based broking firm. \u201cRefineries have no alternatives but to export fuel oil ... [and] run the units at the desired level to reduce fuel oil stocks at the terminal,\u201d he said. Pakistani refineries aim to reduce fuel oil production over the next three to four years, converting their operations to increase the throughput of Euro-V standard petrol and diesel products, according to government sources. The Asian high sulfur fuel oil market has been supported by seasonal power generation demand from South Asian countries such as Bangladesh and Sri Lanka, and stable bunkering activity on the back of increasing high-sulfur grade consumption by scrubber-installed ships, according to trade sources. Tighter non-sanctioned supplies in the region have strengthened HSFO fundamentals, with Pakistan fuel oil likely absorbed by buyers favoring such volumes, traders said. The M1-M2 spread for the 380 CST grade averaged at a backwardation of plus $13.98\/mt in July, compared with the June average of plus $7.65\/mt, Platts data from S&P Global Commodity Insights showed. Pakistan, which traditionally was a net importer of fuel oil, has become an exporter of the residual fuel grade since last year, adding to the regional supplies and weighing on prices, trade sources said. Platts assessed the benchmark Singapore 380 CST high sulfur fuel oil cargo\u2019s cash premium over the MOPS 380 CST HSFO assessment 93 cents lower on the day at a premium of $4.42\/mt on Aug. 2, hurt by slower buying interest and competitive offers from Trafigura during the Platts Market on Close assessment process. Power generation Pakistan's electricity generation from fuel oil-fired plants fell 51.5% on the year to 2,428 GWh in FY 2023-24, according to data from the National Electricity Power Regulatory Authority. Meanwhile, the country\u2019s reliance on other power generation sources picked up during the year. Power generated from hydel rose 10% on the year to 39,872 GWh, regasified LNG gained 7% on the year to 23,755 GWh and local coal surged 55% on the year to 15.197 GWh. Electricity generated in the country during the financial year fell to a four-year low of 127,167 GWh, from a 129,591 GWh a year earlier. \u201cThe fall in consumption was mainly due to the higher electricity tariffs, rising inflation and an overall decline in economic activities, [which] led to the decline in power generation,\u201d said Tahir Abbas, head of research at Arif Habib, a Karachi based broking firm. The government\u2019s decision to generate less electricity from fuel oil-fired plants had reduced HSFO consumption in the country, with demand in the latest financial year slumping 49% on the year to 1.04 million mt, OCAC data showed. Key Pakistani refineries\u2019 fuel oil stockpiles (unit: mt) July 2024* June 2024 M-o-M change July 2023 Y-o-Y change PARCO 90,326 139,834 -35% 83,223 8.5% NPL 30,871 38,132 -19% 18,995 62.5% PRL 9,293 16,110 -42% 19,660 -53% ARL 16,981 44,448 -62% 11,717 45% Cynergico 21,377 59,647 -64% 9,683 120% Total 168,848 298,171 -43% 143,238 17.8% *As of July 25 Source: Refinery sources ","headline":"Pakistan's HSFO exports nearly triple as focus shifts to cheaper power sources","updatedDate":"2024-08-05T07:21:11.000"},{"Unnamed: 0":356,"body":" Taiwan's consumption of oil products fell 2.96% on the month but rose 12.4% on the year to 758,139 b\/d in June, with month-on-month increases in consumption offset by a steep fall in naphtha consumption, the latest data from the Ministry of Economic Affairs' Energy Administration showed. \"Domestic demand isn\u2019t that good. Oil product consumption will be about the same level usually,\u201d a Northeast-Asia refinery source said. Taiwan's naphtha consumption tumbled 9.5% on the month but rose 4.9% on the year to 329,000 b\/d in June. Olefin margins continues to be weak as the spread between CFR Northeast Asia ethylene and CFR Japan naphtha physical averaged at $160.81\/mt in June, down from May average of $182.77\/mt. This is below the typical breakeven spread of $250\/mt for integrated producers and $300-$350\/mt for non-integrated producers, S&P Global Commodity Insights data showed. Taiwan's Formosa Petrochemical reduced its operating rate to an average of 70% to 75% capacity at its No. 2 and No. 3 naphtha-fed steam crackers in Mailiao while the No.1 unit was shut for maintenance, Commodity Insights reported previously. Consumption edges higher Taiwan's diesel consumption edged 2.2% higher on the month but fell 3.7% on the year to 109,000 b\/d in June. In recent spot activity, Taiwan's state-owned CPC sold 450,000 barrels of 10 ppm sulfur gasoil for Sept. 1-20 loading at a discount of 60-70 cents\/b to the September average of Mean of Platts Singapore 10 ppm sulfur gasoil assessments, FOB Kaohsiung. Meanwhile, Taiwan's Formosa Petrochemical sold 300,000 barrels of ultra low sulfur diesel via private negotiation, at a discount of around 90 cents\/b to the loading-month average of MOPS 10 ppm sulfur gasoil assessments, FOB Mailiao. Trade sources said both cargoes were sold to the same Australian buyer who will likely co-load the cargoes to optimize ship economics. Separately, Formosa sold 750,000 barrels of ultra low sulfur diesel loading over Sept. 18-22, at a discount of around 90 cents\/b to the loading-month average of MOPS 10 ppm sulfur gasoil assessments, FOB Mailiao. The buyer was heard to be an oil major, according to trade sources. Taiwan's jet fuel demand inched 0.9% higher on the month and surged 15.3% on the year to 6,000 b\/d in June, the data showed. Global air passenger demand, measured in revenue passenger kilometers (RPK), rose 9.1% year on year in June, driven by the summer holiday season, data from the International Air Transport Association showed July 31 showed, giving a boost to jet fuel prices. Reflecting stronger demand for jet fuel during the month, the Platts-assessed FOB Singapore jet fuel\/kerosene cargo flat price averaged $97.33\/b in June, rising from $95.43\/b in May, Commodity Insights data showed. Motor gasoline consumption rose 1.1% on the month but fell 3.9% on the year to 163,000 b\/d in June, with near-term demand possibly hampered by rising pump prices. CPC and Formosa Petrochemical raised prices for 92 RON Gasoline for a fifth consecutive week, with prices up NT 20 cents\/liter to T$30\/l in the week beginning Aug. 5, local media reported. Taiwan's fuel oil demand firmed 3% on the month to 79,218 b\/d in June, a level that was more than seven-fold the volume consumed in the corresponding month in 2023. Asia's low sulfur fuel oil fundamentals, which garnered strength in recent weeks amid tight prompt supplies and some loading delays in the downstream bunker market in Singapore, were expected to see potential downsides in August as higher arbitrage inflows from the West adds to already increasing regional supplies, while the high sulfur fuel oil market remains relatively well supported amid seasonal utility demand and stable bunkering activity, market sources said. The Platts-assessed Singapore Marine Fuel 0.5%S cargo's cash differential over the Mean of Platts Singapore Marine Fuel 0.5%S assessment, which posted a monthly gain of 62% in July, averaged $6.09\/mt during the month, up from an average of $2.47\/mt in June, Commodity Insights data showed. Platts assessed the LSFO premium $1.33\/mt lower on the day at a premium of $4.42\/mt Aug. 2, the lowest since July 5, when it was assessed at a premium of $4.31\/mt, the data showed. Taiwan's oil products demand in June: Unit: '000 b\/d Jun-24 Jun-23 Change May-24 Change LPG 72 61 17.8% 67 6.3% Naphtha 329 314 4.9% 364 -9.5% Motor gasoline 163 170 -3.9% 161 1.1% Jet 6.0 5.9 0.9% 5.2 15.3% Diesel 109 113 -3.7% 106 2.2% Fuel oil 79.218 10.986 621.1% 76.930 3.0% Source: Ministry of Economic Affairs' Energy Administration ","headline":" June oil products demand falls 3% on month to 758,139 b\/d","updatedDate":"2024-08-05T06:32:40.000"},{"Unnamed: 0":357,"body":" Japan's third-largest refiner Cosmo Oil restarted the 75,000 b\/d No. 1 CDU at its 177,000 b\/d Chiba refinery in Tokyo Bay Aug. 4 after technical issues, a company spokesperson said Aug. 5. The crude distillation unit had been shut June 6-July 16 due to planned maintenance to update power-related equipment, S&P Global Commodity Insights previously reported. The Platts-assessed gasoline, kerosene and gasoil prices across the Chiba, Kanagawa, Chukyo and Hanshin regions averaged Yen 77,550\/kiloliter ($2.05\/gallon), Yen 78,000\/kl and Yen 76,600\/kl, respectively, on Aug. 5, S&P Global Commodity Insights data showed. ","headline":" Japan's Cosmo restarts No. 1 Chiba CDU after glitches","updatedDate":"2024-08-05T06:09:20.000"},{"Unnamed: 0":358,"body":" Asian petrochemicals prices are seen mixed in the week of Aug 5-9, amid varying market fundamentals. Among aromatics, supply for benzene is expected to increase while demand for toluene is seen firm. Meanwhile, plant shutdowns amid continued poor demand from downstream market are likely to keep propylene stable. Methanol could trade sideways this week, with volatility in crude oil and Chinese methanol futures seen impacting the CFR China prices. Benzene ** Market participants expect benzene prices to ease, as South Korea\u2019s S-Oil resumes operations at its benzene production line at the No. 2 aromatics plant in Onsan. ** Lower-than-expected inventory build in east China ports have led some market participants to believe that demand for CFR China cargoes should remain healthy. ** The weekly average of the Platts-assessed FOB Korea benzene marker rose $18.83\/mt to $995.76\/mt in the week ending Aug. 2, S&P Global Commodity Insights data showed. Toluene ** The Asian toluene market in Northeast Asia is expected to detach itself further from South and Southeast Asia prices in the week ahead, with strong buying for South Korea-origin cargoes pulling prices up on the FOB Korea market. ** The Platts-assessed toluene FOB Korea marker jumped $41\/mt week on week to $886\/mt on Aug. 2, led by buy interests heard up to $885\/mt to no counters, Commodity Insights data showed. ** In the China market, the FOB China marker was up $15\/mt on the week, lagging behind the FOB Korea marker, while CFR China prices were down $9\/mt over the same period, in line with the weaker domestic China ex-tank market. Styrene monomer ** Styrene monomer prices may soften as a correction after the rally seen in the previous week due to global supply concerns and stronger international prices, industry sources said. ** Styrene inventory rose marginally in east China with stocks up by 100 mt to 51,300 mt in the week ending Aug. 2, trade sources said. ** Asian styrene monomer prices were assessed $29\/mt higher on the week at $1,145\/mt CFR China and $1,130\/mt FOB Korea Aug. 2. Isomer MX ** Asian markets are expected to be long on isomer MX cargoes, a situation compounded by the S-Oil fire, which is seen adding additional cargoes for sale to the market. ** Some of the isomer MX cargo is off-specification for chemicals usage, and may go into the gasoline blend pool, said sources. However, gasoline traders are likely to seek heavily discounted prices. ** FOB Korea isomer MX tracked weak crude oil market with prices falling to $873\/mt FOB Straits on Aug. 2 from $887\/mt on July 26. MTBE ** The Asian MTBE market is expected to remain weak, with gasoline demand still looking soft. ** China domestic prices were higher than in Singapore, with a closed arbitrage window extending into the next week. Singapore prices were weak, frequently falling below $800\/mt FOB Straits. ** Platts assessed MTBE FOB Straits at $784\/mt FOB Straits on Aug. 2, from $813\/mt on July 26. Methanol ** Asian methanol prices could trade sideways in the week to Aug. 5 but volatility in crude oil and Chinese methanol futures could see CFR China methanol prices oscillating either way. ** Spot trading activity in Southeast Asia is expected to be thin with the region balanced in supply and demand. ** Platts assessed CFR China methanol down $2.50\/mt week on week at $288\/mt and CFR Southeast Asia $4.50\/mt lower at $346\/mt on Aug. 2. Propylene ** The Asian propylene complex is expected to remain stable amid mixed fundamentals. Plant shutdowns may support the market while continued poor demand from downstream markets is seen keeping the supplies buoyed in the region. ** Platts assessed the propylene CFR China marker down $10\/mt on the week at $865\/mt Aug. 2. Polypropylene **The Southeast Asian polypropylene markets remain on a downtrend, as converters in the region remain cautious owing to weak end-user demand. **The Chinese polypropylene market is anticipated to remain rangebound. Despite weak underlying demand, prices remain supported by macroeconomic sentiment and fluctuations in domestic futures. **Platts assessed CFR SEA PP raffia and injection prices down $5\/mt at $950\/mt in the week ending August 2, while CFR China PP raffia and injection prices were stable on the week at $915\/mt, and China domestic PP raffia prices were up Yuan 30\/mt on the week at Yuan 7,620\/mt. PVC ** The Asian polyvinyl chloride complex is expected to remain rangebound as market participants hold mixed views regarding India's buying activity. ** China-India freight rates were seen moving down, sources said, as the Platts-assessed CFR India marker fell $40\/mt on the week to $870\/mt at the July 31 Asian close. R-PET ** Southeast Asian recycled polyethylene terephthalate clear flake (including premium grade) markets were on a downtrend, and prices are expected to weaken further as EU buyers paused purchases. Freight rates to the Middle East were heard to be improving, enabling exports to the region. ** Offers for FOB Southeast Asian R-PET food-grade pellets were stable, although recyclers\u2019 margins remain pressured by high PET bottle bale feedstock costs in the region. ","headline":" Key market indicators for Aug 5-9","updatedDate":"2024-08-05T06:05:40.000"},{"Unnamed: 0":359,"body":" The total traded volume of DME Oman crude futures inched up 1.51% on the month to 127,116 lots in July, Dubai Mercantile Exchange data showed Aug. 5, as a wider East-West spread supported demand for the grade from its main customer, China, despite still poor end-user margins there. Since the start of the year, the exchange has recorded an increase in total traded volumes every month, extending its streak for the seventh consecutive time in July. All contracts traded on the DME consisted entirely of Oman crude futures. The DME also lists other crude futures contracts, including Oman crude financial futures and the Brent-Oman futures spread. The rise in volumes comes as a wider Brent-Dubai Exchange of Futures for Swaps spread helped support demand for Middle Eastern sour crudes despite still poor margins afflicting end-users across the region. The front-month EFS spread had risen over the first half of July to touch a four-month high of $2.48\/b July 19. It was last higher March 4 when it was assessed at $2.54\/b. Platts assessed front-month cash Oman over same-month Dubai futures meanwhile at an average premium of $1.60\/b over July, up 75 cents\/b on the month, S&P Global Commodity Insights data showed. Weak demand is expected to weigh on China's annual crude throughput for the rest of the year. In the first half of 2024, the throughput declined 0.9% on the year to 14.5 million b\/d, according to data from the National Bureau of Statistics. In July, China's combined throughput, which includes state-run refineries and mega private plants, reached 10.23 million b\/d with an 83% utilization rate, lower than the 10.41 million b\/d needed for an 85.6% capacity utilization a year earlier, data collected by Commodity Insights showed. Meanwhile, the exchange announced July 10 that it will be renamed to the Gulf Mercantile Exchange effective Sept. 2, following Saudi Tadawul Group's acquisition of a 32.6% strategic stake, Commodity Insights reported previously. This comes as DME's front-month trading volume soared by an impressive 31%, reaching 505 million barrels during H1 2024, compared with 385 million barrels in the second half of 2023, the exchange said in a July 8 notice. Additionally, the physical delivered volume for H1 2024 rose by 9% to 113 million barrels, up from 104 million barrels in H2 2023, while the total exchange volume saw substantial growth of 21% over the period, touching 680 million barrels, compared with 562 million barrels in H2 2023. However, open interest for the Oman futures contract stood at 15,380 lots on July 31, plunging 32.1% from the end of June. DME Oman futures is a physically delivered futures contract for Oman crude blend. Oman crude -- which has a gravity of 33.2 API and a sulfur content of 1.3% -- typically sees the lion's share of its exports going to mainland China, with some barrels also going to Taiwan, Japan, South Korea and India. Total traded volumes: July June MoM change Oman crude futures 127,116 125,225 1.51% Total open interest: As of July 31 As of June 28 MoM change Oman crude futures 15,380 22,633 -32.05% Source: Dubai Mercantile Exchange ","headline":"DME Oman crude futures traded volume rises for seventh straight month in July","updatedDate":"2024-08-05T05:48:02.000"},{"Unnamed: 0":360,"body":" Open interest for front-month Singapore August gasoline derivative contracts that traded on the Intercontinental Exchange in July rose 14.55% on the month to 41.19 million barrels, latest ICE data showed. Open interest for the front-month August Singapore 92 RON gasoline swaps contract gained 17.98% on the month to 28.61 million barrels in July. The uptick in market liquidity came amid an increase in supply volatility as regional demand slipped seasonally. The Asian gasoline complex softened in July due to tepid demand from Indonesia after the festive season as the country moved away from the Eid al-Adha period, trade sources said. The ongoing monsoon season in India also dampened demand for transportation fuels, leading to an estimated 84,000 b\/d decline in gasoline demand, analysts at S&P Global Commodity Insights said in their latest South Asia short-term outlook. Demand for gasoline in Vietnam -- one of the region's largest buyers of higher octane gasoline -- also fell on the back of heavy flooding, sources said. The regional supply outlook, however, remained relatively unclear amid concerns of a potential increase in Chinese export volumes in August. For now, China's clean oil product exports in 2024 are anticipated to remain stable on the year at around 40 million mt due to less favorable export margins and a slight domestic surplus. Open interest for gasoline futures contracts on ICE: Mogas (Unit: '000 barrels) Aug OI Jul OI M-o-M Change Singapore Mogas 92 28,613 24,253 17.98% Singapore Mogas 92\/Brent 12,574 11,702 7.45% Total 41,187 35,955 14.55% Source: Intercontinental Exchange Notes: Open interest for a month is measured at the end of the previous month ","headline":"ICE front-month Singapore gasoline swaps open interest rises 14.6% on month in July","updatedDate":"2024-08-05T05:34:38.000"},{"Unnamed: 0":361,"body":" The Asian gasoline complex is expected to remain firm over Aug. 5-9 underpinned by lower export flows amid an unplanned refinery shutdown in Japan, sources said. In northeast Japan, ENEOS, the country\u2019s largest refiner, shut down the sole 145,000 b\/d crude distillation unit at its Sendai refinery Aug. 1 due to technical problems, according to a company source. No further details were provided regarding the restart date. The Platts-assessed gasoline cash premium, as of Aug. 2 was at the Mean of Platts Singapore minus $0.26\/b. This represents a sharp decrease of 127.36% from the previous week\u2019s closing value of MOPS plus $0.95\/b on July 26. Naphtha ** The Asian naphtha market continues to be on a downtrend as poor downstream demand exacerbated the complex, market sources said. ** Reflecting the weakening market, the H2 September\/H2 October time spread was flat at the Asian close Aug. 2, narrower from $0.50\/mt the previous day, S&P Global Commodity Insights data showed. ** Platts assessed the front-month Singapore reforming spread -- the difference between Singapore 92 RON gasoline and naphtha derivatives and a barometer of the economic attractiveness of naphtha's use in gasoline blending -- at $15.36\/b on Aug. 2, down $1.78\/b on the week, Commodity Insights data showed. MTBE ** The Asian market was expected to remain weak, with gasoline demand still looking thin. ** China domestic prices were higher than in Singapore, with a closed arbitrage window extending into the next week. Singapore prices were weak, frequently falling below $800\/mt FOB Straits. ** FOB Straits assessment was down $29\/mt week on week to close at $784\/mt FOB Straits on Aug. 2, from $813\/mt on July 26. Toluene ** The Asian toluene market in Northeast Asia is expected to detach itself further from South and Southeast Asia prices in the week ahead, with strong buying for South Korea-origin cargoes pulling prices up on the FOB Korea market. ** The Platts-assessed toluene FOB Korea marker jumped up sharply $41\/mt week on week to $886\/mt on Aug. 2, led by buy interests heard up to $885\/mt to no counters, Commodity Insights data showed. There was a 2,000-mt trade heard done at $880\/mt FOB Korea, for any-September loading, letter of credit at sight basis Aug. 2. ** In the China market, the FOB China marker was up $15\/mt on the week, lagging behind the FOB Korea marker, while CFR China prices were down $9\/mt over the same period, in line with the weaker domestic China ex-tank market. Ethanol ** US Gulf to Philippines freight prices edged down this week to $90-$100\/mt, with MR tanker freight rates heard at around $80\/mt, sources said. ** US Energy Information Administration data released July 31 for the week ended July 26 showed that ethanol production soared to an all-time peak, up 14,000 b\/d, or 1.28%, to 1.109 million b\/d. The previous benchmark of 1.108 million b\/d was set during the week of Dec. 1, 2017. Compared to the year-ago week, production was 42,000 b\/d, or 3.94%, higher. ** The Platts-assessed CIF Philippines bioethanol marker slumped $41.33\/cu m on the week to $615\/cu m Aug. 2, Commodity Insights data showed tracking US futures and lower freight rates. Isomer-MX ** Asian markets are expected to be long on isomer MX cargoes, a situation compounded by the S-Oil fire, which will only add additional cargoes for sale to the market. Sources have said that China could be a potential buyer for cargo. ** Some of the isomer MX cargo is off-specification for chemicals usage, and may go into the gasoline blendpool, said sources, but gasoline traders look set to ask for heavily discounted prices. ** FOB Korea isomer MX assessment followed downward crude oil market with prices falling to $873.5\/mt FOB Straits on Aug. 2, from $887\/mt on July 26. Aug-02 W-o-W Change RON Price per Ron ($\/mt) Price per Ron ($\/cu m) GASOLINE FOB Singapore 91 RON non-oxygenated $89.94\/b -3.48% 91 NA NA FOB Singapore 92 RON oxygenated $87.7\/b -3.56% 92 FOB Singapore 95 RON oxygenated $92.86\/b -2.62% 95 FOB Singapore 97 RON oxygenated $93.66\/b -2.45% 97 BLENDSTOCKS FOB Singapore Naphtha $72.34\/b -1.27% 72 4.72 5.35 FOB Korea Toluene $886\/mt 4.85% 115 6.11 9.79 FOB Singapore MTBE $784\/mt -3.57% 115 1.68 1.90 FOB Korea Isomer-MX $873.5\/mt -1.52% 113 6.10 10.63 CIF Philippines Ethanol $615\/cu m -6.30% 118 1.21 3.01 ","headline":" Key market indicators for Aug 5-9","updatedDate":"2024-08-05T05:31:52.000"},{"Unnamed: 0":362,"body":" The total traded volume of Dubai crude futures rose 11.40% on the month to 1.82 million lots in July, Intercontinental Exchange data showed Aug. 5, amid still-weak refining margins in the Asian market, although wider East-West spreads kept end-user demand focused on Dubai-linked sour crudes. ICE Dubai crude futures comprises Dubai first-line futures, Dated Brent versus Dubai first-line futures and Brent first-line versus Dubai first-line futures. In July, traded volumes for Dated Brent versus Dubai first-line futures fell 20.11% to 12,664 lots, while Dubai first-line futures increased 17.03% to 1.22 million lots and Brent first-line versus Dubai first-line futures edged up 2.1% to 588,285 lots. One lot is equivalent to 1,000 barrels. The rise in traded volumes came amid a still-weak Asian market as end-users across the region continued to grapple with poor margins and weak domestic demand. Nonetheless, the Dubai complex received some support from a largely closed arbitrage window for light, sweet US crudes to Asia, while a wider Brent-Dubai Exchange of Futures for Swaps spread also hindered the flow of Brent-linked crudes from West Africa, Europe and the Mediterranean into the region. The front-month Dubai cash-futures spread averaged at a premium of $1.60\/b over July, up 74 cents\/b from a premium of 85 cents\/b over June. The Brent-Dubai Exchange of Futures for Swaps spread meanwhile had risen over the first half of July to touch a four-month high of $2.48\/b July 19. It was last higher March 4 when it was assessed at $2.54\/b. Open interest volumes As of July 31, the combined open interest volumes for the Dubai crude futures forward curves stood at 947,555 lots, rising 4.83% on the month. The Dubai first-line futures contracts saw the largest increase of 7.25% to 479,354 lots, while the Dated Brent versus Dubai first-line futures decreased 29.75% on the month to 26,291 lots at end-July. Additionally, open interest for front-month Dubai crude futures contracts on ICE dropped 17.61% on the month to 181,798 lots at end-July, data compiled by S&P Global Commodity Insights showed. The decline was led by the Brent first-line versus Dubai first-line futures contract, which fell 21.24% on the month to 74,107 lots. The M1 Dubai swap settled at $84.99\/b at the start of July and ended the month 7.25% lower at $78.83\/b, Commodity Insights data showed. Platts assessed September Brent-Dubai EFS at $1.61\/b on July 31, increasing 23 cents\/b or 16.67% from July 1, according to Commodity Insights data. Front-month open interest As of July 31 As of June 28 MoM change Dubai 1st Line 99,850 115,168 -13.30% Dated Brent vs Dubai 1st Line 7,841 11,387 -31.14% Brent 1st Line vs Dubai 1st Line 74,107 94,096 -21.24% Total 181,798 220,651 -17.61% Total open interest As of July 31 As of June 28 MoM change Dubai 1st Line 479,354 446,949 7.25% Dated Brent vs Dubai 1st Line 26,291 37,423 -29.75% Brent 1st Line vs Dubai 1st Line 441,910 419,538 5.33% Total 947,555 903,910 4.83% Total traded volumes As of July 31 As of June 28 MoM change Dubai 1st Line 1,217,345 1,040,243 17.03% Dated Brent vs Dubai 1st Line 12,664 15,852 -20.11% Brent 1st Line vs Dubai 1st Line 588,285 576,194 2.10% Total 1,818,294 1,632,289 11.40% Source: Intercontinental Exchange ","headline":"ICE Dubai crude futures July total traded volume rises 11.4% on month","updatedDate":"2024-08-05T05:29:16.000"},{"Unnamed: 0":363,"body":" Asian sour crude traders and end-users welcomed Saudi Aramco's lower-than-expected September crude oil official selling prices for Asia-bound cargoes, with some saying the OSPs were a nod to an Asian market still struggling with poor margins and demand, as well as an impending ramp-up in output from the OPEC+ group. The producer in an early Aug. 5 notice raised the Asia-bound September OSP differential for its flagship Arab Light grade by 20 cents\/b to a premium of $2\/b to the Oman\/Dubai average. The September OSP differential for Arab Extra Light and Super Light was raised by a range of 10-20 cents\/b, while that for Arab Medium and Heavy were kept unchanged on the month. Expectations leading into the OSP release had been for the producer to raise Arab Light by a range of 30-80 cents\/b, with Arab Extra Light and Super Light to be raised by largely the same extent, while the heavier Arab Medium and Heavy grades were expected to see slightly larger increases relative to Arab Light by about 10-20 cents\/b, S&P Global Commodity Insights earlier reported. \"Better than expected,\" one Asian end-user source said. The OSPs reflected an Asian end-user market still struggling with poor refining margins and weak domestic demand. An impending hike in OPEC+ output, after the group in an Aug. 1 meeting opted to stand pat on its policy to unwind voluntary production cuts from October, was likely also a contributing factor, traders said. Current OPEC+ plans call for eight members led by Saudi Arabia, Russia, Iraq and the UAE to begin gradually phasing out some 2.2 million b\/d in voluntary production cuts between October 2024 and September 2025. Aramco's OSPs have been overvalued relative to the spot market for the last one year, with current conditions and the impending production increases providing an opportunity for the producer to bring its OSPs more in line with spot prices, trade sources added. \"Think Saudi [Aramco] is partly correcting some of the premium that had accumulated in their OSPs over the last one year. Now that OPEC+ exports are rising and demand is sliding, that premium has to go,\" a trader said. The current month's October-loading cycle was bearish, with Asian refining margins still hovering at relatively weak levels despite having recovered from multiyear lows in May. Platts, part of Commodity Insights, pegged the Dubai-Singapore cracking netback margin at $2.74\/b Aug. 2, down 9 cents\/b on the day and far from when it started the year in the $4-$8\/b range. Key prices and spreads in the Dubai complex have also weakened sharply in recent days, with the second-month October Dubai crude swap pegged by Platts at $75.40\/b at 11 am Singapore time Aug. 5, down 3.7% from the Aug. 2 Asian close and a low not seen since Jan. 3 when it was assessed at $74.92\/b, Commodity Insights data showed. The October-November Dubai swap intermonth spread has similarly plunged, likely reflecting the prospect of increased OPEC+ supplies from October. The spread was pegged at 35 cents\/b at 11 am Singapore time Aug. 5, down 15 cents\/b on the week. ","headline":"Lower-than-expected Aramco Sep OSPs a nod to weak Asian market, OPEC+ cut unwind","updatedDate":"2024-08-05T05:13:22.000"},{"Unnamed: 0":364,"body":" Crude oil prices are expected to receive support over Aug. 5-8 from rising geopolitical tensions in the Middle East and an expansion in China's services activity. Front-month ICE October Brent crude oil futures were trading at $77.03\/b at 11:54 am Singapore time (0354 GMT) Aug. 5, rising 22 cents\/b or 0.3% from the previous settle. Middle East crude The Asian and Middle East sour crude markets saw the emergence of Saudi Aramco's September crude oil official selling prices in early morning trading Aug. 5, with Aramco's September allocations and spot trades expected to pick up shortly after. Aramco's September OSPs for Asia-bound cargoes were below market expectations, in a likely a concession by the producer to many Asian end-users grappling with poor margins and weak domestic product demand. The front-month Dubai cash-futures spread averaged at a premium of $1\/b over Aug. 1-2, down from an average premium of $1.60\/b in July. Asia-Pacific regional crude Trading activity is expected to ramp up over Aug. 5-8, with fresh October-loading program issues anticipated across regional crude and condensate barrels. The cash differentials for October-loading cargoes of medium sweet crudes could be stable to slightly weaker due to lower freight costs and a weakening Brent structure, market sources said. Market participants await the issuance of July Indonesian Crude Price and term tender results for Rang Dong crude by PetroVietnam Oil for loading over Oct. 1, 2024-March 31, 2025. The tender closed July 30, with validity until Aug. 9. Delivered crude US WTI Midland crude premiums into Asia may be stable to lower, with the latest trade levels heard at a premium in the mid-$3s\/b to October Dated Brent, DES Singapore for November-delivery barrels. Market participants are keeping an eye on fresh offers and trades for Brazil's Tupi crude for November-arrival barrels. The grade was last heard traded at a premium in the high $1s\/b to October Dated Brent, DES China. Oil futures Oil prices could increase over Aug. 5-8, as bearish macroeconomic sentiment and escalating Middle East tensions lead to market volatility. China's manufacturing PMI edged down 0.1 point to 49.4 in July, National Bureau of Statistics data showed. In the US, the Institute for Supply Management's July manufacturing purchasing managers' index fell for the fourth straight month to 46.8%, from 48.5% in June. The manufacturing sector represents about 11% of the US economy and 26% of China's economy. Platts, part of S&P Global Commodity Insights, assessed the prompt M1-M2 ICE Brent crude time spread at 54 cents\/b at the Aug. 2 Asian close, narrowing 31 cents\/b or 36.5% on the week. ","headline":" Key market indicators for Aug 5-8","updatedDate":"2024-08-05T04:41:18.000"},{"Unnamed: 0":365,"body":" Asia's light ends refined product gasoline market was expected to strengthen during the week of Aug. 5-8 amid regional refinery issues. LPG prices were also expected to get support amid continuing tensions in the Red Sea. However, naphtha prices could face pressure on the back of lower demand from South Korean naphtha cracking centers. Gasoline ** Asian gasoline could start this week on a positive note after last week\u2019s slump in cash premiums, underpinned by lower export flows amid an unplanned refinery shutdown in Japan and gasoline cargoes circulating within the European domestic market, sources said. ** In northeast Japan, the country\u2019s largest refiner ENEOS shut the sole 145,000 b\/d crude distillation unit at its Sendai refinery Aug. 1 due to technical problems, according to a company source. No further details were provided regarding the restart date. ** The negative East-West arbitrage, ranging between minus $7\/b and minus $8\/b, shows that spreads are more favorable for Europe, encouraging ships to remain in European waters due to better margins, according to market sources. The spread was pegged at minus $7.25\/b at 0300 GMT on Aug. 5. ** However, market participants are expecting fresh resupply sometime in September due to better refining margins and China\u2019s anticipated export quota announcement for the third quarter. **The Platts-assessed gasoline cash premium was at the Mean of Platts Singapore gasoline assessment minus 26 cents\/b as of Aug. 2. This represented a sharp decrease of 127.36% from the previous week\u2019s closing value at MOPS gasoline assessment plus 95 cents\/b on July 26, according to data from S&P Global Commodity Insights. Naphtha ** The physical C+F Japan naphtha marker was at $655\/mt in midmorning Asian trade Aug. 2, down $19.50\/mt from the previous Asian close. ** Asian naphtha prices were expected to fall on the back of low demand from South Korean naphtha cracking centers, sources said. ** Many South Korean units were running at lower run rates of 60%-70%, sources said. ** Cash differentials are expected to decrease this week as physical time spreads narrowed. The H2 September-H2 October time spread was flat at the Asian close Aug. 2, down from 50 cents\/mt the previous day, Commodity Insights data showed. ** The Platts-assessed CFR Northeast Asia ethylene-CFR Japan naphtha physical spread -- closely watched by petrochemicals producers -- widened $14.50\/mt on the week to $190.50\/mt at the Aug. 2 Asian close, Commodity Insights data showed. LPG ** The Asian LPG market was likely to see some strength as the landed cost of exports from the Middle East could rise amid higher freight costs following issues moving Very Large Gas Carriers from Yanbu due to tensions in the Red Sea, sources said. ** Saudi Aramco announced August contract prices at $590\/mt for propane and $570\/mt for butane, up $10\/mt and $5\/mt, respectively, Commodity Insights previously reported. ** However, Asian LPG prices could face some pressure amid slowing demand from China as PDH run rates remain stable, sources said. ** Broker sources pegged the front-month September FEI swap at $624\/mt early Aug. 5, down from the Platts assessment at $637\/mt at the Aug. 2 Asian close, on the back of a drop in front-month Brent crude markers. ","headline":" Key market indicators for Aug 5-8","updatedDate":"2024-08-05T04:38:39.000"},{"Unnamed: 0":366,"body":" A gradual decline in fuel oil export quota volumes for the rest of the third quarter is expected to support the downstream low sulfur fuel oil premium at China's Zhoushan bunkering hub, as market participants await the next batch of quotas. The volumes have continued to decline after the release of the previous fuel oil export quota in early May, with market participants expecting the next batch in one to two months. \u201cMost of [the export quota is] gone \u2026 I think it's probably less than 20%,\u201d a local bunker supplier said, anticipating the next fuel oil export quotas around end-August. \u201cLSFO export quotas are going to run out and refineries are reducing LSFO production.\u201d However, slower demand could cap gains in the premium in Zhoushan, leading to a little changed delivered spread versus Singapore in the near term, traders said. Singapore, the world's largest bunker hub, in recent months has been facing intense price competition from alternative bunkering locations, such as Zhoushan and neighboring Port Klang, as the LSFO premium in the city-state hit a near 6-month high. Local suppliers in Singapore have been waiting for the arrival of replenishment LSFO cargoes in the wake of some off-specification supply issues since late July. That has disrupted some downstream suppliers' barge reloading schedules, deferring ex-wharf loadings to early-August dates and leading to a wider spread with competing bunkering hubs such as Zhoushan. In early August, traders in Singapore have reported a gradual resumption of previously deferred barge reloadings at local terminals, as more suppliers strive to \"catch up\" with lost bunker-grade LSFO supplies from late July. Platts, part of S&P Global Commodity Insights, assessed the spread between Zhoushan-delivered marine fuel 0.5%S bunker over the delivered grade in Singapore at a discount of $6.00\/mt on Aug. 2, narrowing from $10.00\/mt on Aug. 1. The spread in July averaged at a discount of $1.57\/mt, narrowing from a discount of $6.53\/mt in June. The premium for Singapore-delivered marine fuel 0.5%S bunker against the benchmark FOB Singapore marine fuel 0.5%S cargo reached a near a six-month high of $30.66\/mt on Aug. 1, before declining marginally to $29.34\/mt on Aug. 2. Meanwhile, the premium for Zhoushan-delivered marine fuel 0.5%S bunker against benchmark FOB Singapore marine fuel 0.5%S rose $2.68\/mt on the day to $23.34\/mt on Aug. 2. The average premium for July strengthened to $12.91\/mt, from $4.19\/mt in June. Traders\u2019 LSFO sentiment for the Singapore hub has been more bearish for the later part of August through September, with stronger cargo inflows expected due to viable East-West arbitrage margins. Lower production, weather impact Market participants expect the premium to rise slightly in Zhoushan in August against the benchmark FOB Singapore marine fuel 0.5%S cargo value but remain at a discount to the delivered grade in Singapore. Lower production levels due to depleting current export quotas and adverse weather-related impacts could support the premium. \u201cZhoushan [LSFO premiums] in August, I think it will go up \u2026 the flat price is around Mean of Platts Singapore plus $15\/mt recently,\u201d another local bunker source said. A third local bunker supplier in Zhoushan said the next tranche of fuel oil quotas could be possibly smaller. \u201cThe refineries will have to cut back [on LSFO production].\u201d Bad weather conditions in Zhoushan have been a common occurrence and are expected to continue resulting in the loss of some supply days. Trade sources estimate that bad weather affects deliveries for nearly one-third of the year, with August expected to face more weather events than July. July saw some impact from weather as anchorages in Zhoushan were shut for about half a week due to strong winds due to Typhoon Gaemi making landfall in Taiwan. However, slower LSFO demand is expected to weigh on the premium in Zhoushan. \u201cI personally think the discount [to the delivered grade in Singapore] will continue until October, mainly due to a reduction in demand for fuel oil in China, and the continued decline in demand for gasoline and diesel. Marine fuel is no exception,\u201d a Chinese ship charterer said. ","headline":"China fuel oil quotas decline seen supporting Q3 LSFO premiums in Zhoushan","updatedDate":"2024-08-05T04:21:24.000"},{"Unnamed: 0":367,"body":" South Korea's third-quarter 2024 diesel demand could take a hit as domestic courier and parcel delivery truck operations are expected to fall significantly in the short term, after two major e-commerce companies filed for bankruptcy, middle distillate marketers at two refiners said Aug. 2-5. Two major South Korean e-commerce platform operators, WeMakePrice and TMON, filed for court receivership with the Seoul Bankruptcy Court July 29, as the two companies failed to repay vendors using their services amid liquidity crisis. The Seoul court decided to grant the two companies one month to seek debt restructuring on their own on Aug. 2. Middle distillate marketers at two major South Korean refiners indicated that they are reassessing their near-term diesel wholesale distribution and sales outlook as the two e-commerce firms' financial troubles could lead to a significant drop in domestic online shopping transactions and ultimately much lower courier truck operations throughout August or even September. The number of delivery packages or parcels that nationwide couriers handle every month averaged over 400 million so far this year, according to CJ Logistics. The financial issue at WeMakePrice and TMON would bode ill for domestic logistics as consumer online shopping activities through e-commerce platforms generate a large majority portion of courier companies' delivery operations, an official at CJ Logistics said. Diesel demand in Asia's fourth biggest oil consuming nation rose 1.9% year on year to 40.93 million barrels in the second quarter. Most of South Korea's diesel demand is driven by the transportation and logistics sectors. Reflecting the increase in demand, exports in Q2 slipped 0.6% year on year to 47.7 million barrels. Taking into account the potential drop in delivery truck turnover rate and overall online shopping logistical operations, on top of the dismal new housing projects and old apartment renovation activities, South Korea's Q3 diesel sales could slip under 40 million barrels, according to analysts and middle distillate marketing sources based in Seoul. The nation's biggest e-commerce platform operator Coupang is still thriving, which means any downside diesel demand impact from the logistics sector should be short lived, said a middle distillate distribution and sales manager at a major South Korean refiner. The government estimates the two troubled e-commerce companies' unsettled payments to be at around 274.5 billion won ($200 million) so far and the amount could more than triple due to the approaching settlement period for consumer-vendor transactions made during June and July. Asian market overview In the broader Asian gasoil complex, market participants are assessing the possibility of South Korea increasing exports in the event of a significant drop in August domestic sales as ample near-term regional supply and a lack of fresh demand drivers amid monsoon season continue to weigh on the ultra low sulfur diesel market. \u201cThe gasoil complex should receive some support in September as the monsoon season ends and there\u2019s some demand from Europe on the back of winter heating demand. Otherwise, demand is going to be weak in August,\u201d a regional middle distillate trader said. At the same time, trade participants were keeping close watch on refinery margins. \u201cIt is possible that we see some economic run cuts due to current oversupply but I don\u2019t think it will be that significant since cracks are still positive,\u201d an industry source said. Platts, part of S&P Global Commodity Insights, assessed the FOB Singapore 10 ppm sulfur gasoil derivative crack spread to the front-month Dubai swap -- which measures the relative strength of the product to the crude it is refined from -- narrowing 32 cents\/b on the day to $16.90\/b at the Aug. 2 Asian close. At this level, the crack is trading at a 92 cents\/b premium to that of jet fuel\/kerosene and $8.48\/b higher than 92 RON Gasoline, Commodity Insights data showed. ","headline":"South Korea's short-term diesel demand under pressure on e-commerce firms' bankruptcy","updatedDate":"2024-08-05T04:10:41.000"},{"Unnamed: 0":368,"body":" Open interest for front-month August Singapore 10 ppm sulfur gasoil swap contract traded on the Intercontinental Exchange rose 2.37% on the month to 41.12 million barrels in July, Intercontinental Exchange data showed Aug. 2. Despite the rebound, July\u2019s figure remains marginally lower than the front-month open interest seen in both April and May, historical data compiled by S&P Global Commodity Insights showed. While stockpiling demand for winter heating is due to begin in the coming months, current gasoil demand remains under pressure amid a seasonal lull due to the monsoons. Furthermore, Asia continued to witness a supply glut amid poor arbitrage economics to the West as elevated freight rates trapped barrels in the region. Reflecting stability in the swaps market, the Platts-assessed FOB Singapore 10 ppm sulfur gasoil front month derivative time spread was mostly unchanged across June and July, averaging about minus 10 cents\/b in both months. Looking ahead, Commodity Insights analysts revised down their forecast for Asian diesel\/gasoil demand growth by 60,000 b\/d to 90,000 b\/d in 2024. \"This reflects a downward revision to demand in mainland China, where the real estate sector continues to lag despite stimulus measures, and growing LNG heavy truck penetration driven by economic benefits,\" the analysts said in their latest outlook. The Chinese government is considering the release of 15 million mt of oil product export quotas in September, according to the sources, that will bring the country's total clean oil product export quota to 48 million mt for 2024. In the first half of 2024, China's clean oil products exports declined 2.7% year on year to 19.86 million mt (865,000 b\/d) because of slower overseas demand and thin export margins, leaving about 13.14 million mt of quotas available for the second half of the year until a new batch of quotas is released. China's 2024 clean oil product exports have been widely expected to remain steady on the year at about 40 million mt, due to less attractive export margins and a slight surplus in the domestic market. Open interest for front-month August FOB Arab Gulf gasoil swap contracts that traded on ICE, meanwhile, slumped 92.13% on the month in July to 132,000 barrels, ICE data showed. The availability of VLCCs could bolster the Persian Gulf gasoil complex in the near term though demand concerns in Europe remain due to a seasonal lull, according to middle distillate trade sources. Open interest for gasoil futures contracts on ICE: Gasoil (Unit: '000 barrels) Aug OI Jul OI M-o-M Change Singapore Gasoil 10ppm Futures 41,121 40,169 2.37% Singapore Gasoil 0.05% 0 0 N\/A Singapore Gasoil 0.05%\/ICE Gasoil 0 0 N\/A Singapore 10ppm Gasoil\/Gasoil 0.05% 0 0 N\/A Singapore Gasoil 0.05%\/Dubai 0 0 N\/A Middle East Gasoil Futures 132 1,678 -92.13% Total 41,253 41,847 -1.42% Source: Intercontinental Exchange Note: Open interest for a month is measured at the end of the previous month. ","headline":"ICE front-month Singapore 10 ppm gasoil swap open interest rebounds 2% on month in July","updatedDate":"2024-08-05T02:05:30.000"},{"Unnamed: 0":369,"body":" Saudi Aramco maintained or raised the Asia-bound September official selling price differentials for its crude grades by 10-20 cents\/b, a notice from the producer showed Aug. 5. Aramco set the September OSP differential for its flagship Arab Light at a premium of $2.00\/b to the Oman\/Dubai average, rising 20 cents\/b on the month. For the Arab Extra Light grade, Aramco increased the OSP differential by 10 cents\/b to a premium of $1.70\/b to the Oman\/Dubai average. The Super Light OSP differential gained 20 cents\/b to a premium of $2.95\/b to the Oman\/Dubai average. The Arab Medium and Arab Heavy OSP differentials were both unchanged on the month respectively at premiums of $1.25\/b and 50 cents\/b to the Oman\/Dubai average. Saudi Aramco's crude oil official selling prices: (Unit: $\/b) Grade Destination Basis June July August September Change Super Light Asia Oman+Dubai 3.45 2.95 2.75 2.95 0.2 Extra Light Asia Oman+Dubai 2.8 2.2 1.6 1.7 0.1 Light Asia Oman+Dubai 2.9 2.4 1.8 2 0.2 Medium Asia Oman+Dubai 2.35 1.95 1.25 1.25 0 Heavy Asia Oman+Dubai 1.6 1.2 0.5 0.5 0 Extra Light USA ASCI 7 7 7.1 6.35 -0.75 Light USA ASCI 4.75 4.75 4.85 4.1 -0.75 Medium USA ASCI 5.45 5.45 5.45 4.7 -0.75 Heavy USA ASCI 5.1 5.1 5.1 4.35 -0.75 Extra Light Med ICE Brent 3.7 4.7 5.6 2.85 -2.75 Light Med ICE Brent 2 3 3.9 1.15 -2.75 Medium Med ICE Brent 1.4 2.4 3.3 0.55 -2.75 Heavy Med ICE Brent -1.3 -0.3 0.6 -2.15 -2.75 Extra Light NWE ICE Brent 3.7 4.7 5.6 2.85 -2.75 Light NWE ICE Brent 2.1 3.1 4 1.25 -2.75 Medium NWE ICE Brent 1.3 2.3 3.2 0.45 -2.75 Heavy NWE ICE Brent -1.1 -0.1 0.8 -1.95 -2.75 Source: Saudi Aramco ","headline":"Saudi Aramco maintains or raises Asia-bound Sep crude OSPs by 10-20 cents\/b","updatedDate":"2024-08-05T01:59:16.000"},{"Unnamed: 0":370,"body":" The Asian middle distillates complex could be sluggish over Aug. 5-8, as trade participants await fresh spot activity for September-loading cargoes to provide further pricing direction. Front-month ICE October Brent crude oil futures fell to $76.42\/b at 9 am Singapore time (0100 GMT) on Aug. 5, from $80.03\/b at the Aug. 2 Asian close. Jet fuel\/kerosene The Asian jet fuel\/kerosene complex over Aug. 5-8 could be pressured by exports from China that are expected to add to a supply glut, dampening market sentiment. The Platts FOB Singapore cash differential for jet fuel\/kerosene to the Mean of Platts Singapore jet fuel\/kerosene assessment was minus 56 cents\/b at the Aug. 2 Asian close, compared with minus 13 cents\/b a week earlier. Platts is part of S&P Global Commodity Insights. Global air passenger demand, measured in revenue passenger kilometers, rose 9.1% year on year in June , driven by the summer holiday season, data from the International Air Transport Association showed July 31. Total capacity, measured in available seat kilometers, increased 8.5% from June 2023. Brokers pegged the balance-month August-September jet fuel\/kerosene swap time spread at minus 36 cents\/b at 0100 GMT on Aug. 5, compared with minus 35 cents\/b at the Aug. 2 Asian close. The Platts fourth quarter-first quarter jet fuel\/kerosene swap spread averaged plus 50 cents\/b over July 29-Aug. 2, narrowing from plus 60 cents\/b the week before. Gasoil The Asian gasoil complex is expected to be stable over Aug. 5-8 supported by pockets of regional demand, though trade participants have been cautious about a potential downside due to seasonal weakness. Brokers pegged the balance-month August gasoil exchange of futures for swaps -- an indicator of East-West arbitrage flows -- at minus $26.57\/mt at 0100 GMT on Aug. 5, compared with Platts' assessment of minus $26.17\/mt at the Aug. 2 Asian close. Brokers pegged the balance-month August-September gasoil swap time spread at minus 30 cents\/b at 0100 GMT on Aug. 5, compared with Platts' assessment of minus 31 cents\/b at the Asian close Aug. 2. Singapore's onshore commercial stocks of gasoil and jet fuel\/kerosene rose 2.7% over July 25-31 to a three-month high of 11.35 million barrels, Enterprise Singapore data showed Aug. 1. The stocks were last higher at 11.39 million barrels in the week to May 1. The Platts-assessed Q4-Q1 gasoil swap spread averaged plus 64 cents\/b over July 29-Aug. 2, narrowing from plus 75 cents\/b in the previous week. ","headline":" Key market indicators for Aug 5-8","updatedDate":"2024-08-05T01:50:17.000"},{"Unnamed: 0":371,"body":" The combined open interest for front-month Singapore high sulfur fuel oil contracts rose 19.6% on the month to 8.54 million mt in July, the latest Intercontinental Exchange data showed. The combined open interest includes contracts for the Singapore 380 CST and 180 CST HSFO grades, the Singapore viscosity spread and the Singapore 180 CST and 380 CST East-West contracts. The biggest increase was seen in the Singapore 180 CST East-West contract, which saw front-month open interest soar 82.9% on the month to 75,000 mt in July. The Singapore 380 CST contract was the only contract that saw a decrease in front-month open interest, which slipped 1.6% month on month to 4.06 million mt. Meanwhile, open interest across the HSFO forward curve edged 0.05% higher on the month to 43.465 million mt. The forward curve open interest for the 180 CST East-West contract plunged 40.9% on the month to 189,000 mt, while the open interest for the 180 CST contract gained 6.4% month on month to 2.68 million mt. The Asian HSFO market has been supported by seasonal utility demand and stable bunkering activity due to increasing high sulfur grade consumption by scrubber-installed ships. Tight availability of non-sanctioned supplies has also aided current HSFO market fundamentals. The M1-M2 spread for the 380 CST grade averaged at a backwardation of plus $13.98\/mt in July, compared with the June average of plus $7.65\/mt, Platts data from S&P Global Commodity Insights showed. The benchmark Singapore 380 CST HSFO cargo\u2019s cash premium to the Mean of Platts 380 CST HSFO assessment fell to $4.42\/mt on Aug. 2, hurt by weak buying interest and competitive offers from Trafigura during Platts Market on Close assessment process. The Singapore 380 CST HSFO cargo price averaged $500.98\/mt in July, compared with an average of $500.35\/mt in June. Marine fuel oil The combined open interest for front-month Singapore marine fuel oil contracts on ICE inched down 1.3% on the month to 4.631 million mt in July, led by a 42.7% decrease in the marine fuel 0.5%S East-West contract to 697,000 mt. The combined open interest includes contracts for Singapore marine fuel oil 0.5%S, the marine fuel 0.5%S-380 CST HSFO spread, called the Hi-5 spread, and the marine fuel 0.5%S East-West contract. Asian low sulfur fuel oil fundamentals, which have strengthened in recent weeks because of tight prompt supplies and some loading delays in the downstream bunker market in Singapore, could potentially weaken in August as higher arbitrage inflows from the West add to already increasing regional supplies, trade sources said. Along with low sulfur straight run fuel oil barrels from Nigeria\u2019s new Dangote refinery coming into Asia in recent weeks, traders have been expecting potentially higher exports from Kuwait\u2019s Al-Zour refinery in the coming months once peak summer power generation demand cools off in the Middle East. Singapore is expected to receive 2.5 million-2.6 million mt of LSFO from the West in August, up from 2.2 million-2.4 million mt in July, aided by viable arbitrage economics, Commodity Insights reported earlier. Platts assessed the Singapore marine fuel 0.5%S cargo's cash differential over the MOPS marine fuel 0.5%S assessment $1.33\/mt lower on the day at a premium of $4.42\/mt on Aug. 2, the lowest since a premium of $4.31\/mt on July 5. In July, the LSFO premium posted a monthly gain of 62%. The Singapore 0.5% sulfur marine fuel cargo price averaged $604.39\/mt in July, up from an average of $584.86\/mt in June. Open interest for the marine fuel oil contracts across the forward curve fell 4.8% on the month to 32.069 million mt. Front-month open interest: Aug-24 OI (as of July 31, 2024) Jul-24 OI (as of June 28, 2024) M-o-M change S'pore 380 CST 4,057 4,124 -1.62% S'pore 180 CST 796 776 2.58% S'pore visco 927 707 31.12% 180 East-West 75 41 82.93% 380 East-West 2,680 1,490 79.87% HSFO total 8,535 7,138 19.57% MF 0.5% 3,537 3,115 13.55% MF 0.5%\/380 CST 397 360 10.28% MF 0.5% East-West 697 1,216 -42.68% LSFO total 4,631 4,691 -1.28% Total forward curve open interest: As of July 31, 2024 As of June 28, 2024 M-o-M change S'pore 380 CST 27,349 26,403 3.58% S'pore 180 CST 2,680 2,520 6.35% S'pore visco 3,138 3,115 0.74% 180 East-West 189 320 -40.94% 380 East-West 10,109 11,086 -8.81% HSFO total 43,465 43,444 0.05% MFO 0.5% 22,715 23,997 -5.34% MFO 0.5%\/380 CST 2,314 2,295 0.83% MF 0.5% East-West 7,040 7,390 -4.74% LSFO total 32,069 33,682 -4.79% Units: 1,000 mt Source: Intercontinental Exchange ","headline":"ICE front-month Singapore HSFO open interest rises 19.6% on month in July","updatedDate":"2024-08-05T01:26:07.000"},{"Unnamed: 0":372,"body":" Production will be increasing \u201cin the near future,\u201d Montfort said by email, in response to a report by Argus that output will resume in August after being stopped in May because of a lack of feedstock. \u201cThe refinery remains operational. As with any refinery there will be fluctuations in production over time due to a variety of usual operational and market factors,\u201d Montfort said. The business operates a 65,000 b\/d crude processing facility in the Port of Fujairah, the UAE, selling low sulfur fuel oil to the shipping industry. Vitol also produces LSFO at Fujairah with an 82,000 b\/d refinery that can produce some 45,000-50,000 b\/d of International Maritime Organization-compliant bunker fuels. Both facilities have focused on taking heavy sweet crude feedstock, including Chad's Doba Blend and South Sudan's Dar Blend. Damage to South Sudan\u2019s only export pipeline through Sudan has kept tens of thousands of barrels offline. Fort Energy under previous ownership by Uniper and Vitol has also taken heavy sweet Australian crude , including Pyrenees and Van Gogh. Montfort declined to comment on its crude sources and on current demand, other than \u201cwe see continued strong demand in the market.\u201d ","headline":" Fort Energy at Fujairah \u2018remains operational\u2019","updatedDate":"2024-08-05T00:45:56.000"},{"Unnamed: 0":373,"body":" Container ship Groton was attacked 125 nautical miles east of Aden in Yemen, the UK Maritime Trade Operations said Aug. 3, as shipping continues to be a target in the conflict in the Middle East. Groton is sailing under a Liberian flag, was last docked at Fujairah in the UAE and is bound for Djibouti, according to S&P Global Commodities at Sea. UKMTO said that the vessel was hit by an unknown explosive. It added that there were no fires, water ingress or oil leaks as a result of the attack, and the vessel was continuing to its next port of call. An investigation is ongoing and UKMTO advised vessels to transit with caution and report any suspicious activity. On July 15, three ships were attacked off the Red Sea coast of Yemen, including the Aframax tanker Chios Lion, which suffered damage. Yemen-based Houthi rebels have not formally claimed responsibility, but they have led a major campaign targeting ships in recent months. They claim to have attacked more than 100 ships linked to Israel, the US and UK in the Red Sea and Gulf of Aden since the Israel-Hamas war broke out Oct. 7. Many major energy and shipping companies, including BP, Maersk, QatarEnergy and Frontline, have altered their routes to sail around Africa to avoid the Houthis. Security risks have increased in the Middle East in recent weeks, with the assassination of Hamas political leader Ismail Haniyeh in Iran raising the risk of retaliatory attacks. This will pose ongoing risks to shipping, S&P Global Commodity Insights forecasts. \u201cHouthi targeting of commercial and naval vessels in the Gulf of Aden, Bab al-Mandab Strait and Red Sea is likely to continue through 2024, despite US-led coalition strikes on Houthi territory in Yemen, maintaining a severe risk for all vessels and crew attempting to transit the Bab al-Mandab Strait and the Red Sea, regardless of affiliation,\u201d Commodity Insights said. ","headline":"Container ship Groton attacked near Yemen amid growing Middle East security risks","updatedDate":"2024-08-04T12:25:30.000"},{"Unnamed: 0":374,"body":" A drone strike on an oil depot in Russia\u2019s Belgorod region resulted in a fire breaking out at a fuel tank, regional governor Vyacheslav Gladkov said in a post on Telegram Aug. 3. Infrastructure in the region, which borders Ukraine, has been the target of numerous attacks since Russia invaded Ukraine in February 2022. It is the second attack on Russian oil storage in a week. On July 28, the governor of Kursk region said that three fuel tanks were set on fire after a drone strike. Ukraine has increased attacks on Russian oil storage and refining in 2024 as it bids to disrupt supplies to the Russian military. In response, Russia is targeting power infrastructure in Ukraine, leading to widescale blackouts and forcing it to increase imports from the EU. ","headline":"Oil depot in Russia\u2019s Belgorod region hit by drone strike","updatedDate":"2024-08-04T10:14:50.000"},{"Unnamed: 0":375,"body":" Randy Letang, CEO of US-based renewable energy company SGP BioEnergy, said the bioenergy industry will ignite growth in emerging regions and foster new social and economic development routes, noting, however, that the market has faced various challenges, particularly concerning broader product adoption by end customers. In an interview with S&P Global Commodity Insights, Letang said that cultivating raw materials in different areas and then processing these feedstocks into fuels and products locally would pave the way for the next generation of the industry. He added that the development of the bioenergy industry has faced several challenges. \"Even with the best technology and engineering contractors to build the facility, the rules of economy of scale still apply,\" Letang said. \"We need to build a refinery of a certain size to achieve a lower overall cost per gallon of fuel.\" The competition between jet fuel and sustainable aviation fuel has been an example of one such challenge. Letang said airlines have fixed parameters in which they operate and cannot adopt unfeasible practices. \u201c[Airlines] might overpay for SAF only if their growth allows them to absorb the costs,\" Letang said. \"Otherwise, with their thin margins and high fuel expenses, it's not feasible.\u201d Letang said the industry is addressing this in three ways: passing costs to consumers, developing policies where consumers absorb costs through tax credits, and creating tax schemes for trading incentives among various parties. Another consistent concern in the bioenergy industry is feedstock availability. However, Letang said feedstock issues are specific to certain producers and not industry-wide. \"When I hear about feedstock limitations for HEFA, it\u2019s clear that the connection between agriculture and HEFA technology hasn\u2019t been effectively established yet,\" Letang said. \"The reality is there is plenty of feedstock available -- enough to match current petroleum production once this link is made.\" Letang sees industrial hemp as a potentially viable feedstock for his Panama Project under the READY.GROW. program due to its unique characteristics; industrial hemp sequesters four times more CO2 than other crops, removes toxins and heavy metals from the soil, and is carbon neutral, according to Letang. Additionally, industrial hemp can return nutrients to the soil, requires only a third of the water needed for sugarcane and produces as much oil as canola, creating a zero-waste ecosystem, Letang said. \"Industrial hemp can thrive in challenging environments, breaks the trade-off between fuel and food production, and benefits from the extensive cultivation knowledge of indigenous tribes,\" Letang said. Policy and implementation have played crucial roles in the industry's development, although policy has often outpaced implementation. Constant regulatory changes disrupt developers, altering business models and investor and bank confidence in supporting projects. This uncertainty leads to stalled implementation. \u201cAligning policy with implementation, rather than leading it, is essential. Currently, prioritizing implementation over innovation is paramount,\u201d Letang said. ","headline":" 'Transformative' bioenergy market to connect agriculture and fuel production, SGP BioEnergy says","updatedDate":"2024-08-02T21:49:58.000"},{"Unnamed: 0":376,"body":" Coterra Energy plans to curtail 275 MMcf\/d of Marcellus Shale natural gas production in August and September in response to weak natural gas prices, executives said Aug. 2 during the company's second-quarter earnings call. Coterra will \"extend this curtailment as warranted on a month-to-month basis,\" said Blake Sirgo, senior vice president of operations. The company returned 12 previously deferred Marcellus wells online in July \"due to favorable pricing we were able to secure,\" Sirgo said. But it was unable to secure favorable pricing for August, so it curtailed the 275 MMcf\/d from Aug. 1, he said. The 275 MMcf\/d of net gas curtailed \"represents the portion of our near-term portfolio, which is exposed to Marcellus in-basin pricing,\" Sirgo said. \"We are prepared to make further cuts as some of our summer sales commitments roll off in the shoulder season.\" Curtailments reduced the company's Q2 production in the Marcellus to 2.11 Bcf\/d, down from 2.31 Bcf\/d in the first quarter, Coterra reported Pricing \"Our industry does not need $5 [per MMBtu] gas to have a healthy runway,\" CEO Thomas Jorden said. \"We do, however, need sustainable price support in the mid-threes or better to motivate producers to bring incremental gas to market to meet growing demand.\" Coterra would look for netbacks above $1\/MMBtu to return gas production in the Marcellus, Jorden said. This would require a NYMEX price \"north of three [$\/MMBtu]\" in the lower Marcellus, and in \"the mid-threes\" in the upper Marcellus. Because it is delaying turn-in lines, its ability to return production could be \"almost instantaneous depending on price response,\" Jorden said. NYMEX Henry Hub prompt-month futures briefly rallied above $3\/MMBtu in June, but a recovery in natural gas production and the lingering storage surplus killed off that momentum, sending futures back below $2\/MMBtu . \"Although we remain bullish on gas long term, near-term supply-demand dynamics are placing downward pressure on natural gas prices and likely will continue to do so throughout the remainder of injection season,\" Jorden said. US gas production averaged 103 Bcf\/d in July, after falling to 100.7 Bcf\/d in May, according to S&P Global Commodity Insights data. Total gas in storage was 441 Bcf, or 16%, higher than the five-year average as of July 26, the Energy Information Administration reported Aug. 1. Futures are still above the $3\/MMBtu mark for December-February and the second half of 2025, data from CME Group showed Aug. 2. \"With increasing LNG exports and growing natural gas power demand, we have a line of sight to a materially better natural gas market,\" Jorden said. Oil volumes Coterra's oil production rose to 108,000 b\/d in the second quarter, up from 102,000 b\/d in the first quarter. It increased its oil production guidance range to 105,500-108,500 b\/d, up 2.4% from its prior guidance thanks to faster cycle times and strong well performance, it said in an Aug .1 statement. It is guiding Q3 oil production in a range of 107,000-111,000 b\/d. \"We're just really in uncharted territory of efficiency gains that we've seen and it's increasing our capital efficiency,\" Sirgo said. \"Our diesel zipper crew today completes 40% more footage in a year than it did five years ago.\" ","headline":"Coterra Energy to curtail Marcellus Shale natural gas production in Q3","updatedDate":"2024-08-02T21:31:05.000"},{"Unnamed: 0":377,"body":" Three months after ExxonMobil's nearly $60 billion acquisition of independent E&P company Pioneer Natural Resources, the merged major is producing more than its long-awaited landmark goal of 1 million barrels of oil equivalent from the Permian Basin owing to that prized asset, ExxonMobil's top executive said Aug. 2. In the second quarter, \"we once again set production records from our advantaged assets in Guyana and the Permian,\" CEO Darren Woods said during a second quarter conference call. \"Including Pioneer, our Permian production surged to 1.2 million barrels [equivalent],\" Woods said. \"Including Pioneer, our Permian production volumes have more than tripled since 2019.\" \"In Guyana, we started 2019 with zero production and we\u2019ve grown to an average of 633,000 barrels per day gross [of oil] in the second quarter,\" he added. With Pioneer, ExxonMobil now expects more than 60% of its production will be generated from competitively advantaged assets by 2027, ExxonMobil Chief Financial Officer Kathy Mikells said in a prepared written supplement. \"We've also grown the current share of liquids in our Upstream portfolio to approximately 70% - the highest it\u2019s been since Exxon and Mobil merged almost 25 years ago,\" Mikells said. Also, in Guyana scheduled work from temporary shutdown of the Liza Phase 1 and Phase 2 FPSOs should reduce volumes at the Exxon-operated Stabroek Block by about 80,000 b\/d in the third quarter, she said. The shutdown is required to tie the FPSOs into the pipeline for an historic gas-to-energy project, which will feed gas to onshore Guyana industries. ExxonMobil and Stabroek partners Hess Corp. and China's CNOOC are producing from three FPSOs offshore that country. Eyes completion of brief Guyana Liza 1 shutdown in early August The work on Liza Phase 2 was completed in mid-July and Liza Phase 1 is expected to be completed in early August, she added. ExxonMobil\u2019s part of the overall project \u2013 the 152-mile natural gas pipeline from the FPSOs \u2013 will be finished in Q4 2024 and commissioning will follow the government of Guyana\u2019s completion of its 300-megawatt gas-fired onshore power plant. In addition, ExxonMobil said it likely will have first output at Golden Pass LNG project in Port Arthur, Texas, in late 2025, after reaching a settlement with contractor Zachry Holdings after conflicts involving payments and other issues, Woods said. \"That venture is in the process ... of re-staffing and getting started back up again,\" he said. \"Obviously, we're in the very early days of that. So there's still more work to be done.\" Currently, ExxonMobil's estimate is a startup slippage of about six months, he said: \"We had anticipated first LNG in the middle of next year, but we are now looking at probably the back end of 2025 for first LNG.\" ExxonMobil produced 4.358 million boe\/d of liquids and natural gas in Q2, including 2.557 million b\/d of liquids and 7.36 Bcf\/d of natural gas. By contrast, the company produced 3.6 million boe\/d in Q2 2023, including 2.353 million b\/d of liquids and 7.5 Bcf\/d of natural gas. ","headline":"ExxonMobil tops 1 million boe\/d in Permian in Q2 after Pioneer buy: CEO","updatedDate":"2024-08-02T21:19:01.000"},{"Unnamed: 0":378,"body":" Insecurity due to organized crime in the Mexican border state of Tamaulipas is delaying the exploration activities of Pantera, a joint venture between Calgary, Canada-based Sun God Resources and Mexico's Jaguar Exploraci\u00f3n y Producci\u00f3n. The situation in the region has made it impossible for the company to fully appraise the site where it made an oil discovery in 2021. During its weekly meeting on Aug. 1, the country's upstream regulator, the National Hydrocarbons Commission, or CNH, approved a request by Mexico-based Pantera for six additional months to complete its exploration activities at the onshore block operated under contract R02-L02-A7.BG\/2017. The original evaluation program for the site was approved in 2021, but the company has asked for additional time since. Company workers have had to deal with members of the organized crime both on the premises as well as on the roads that lead to the exploration area, the CNH said during the meeting. These disruptions have resulted in fewer available hours for workers to perform their duties and hurdles to deal with land owners, the CNH said. At the site, Pantera plans to drill up to three delimiting wells and has committed around $20 million to the project. The company estimates roughly 5 Bcf of dry gas in contingent resources at the site, the CNH said. Pantera is only one of many companies in all sectors of the economy whose operations have been disrupted due to organized crime, mainly in the northern states of Tamaulipas and Nuevo Le\u00f3n, but increasingly in other areas of the country. Typically small businesses, mostly family-owned, were victims of extorsion, but now, larger firms, including international corporations are being targeted. On July 29, a high-level meeting was held between government officials and members of the private industry, including the National Association of Retailers, ANTAD, and Mexican conglomerate FEMSA, whose convenience store chain OXXO had been targeted the most. The next day, the president of the Federation of Chambers of Commerce in Tamaulipas, Julio Almanza Armas, who had been denouncing the situation repeatedly, was shot dead in broad daylight by a group of masked men in the city of Matamoros, Tamaulipas. ","headline":"Organized crime delays Pantera's exploration activities in Mexican state of Tamaulipas","updatedDate":"2024-08-02T21:09:37.000"},{"Unnamed: 0":379,"body":" The production debut of Chevron's deepwater US Gulf of Mexico Anchor field is \"imminent,\" the company's top executive said Aug. 2, marking the start of what will be a rash of similarly complex oil fields that will come on stream in the next several years. Anchor, a high-pressure, high-temperature project, will be the petroleum industry's first deepwater field to be produced at 20,000 pounds of pressure, Chevron CEO Mike Wirth said during his company's second-quarter earnings call. \"Anchor ... is on track to come in under budget while deploying multiple breakthrough technologies,\" Wirth said, noting that following Anchor, three more Chevron-operated US Gulf deepwater projects should come online in the next couple of years. They include the Chevron-operated Ballymore field in 2025 and the Shell-operated Whale field, where Chevron is a 50% partner, later in 2024. \"We expect [US Gulf] production of 300,000 barrels a day [of equivalent oil] by 2026,\" he said, compared to 199,000 boe\/d in Q2 \u2013 a level the company has maintained for the last couple of years. BP also recently greenlighted its Kaskida field, a 2006 find, and expects to approve its Tiber field, a 2009 discovery, next year. Both are 20,000 psi fields. In addition, Beacon Offshore is developing the 20,000 psi Shenandoah field which should come online either late 2024 or early 2025. Anchor was discovered in late 2014, although the technological know-how to produce 20,000 psi fields was not yet developed. In addition, low oil prices of the last decade also delayed sanctioning of Anchor and other 20,000 psi fields. Bigger equipment needed for 20,000 psi fields In those fields, bigger equipment is needed to contain the higher pressures, Wirth said. \"You've got greater thickness on all your equipment \u2013 it's heavier and you need heavier hook loads to lift and and deploy it,\" he said. \"We've worked closely with some of our suppliers who have developed the specific equipment that is in place and we're very pleased with everything from the drilling rigs to production trees.\" Chevron with its field partners provided input on construction of a drilling rig that would enable drilling at very deep total depths, Chevron Chief Financial Officer Eimear Bonner, who previously was the company's chief technology officer, said. Anchor is sited in 5,183 feet of water which is relatively moderate compared to some other US Gulf fields in 7,000-8,000 feet of water. But initial wells were drilled to a very deep 33,749 feet (nearly six and a half miles subsea). \"The equipment to allow us to to do that that had very special dynamic positioning and technology,\" Bonner said. \"On the subsurface side ... we were able to get a really accurate image of the prospect [through] our proprietary seismic technology.\" In addition, production in the Permian Basin, a major Chevron asset and major source of the company's output growth, was \"strong,\" Wirth said, at a record 884,000 boe\/d which is up 3% sequentially and up 15% year on year. Eyes 15% Permian growth in 2024 \"We now expect full year [2024 Permian] production growth of about 15% and fourth-quarter production to average around 940,000\" boe\/d, he said. For years Chevron has had a target to deliver 1 million boe\/d of Permian production by 2025. Wirth noted that 80% of the company's Permian activity is in the Delaware Basin -- the western Permian. \"We're seeing lower decline from proactive maintenance efforts, lower operated downtime, and artificial lift optimization,\" he said. \"Triple frac ... is reducing costs and increasing cycle time so the the you know spud to production cycle has shortened further, so we're getting more [producing] days on online than than we might have a year ago.\" Triple \"frac\" or TrimulFrac is a technique of hydraulically fracturing three wells simultaneously rather than just one well at a time as in previous years. In the Midland Basin or eastern part of the Permian, some of Chevron's H1 2024 producing wells have been \"a little bit below expectations,\" but not many, and the company is optimizing development across the basin because it is \"not completely homogeneous,\" Wirth said. Testing Permian wells to map future drilling \"We're testing new zones to inform our future development plans,\" Wirth said. \"This is a big long-term asset that's got a lot of life ahead of it and we should be continually improving in it so that over time we can deliver even stronger returns and performance. It's exceeding expectations for for this year and we've got great confidence in what we'll deliver in 2025.\" Wirth said Chevron's pending merger with Hess Corp. is now expected to be reviewed by the US Federal Trade Commission starting in the third quarter, after the transaction close was delayed over a dispute with ExxonMobil. The merger was originally expected to close about midyear 2024, but was set back when ExxonMobil exercised its preemptive right of first refusal (ROFR) on Hess' 30% stake in Guyana's offshore Stabroek Block asset which ExxonMobil operates. Hess and Chevron have disputed ExxonMobil's claim which gives an asset holder a chance to match or decline to make an offer before the owner can sell it to someone else. Chevron has said that the right does not apply to the Stabroek Joint Operating Agreement because it is acquiring Hess' entire company, not simply a lone asset. On July 31, Chevron and Hess said an arbitration date has been set in mid-2025 for a panel to address ExxonMobil's claim, with a decision expected about three months later. The Stabroek Block is currently producing over 600,000 b\/d of oil from three FPSOs, with another four oil developments in various stages of construction. The next Stabroek project is slated to come online in 2025, followed by the others in 2026, 2027 and 2029. In Q2, Chevron's global production totaled 3.23 million b\/d of oil equivalent, up 11% year over year, but down 1.5% sequentially. Chevron reported Q2 earnings of $4 billion or $2.43\/share, down from $6 billion or $3.20\/share in the same period in 2023. ","headline":"Chevron's US Gulf of Mexico Anchor project debut 'imminent': CEO","updatedDate":"2024-08-02T20:50:45.000"},{"Unnamed: 0":380,"body":" Explorer Pipeline said Aug. 2 that it closed its open season for a diluent expansion project, with plans to construct a new project that will increase the transportation capacity of an existing portion of Explorer's system for shipments of diluent out of the US Gulf Coast to destinations in the Midwest. The open season began May 29 and lasted until July 26, extending a month from its original ending date in June. The Diluent Expansion capacity will be available to shippers on or around July 1, 2025, the company said in a release Aug. 2. Diluent shipments on the new project will also head to destination points at the Irwin\/Cochin Terminal in Kankakee County, Illinois, and the Manhattan\/Southern Lights Terminal in Will County, Illinois. Demand for diluent has increased in Western Canada, where many of these shipments heading to the Midwest will be re-directed. Diluent is a special type of ultralight oil that is used as a thinning agent of lighter hydrocarbons and is mixed with heavier products such as Canadian oil sands bitumen in order to pump it more easily through pipelines. With enhanced production capacity newly online, such as the Trans Mountain Expansion, the Canadian crude market is expected to grow nearly 720,000 b\/d through the remainder of the decade, with 580,000 b\/d coming from increased oil sands output, subsequently applying pressure on diluent demand. Most of this demand is met with domestic pentane plus or condensate, with smaller volumes of refinery naphtha, synthetic crude oil and light sweet crude oil also being sourced as diluent. The remainder is imported from the US via one of two inbound pipelines: the Cochin pipeline, with a capacity of 95,000 b\/d, or the Southern Lights pipeline, with a capacity of 180,000 b\/d. Both pipelines feed into diluent markets in Canada. ","headline":"Explorer pipeline in US closes open season on diluent expansion","updatedDate":"2024-08-02T20:46:44.000"},{"Unnamed: 0":381,"body":" Leading Canadian oil sands producer Imperial Oil expects higher production in the second half of 2024 following strong second-quarter output, several major turnarounds and the startup a new oil sands plant, CEO Brad Corson said Aug. 2. Upstream production averaged 404,000 b\/d of oil equivalent in the second quarter, up 11% year on year, Imperial said. That included included about 3,000 b\/d from the first phase of its Grand Rapids facility in Cold Lake in northern Alberta that was started up in May, he said. \"With the majority of upstream turnaround activity behind us, we are well positioned for strong production in the second half of the year,\" Corson said on the company's second-quarter earnings call. The Grand Rapids project marked the first commercial deployment of the recovery technology that uses less steam to lower emissions intensity, Imperial said, adding the facility will reduce GHG emissions by 40% when compared with other existing industry applications like cyclic steam stimulation (CCS) technology. Called SA-SAGD, or solvent-assisted, steam-assisted gravity drainage, Imperial will use a lighter oil mixed with steam to recover bitumen from underground deposits, it said, noting Imperial developed and piloted the technology which is the first deployment in industry. \u201cThe remaining pumps are being installed and output continues to ramp up, producing about 10,000 b\/d to 12,000 b\/d now. We are on way to reaching full production rate of 15,000 b\/d,\u201d Corson said, adding in addition to bringing on stream new production, Grand Rapids is also lowering unit cash cost. Grand Rapids is one of the other projects at Cold Lake that Imperial is developing, with the other acreage being redevelopment of the Leming. \u201cThis [Leming] is another key project for us and last quarter module fabrication work started for the facility. The project is on track for a 2025 start up with peak production anticipated to be around 9,000 b\/d,\u201d Corson said. Technology and new projects Application of new technology and a lowering of greenhouse gas emissions are two key elements as Alberta\u2019s oil sands producers move ahead with adding new production over the coming few years. Imperial is working with fellow oil sands producer Suncor Energy on a pilot project that is studying the application of the EBRT technology in Alberta, Corson said. The enhanced bitumen recovery technology gives a producer the advantage of a lower capital and operating cost, reduced carbon footprint and greater bitumen recoveries. An option for Imperial could be to apply EBRT to develop its 75,000 b\/d Aspen project that it had put on the backburner in 2019 citing market conditions. \"Suncor is only a partner with us for the pilot study and working with them allows us to share insights and technology,\" he said. Upstream production, restart of Winnipeg pipeline Kearl production rose 38,000 b\/d in Q2 to 255,000 b\/d, compared with 217,000 b\/d a year earlier, on the back of its annual turnaround last quarter, Corson said, adding its Q2 operating cost were $22.12\/b, down $6\/b year on year. At Cold Lake, Q2 output was 147,000 b\/d, up from 132,000 b\/d in the same quarter of 2023, he said. Imperial\u2019s share of production at Syncrude, which completed its annual coker turnaround in May, held steady at 66,000 b\/d in Q2. The producer realized an average bitumen price of C$83.02\/b ($59.89\/b) in Q2, up from C$68.64\/b a year earlier. Startup of the 590,000 b\/d Trans Mountain Expansion oil pipeline has narrowed the differential between WTI and Western Canadian Select, Corson said. WCS at Hardisty, Alberta, averaged a $14.56\/b discount to WTI in July, widening slightly from a $13.29\/b discount in June, Platts assessments show. However, the discount was at $25.44\/b in November, prior to the line fill for the Trans Mountain crude pipeline expansion. Platts is a unit of S&P Global Commodity Insights. In the downstream segment, Imperial completed major turnarounds at the Strathcona and Sarnia refineries, Corson said, with throughput averaging 387,000 b\/d in Q2 and overall refinery capacity utilization of 89%, reflecting strong operations and high reliability, particularly at the Nanticoke refinery. Imperial operates the 121,000 b\/d refinery in Sarnia and the 112,000 b\/d plant in Nanticoke, both in Ontario, and 200,000 b\/d refinery in Strathcona, Alberta. In Q2, Imperial also completed a proactive replacement of a section from the Winnipeg Products Pipeline, restoring pipeline fuel supply in the region and also developed a network of renewable diesel blending and offloading distribution terminals. ","headline":"Imperial starts up new 15,000 b\/d oil sands facility, sees higher H2 output","updatedDate":"2024-08-02T19:47:39.000"},{"Unnamed: 0":382,"body":" Increased oil and natural gas production in the prolific Delaware Basin and Eagle Ford play continues to drive EOG Resources' growth, with inventory levels during the second quarter reflecting increased well performance and improved operational efficiencies, executives said Aug. 2. The Houston-based upstream producer extended its 2024 well length averages in drilling and completions over the previous year, continuing a trend seen last quarter. \"In our foundational Delaware Basin and Eagle Ford plays, operational efficiencies are driven primarily by longer laterals, improving drilled feet per day,\" EOG's executive vice president and chief operating officer, Jeffrey Leitzell, said during the company's second quarter earnings call. \"Longer laterals allow for more time being spent drilling downhole and less time moving equipment on the surface.\" The company in 2024 will increase its overall well lateral drilled per foot -- a lateral is the horizontal portion of a well -- between 15% to 20% and completions per foot by about 7%. In the Eagle Ford, EOG is on target to extend laterals by 20% on average across its 535,000 net acre footprint in that play, with a year-to-date 7% increase in drilled feet per day. In the Delaware Basin, the company will use 3-mile laterals for more than 50 wells compared with only four 3-mile laterals used last year, resulting in a 10% increase in drilled feet per day. EOG also increased its target for full year 2024 total liquids production by 11,800 b\/d, with natural gas accounting for most of the growth, which has been led by higher production coupled with an increase to forecast operational efficiencies. In the South Texas Dorado natural gas play, the drilling team achieved a 13% increase in drilled feet per day year to date, the result of deferring completions, while retaining a full rig program in order to maintain \"operational momentum,\" Leitzell said. In the Uticia Shale, EOG has added another 10,000 net acres to its position, totaling 445,000, and is on target to complete 20 net wells in the Utica across the company's northern, central and southern acreage. Demand drives growth despite lull in rig activity Growing demand drove these results despite a plateau in drilling activity, company executives said. \"Global oil demand continues to increase after a seasonally soft first quarter and is in line with our forecast,\" Leitzell said. \"We expect Lower 48 US supply to exit 2024 at roughly the same level as year-end 2023, with only modest gains to total US oil supply from offshore -- as offshore production increases,\" he added. Activity levels, as reflected in rig count, indicate continued lower oil production growth through at least mid-2025, according to the company. The US oil and gas drilling rig count climbed by three to a five-week high 636 in the week ended July 24, S&P Global Commodity Insights data showed Aug. 1, despite little change across the major basins. The number of active oil-focused rigs climbed by six to 540 and was the highest since early April, while gas-focused drilling activity dipped by three to 96, the lowest since October 2020. This is compared with a rig count at 639, a 30-month low seen in late April as drilling activity slowed across all major basins. EOG's year-to-date 2024 oil production is at 488,400 b\/d on average, while Q2 volumes equaled 490,700 b\/d, up from 487,400 b\/d seen in the last quarter. In 2023, second-quarter production was at 476,000 b\/d. In 2024, EOG plans to run 27 rigs and eight hydraulic fracturing crews specializing in well completions. Infrastructure to come online EOG's Janus gas processing plant is on track to start up in the first half of 2025, adding 300 million cbf\/d to the Delaware Basin while establishing connectivity to the new Matterhorn Express pipeline, expected to be in service later this year. In the Dorado play, Phase 1 of EOG's 36-inch Verde pipeline is now in service, with Phase 2 expected to come online in the second half of this year. \"We expect the combination of Verde Phase 2 and the premium markets accessed at Agua Dulce will further expand our margins, positioning Dorado as one of the most competitive, lowest cost and highest return natural gas plays in North America,\" D. Lance Terveen, senior vice president of marketing and midstream, said during the call. At Agua Dulce, the company has executed agreements for three interconnects to the Verde pipeline, one of which is the Texas to Louisiana Energy Pathway Project. The 364,400 MMBtu\/d capacity TLEPP received FERC approval in June and has since begun construction, with an in-service date set for the first quarter of 2025. ","headline":"Better well performance, improved operational efficiencies drive growth: EOG Resources","updatedDate":"2024-08-02T19:47:04.000"},{"Unnamed: 0":383,"body":" Activity in global spot methanol and MTBE markets was mixed in July, with methanol seeing increased trading volumes in Asia compared with the US and Europe, while MTBE saw a drop in Europe trading versus Asia and the US. Methanol spot volume July June July 2023 CFR China 75,000 39,000 55,000 FOB Rotterdam 47,000 67,000 37,000 FOB USG 6,305 20,180 5,487 CFR India 97,000 75,000 101,000 MTBE MOC spot volume* FOB Singapore 3,000 0 15,000 FOB ARA 13,000 19,000 18,000 FOB USG 8,873 2,957 37,275 *Volumes as observed during the Platts e-Window process. Source: S&P Global Commodity Insights Unit: mt Methanol ASIA: Trading activity in the Chinese methanol market soared 92.31% on month to 75,000 mt in July. Market sources attributed the pick up to healthy supply and demand downstream. Ample supply, especially from Iran, weighed on coastal domestic prices, which spurred buying, market sources said. The restart of a methanol-to-olefin plant also bolstered buying sentiment, they added. Zhejiang Xingxing New Energy Chemical restarted its 690,000 mt\/year methanol-to-olefins plant in Zhejiang, China on July 19 after a two-month furlough. Methanol inventory in east and south China hit an intra-year high of 1 million mt in July. CFR China methanol prices fell 2.04% on the month, averaging $289.35\/mt in July, data from Platts, part of S&P Global Commodity Insights, showed. Spot trading activity in the Indian methanol market improved on the month in July to at least 97,000 mt, amid stronger buying interest as port inventory continued to stay range-bound. Buyers remained cautious amid a seasonal slowdown in downstream demand and booked only required volumes. Overall, regular movement of Iranian vessels in India continued to remain impacted at least until first-half July before normalizing in the second-half. Gap in cargo arrivals, however, kept ex-tank pricing discussions volatile. Fixed-price discussions were range-bound around $275-$285\/mt CFR India. CFR India methanol prices averaged $283.8\/mt in July, down $8.5\/mt from the June average, Platts data showed. EUROPE: Spot trading activity in Europe fell in July, with at least 47,000 mt heard traded in the month, down from around 67,000 mt in June. Most of this volume was traded in the first three weeks of the month, as market activity slowed at the tail-end of the month heading into August, amid the summer holiday period in Europe. Global supply disruptions in Europe, Egypt and the Americas persisted throughout the month, keeping prices elevated. Further price increases were prevented by steady-to-slow demand, particularly at the end of the month, with derivatives demand in construction, automotive and general manufacturing remaining relatively subdued, albeit better than recent years. Overall, methanol FOB Rotterdam prices averaged Eur323.34\/mt in July, down marginally from Eur323.50\/mt in June, but up significantly from Eur201\/mt in July 2023, Platts data showed. US: Methanol spot trading volume plunged to 6,305 mt in July from 20,180 mt in June, when a spike in demand was seen for the then forward-month July trading, market sources said. Spot trading slowed on the month in July as most of the demand for July delivery was met in June, sources added. In addition, demand from the housing sector remained weak despite US housing starts climbing above pre-pandemic levels. Platts assessed M1 spot methanol at an average of $350.60\/mt FOB USG in July, up $3.40\/mt from the June spot monthly average. Canada's Methanex started methanol production at its Geismar 3 facility in Louisiana on July 30, according to CEO Rich Sumner, adding 1.8 million mt\/year of capacity to the market. The plant is running at 70% rates, with Methanex expecting to ramp up to full rates \"in the coming weeks,\" he said. Methanex nominated its North American methanol contract price at 209 cents\/gal in August, up 5 cents from July. MTBE ASIA: Trading activity during the Platts Market on Close assessment process increased in July, with oil majors like Shell, Saudi Aramco and Unipec participating in the process during the month. There was one 3,000-mt cargo traded between Trafigura and Aramco at $865\/mt FOB Straits for July 20-24 loading. However, market sentiment in Singapore remained bearish, with a reduction in demand for blending during the past month, a market participant said. The arbitrage between China and Singapore was mostly closed, with only a few cargoes heard traded. However, Chinese domestic market prices and sales of gasoline and gasoline blendstocks remained robust during July. The FOB Singapore MTBE marker averaged $835\/mt during July, marginally down from $836.63\/mt in June. The FOB China marker averaged $811.43\/mt in July, up from $807.58\/mt in June, Platts data showed. EUROPE: Traded volumes of MTBE out of the Amsterdam-Rotterdam-Antwerp hub fell to 13,000 mt in July, from 19,000 mt in June. The spot MTBE market saw increasing demand as the peak summer driving season kicked in, while product availability was long, mainly due to more imports from China amid an open arbitrage. There were talks that import volumes could be directed to non-EU destinations, such as Africa, for blending. In late July, market sources said that the arbitrage could be closing, though around 20,000 mt was heard to be on water from China to Europe for mid-August arrival. The MTBE FOB ARA price averaged at a $177\/mt premium to the Eurobob August gasoline swap in July, down from the $148.88\/mt premium average in June, Platts data showed. Outright MTBE prices averaged $1,000.39 \/mt FOB ARA in July, up from $962.66\/mt average in June. US: MTBE traded volumes totaled 8,873 mt in July, up 2,957 mt on the month. For the January-July period, a total of 79,859 mt was traded, down 22% on the year. A total of three trades were recorded in July during the Platts MOC process. A trade was also heard done outside of the MOC for 25,000 barrels on July 2, for prompt loading dates between July 4-7. Although arbitrage economics were considered unfavorable to transport US MTBE to Europe throughout the month, a cargo with US MTBE was heard to have arrived in the Mediterranean to fulfill European contractual obligations. Platts assessed the outright price spread between FOB US Gulf Coast and FOB ARA MTBE at minus $3.96\/mt on July 31, while the freight to move liquid chemicals in 5,000-mt vessels from the USGC to Europe was at $76\/mt on July 26. Platts assessed US Gulf Coast MTBE at an average premium of $114\/mt over NYMEX RBOB futures in July, up from a $112\/mt premium in June. The outright price averaged $994\/mt in July, up from $978\/mt in June. ","headline":"Global Methanol & MTBE Trade Tracker: Mixed trading activity seen for July","updatedDate":"2024-08-02T18:45:17.000"},{"Unnamed: 0":384,"body":" Enbridge has given the green light for a 120,000-b\/d expansion of its Gray Oak long-haul Texas pipeline, following a successful open season to export incremental barrels to global markets from marine docks at the US Gulf Coast, CEO Greg Ebel said Aug. 2. The midstream player has also taken a final investment decision for the proposed Blackcomb natural gas pipeline that will be designed to transport 2.5 Bcf\/d of feedgas from the Permian Basin to an export facility on the USGC, Ebel said on the company\u2019s second quarter 2024 earnings webcast. \u201cThere is a growing demand for crude oil and natural gas, with producers seeking more egress,\u201d he said. \u201cWe have had record Mainline volumes [in Western Canada] and Ingleside [in Texas]. While gas producers in the Permian are seeking the much-needed egress out of the basin.\u201d On May 9, Enbridge launched an open season seeking additional barrels on its Gray Oak pipeline that transports light crude from Crane in Texas to Corpus Christi on the USGC. The 850-mile pipeline has a nameplate capacity of 1 million b\/d. The company also plans to add another 2 million barrels of storage at its purpose-built Enbridge Ingleside Energy Center crude oil export facility at Corpus Christi and increase the overall crude storage capacity to 20.5 million barrels by 2025, Ebel said. Lastly, Enbridge has also acquired two docks and nearby land adjacent to EIEC from fellow midstream entity Flint Hills Resources with a price tag of $200 million, providing future growth opportunities that optimize existing operations and create ready growth headroom for multiple products. \u201cThe Gray Oak expansion will be fully online in 2026 and incremental volumes will serve our Ingleside facility, which had a record quarterly volume of crude exports and a single-day loading of over 2.3 million barrels,\u201d Ebel said. The EIEC is \u201cadvantaged in many respects\u201d for crude exports and \u201cwe have another 1 million b\/d of crude volumes coming from the Permian\u201d, President of Liquids Pipelines Colin Gruending said on the same webcast. \u201cThat facility has moved over 3 million b\/d of crude out of the docks.\u201d Crude exports from the USGC averaged 4.2 million b\/d in July, S&P Global Commodities at Sea data shows. Of that, 1.1 million b\/d originated from the Enbridge Ingleside terminal, a record high, CAS data shows. Exports from Ingleside have climbed from 659,000 b\/d in April. CAS data shows only US-origin crude being exported from Ingleside. Overall, the solutions that Enbridge is providing to producers in the US and Canada for their need to move barrels to markets at a low cost is yielding results with the Mainline once again reporting a record throughput quarter, Ebel said. Light and heavy barrels on the Mainline last quarter stood at 3.078 million b\/d, a 74,000-b\/d increase over 2.991 million b\/d in the same quarter the prior year, Enbridge said in its earnings release. The 3,000-mile Mainline pipeline system transports Canadian heavy and light barrels from Edmonton to Gretna on the Canadian-US border where the volumes flow onto Enbridge\u2019s Lakehead system that supplies crude oil to refineries in PADD II (US Midwest) and further on to PADD III (USGC). Growing production from the Western Canadian Sedimentary Basin has resulted in Mainline volumes being apportioned last quarter with that scenario continuing into the fall as Enbridge spares no efforts to maintain its guidance of average 2024 throughput volumes of 3 million b\/d on the pipeline system, Ebel said. \u201cFor long-term egress out of Western Canada, given the strength in supply and appetite to get to the US markets, we are designning a 150,000 b\/d expansion of the Mainline. This will come into effect by late 2026 and will be very economical,\u201d Gruending said without giving any figures. A prime reason for WCSB seeking access to US markets is a better pricing and also dealing with negative price differentials for their heavy barrels. \u201cWith new pipeline access, we don\u2019t expect base differentials to be blowing up again,\u201d Gruending said. Western Canadian Select at Hardisty, Alberta averaged at a $14.56\/b discount to WTI in July, widening slightly from a $13.29\/b discount in June, Platts assessments show. However, that was tighter from a $25.44\/b discount in November, prior to the line fill for the Trans Mountain crude pipeline expansion. Platts is part of S&P Global Commodity Insights. Blackcomb expansion In the Permian Basin, Enbridge announced an FID for Blackcomb Pipeline , an up to 2.5 Bcf\/d natural gas pipeline which will provide transportation service from Rankin, Texas to the Agua Dulce area in South Texas providing much needed export capacity for Permian shippers, Ebel said. \u201cWe closed the 19% acquisition in an integrated Permian natural gas pipeline and storage joint venture with Whistler, which is immediately accretive and directly connected to our existing infrastructure at Agua Dulce. This investment is already yielding additional growth opportunities through FID of Blackcomb Pipeline which is expected to provide much needed egress for Permian natural gas shippers in 2026,\u201d Ebel said. Private firm WhiteWater Midstream will construct and operate the 365-mile, 42-inch diameter Blackcomb Pipeline, it announced late July 31. The second half of 2026 start date is subject to \u201cthe receipt of customary regulatory and other approvals,\u201d it said. \u201cWhistler has a track record of project deliveries on time and budget and they have a strong operating history,\u201d Enbridge\u2019s President Gas Transmission and Midstream Cynthia Hansen said on the same earnings webcast. ","headline":"Enbridge approves 120,000 b\/d expansion of Gray Oak Texas oil pipeline","updatedDate":"2024-08-02T18:29:24.000"},{"Unnamed: 0":385,"body":" July saw the return of key players Litasco and Koch to the Platts Brent CFD Market on Close assessment process. On July 18, Koch Industries sold an October pricing Aug. 5-9 Brent CFD into a bid published by Chevron, marking their first CFD trade in nearly eight years, having last traded with PetroIneos in October 2016. Koch have bought and sold CFDs in subsequent MOC sessions through July. Similarly, on July 15, Litasco sold an October pricing Aug. 5-9 Brent CFD into a bid published by Trafigura, marking their first CFD trade since March 2022. Litasco has continued to sell CFDs in the Platts MOC since. Litasco and Koch industries join a growing list of new and returning participants to the Platts CFD MOC, including Suncor Energies and Klesch Petroleum, continuing the wider trend of increased participation in the Brent complex via the Platts MOC. ","headline":"Litasco, Koch Industries return to Platts MOC through July","updatedDate":"2024-08-02T18:00:30.000"},{"Unnamed: 0":386,"body":" Chevron's pending merger with Hess is now expected to be reviewed by the US Federal Trade Commission starting in the third quarter, after the transaction close was delayed over a dispute with ExxonMobil, Chevron CEO Mike Wirth said Aug. 2. The merger, which was originally expected to close about mid-year 2024, was stymied when ExxonMobil stepped in to exercise its preemptive right of first refusal on Hess' 30% stake in Guyana's offshore Stabroek Block asset, which ExxonMobil operates. Hess and Chevron have disputed ExxonMobil's claim regarding rights of first refusal, or ROFR, which gives an asset holder a chance to match or decline to make an offer, before the owner can sell it to someone else. Chevron has said that the ROFR does not apply to the Stabroek Joint Operating Agreement because it is acquiring Hess' entire company, not simply a lone asset. Hess' asset portfolio also includes operations in the US Gulf of Mexico, the US Bakken Shale and offshore Thailand and Malaysia. On July 31, Chevron and Hess said an arbitration date has been set in mid-2025 for an arbitration panel to address ExxonMobil's claim, with a decision expected about three months later. The long lead time between that date and the present stems from scheduling issues. \"[We] had requested an earlier hearing ,but the panel ultimately sets the schedule,\" Wirth said. The Stabroek Block is a valuable asset, currently producing over 600,000 b\/d of oil from three FPSOs, with another four oil developments in various stages of construction. The next Stabroek project is slated to come online in 2025, followed by the others in 2026, 2027 and 2029. ","headline":"US' FTC to undertake review process in Q3 on pending Chevron-Hess merger","updatedDate":"2024-08-02T17:26:47.000"},{"Unnamed: 0":387,"body":" Brazilian state-led oil company Petrobras signed purchase and supply agreements with SLB OneSubsea to provide submarine equipment for the second phase of development at the Atapu and Sepia subsalt fields, and a revitalization campaign at the Roncador field. This is part of the latest production advance under the company's $102 billion investment plan for 2024-2028. The contract includes orders for 19 wet Christmas trees, five electrical-hydraulic distribution units, six pipeline end manifolds and related equipment, Petrobras said Aug. 1. The deal also includes installation, service and maintenance contracts. The equipment is among some of the most important pieces involved in safely producing oil and gas offshore, according to industry officials. Wet Christmas trees are tangles of pipes and valves that control the flow of oil from the well, which is supplied with electrical power and hydraulic fluids from the distribution units. Pipeline end manifolds connect the production lines with other systems onboard the floating production, storage and offloading vessels, or FPSOs, installed on the surface. \"The equipment will start to be built yet in the third quarter of 2024 at factories located in Brazil,\" Petrobras said. The order also underscores efforts by President Luiz Inacio Lula da Silva and his Workers' Party, or PT, to increase the use of locally produced goods and services in offshore oil field development. In 2023, Brazil's National Energy Policy Council, or CNPE, raised so-called local content requirements in an effort to stir activity in the country's oil and natural gas sector. The use of factories and service centers in Brazil means that SLB OneSubsea will reach local content of at least 55% in equipment manufacturing and 40% in services, but with the potential to hit as much as 65% local content, Petrobras said. \"Petrobras can guarantee the generation of jobs in the country as well as develop our national supply chain with these local content mechanisms,\" Renata Baruzzi, Petrobras' director for engineering, technology and innovation, said. FPSOs P-84, P-85 The supply contracts with SLB OneSubsea followed Petrobras' order of the FPSOs P-84 and P-85 from Seatrium O&G Americas in May. Seatrium was created out of the merger of Sembcorp Marine and Keppel Offshore & Marine. The FPSO P-84 will be installed at the Atapu field and pump first oil in 2029, while the FPSO P-85 will be installed at the Sepia field and enter production in 2030, according to Petrobras. Each of the FPSOs will have installed capacity to produce 225,000 b\/d and process up to 10 million cu m\/d. The two new FPSOs will also be all-electric models in a move that will reduce greenhouse gas emissions by 30% during production, Petrobras said. In addition, the vessels will feature other efficiency measures like gas recovery, waste heat recovery units, closed flaring and carbon dioxide gas storage. The Atapu and Sepia fields each currently feature a single floating production unit, according to Petrobras. The FPSO P-70, which has installed capacity to produce 150,000 b\/d and process up to 6 million cu m\/d, pumped first oil from the Atapu field in June 2020. Meanwhile, the FPSO Carioca, which has installed capacity to produce 180,000 and process up to 6 million cu m\/d, pumped first oil from the field in August 2021. Atapu produced 126,984 b\/d and 4.9 million cu m\/d in June, according to the latest production report from the National Petroleum Agency, or ANP, published Aug. 2. Sepia, meanwhile, pumped 139,266 b\/d and 5.1 million cu m\/d. Petrobras owns a 65.7% operating stake in the Atapu shared reservoir, with Shell retaining 16.7% and TotalEnergies holding 15%. Galp Energia also owns a 1.9% share and PPSA holds 0.9% as part of a unification agreement. Petrobras also holds a 55.3% operating stake in the Sepia field, with TotalEnergies owning 16.9%. Petronas and Qatar Energy each own 12.7% equity shares. Under terms of a unification agreement, Galp owns the remaining 2.4% stake. Roncador, meanwhile, produced 101,570 b\/d and 2.1 million cu m\/d in June, according to the ANP. Petrobras holds a 75% operating stake in the field, while Norway's Equinor retains a 25% equity share purchased in December 2017. ","headline":"Brazil's Petrobras signs supply deals for Atapu, Sepia field expansions","updatedDate":"2024-08-02T17:02:41.000"},{"Unnamed: 0":388,"body":" LyondellBasell reported its Houston refinery\u2019s second-quarter operations were affected by higher production countered by lower refining margins, according to a company executive Aug. 2. \u201cHigher production following the [Q1] downtime was more than offset by lower Maya crack spreads. Margins decreased driven by lower distillate cracks, partially by slight improvements in gasoline cracks with modest second quarter demand, indicating a slow start to the driving season,\u201d said Kim Foley, LyondellBasell's head of olefins & polyolefins, refining and supply chain on the Q2 results call. US Gulf Coast Maya coking margins in Q2 averaged $12.34\/b, slightly above the Q3 margin, which stood at $12.10\/b as of Aug. 2, according to S&P Global Commodity Insights margin data. \u201cIn the near term, we expect summer demand to support stable gasoline crack spreads and continued high operating rates for refiners. We intend to operate at approximately 90% of capacity\" in Q3, she added. Foley said LyondellBasell was committed to \u201cthe safe and reliable operation of these assets until we shut down, no later than the end of the first quarter of 2025,\u201d adding the company would provide additional details on the rampdown provided during its Q3 earnings updates. \u201cOur team is making good progress in evaluating projects to transform the site in support of our circular and low-carbon solution growth strategy,\u201d she added. Two projects being considered for the repurposing of the Houston refinery modified hydrotreaters to upgrade plastic oil produced by MoReTec, LyondellBasell\u2019s patented catalytic advanced recycling process, which would be sent to its steam crackers at Channelview, Texas. The second project is around renewable hydrocarbons feedstock, produced with used cooking oil and other wastes as feed for the hydrotreaters, with the product sent by pipeline to Channelview to be cracked and polymerized. ","headline":" LyondellBasell\u2019s Q3 Houston rates near 90%, mulls renewable fuels option for plant","updatedDate":"2024-08-02T16:56:42.000"},{"Unnamed: 0":389,"body":" Russia's Omsk refinery is expected to reduce processing until around mid-August while repairing a primary processing unit that was affected by fire Aug. 1, according to market sources Aug. 2. The refinery reported fire at a pumping station Aug. 1 adding that operations continued normally. However according to market sources and media reports the fire affected an 8.6 million mt crude and vacuum distillation complex AVT-10. The refinery was trading oil products on the St. Petersburg exchange Aug. 2 but sources indicated it will likely suspend truck loadings over the weekend. Sources told Russia's Tass news agency that external interference was not the cause of the fire, in contrast to recent incidents at Russian refineries predominantly caused by drone attacks. Separately, the Novoshakhtinsky refinery in southern Russia is expected to increase processing in August following restart after a drone attack, according to sources. A fire June 6 affected both CDUs, leading to a halt of operations. Previously, the refinery resumed operations shortly after drones fell at the site March 13. The export-oriented refinery, which produces feedstocks, was partly offline in the summer of 2022 following a drone attack. ","headline":" Russia's Omsk to reduce runs after fire; Novoshakhtinsky set to process more after restart: sources","updatedDate":"2024-08-02T16:31:31.000"},{"Unnamed: 0":390,"body":" Brazil's oil and natural gas production advanced for a second consecutive month in June amid the end of maintenance projects and revitalization campaigns at offshore fields, especially in the country's subsalt frontier, the National Petroleum Agency, or ANP, said Aug. 2. Oil companies operating in Brazil pumped an average of 4.353 million b\/d of oil equivalent in June, up 0.7% from 4.324 million boe\/d in June 2023, the ANP said in its latest production report. June's oil and gas output also rose 2.8% from 4.234 million boe\/d in May. The second month of production growth indicated that state-led oil company Petrobras and its partners developing subsalt deposits had completed a series of maintenance projects at offshore fields that had caused production to slide dramatically since November 2023. That was when Brazil set its most-recent record monthly high for oil and gas output at 4.698 million boe\/d. Petrobras typically concentrates maintenance shutdowns, well workovers and equipment overhauls in the first quarter of each year, when economic activity is at its weakest because of the fallow season between oil seed and sugarcane harvests. Brazil's massive agriculture sector is the primary driver in demand for diesel, which is Brazil's top refined product in terms of consumption. Despite the maintenance work, Brazil's oil and gas output is expected to continue to trend higher in the second half of 2024 amid the ramp up of production at floating production, storage and offloading vessels, or FPSOs, installed at offshore fields in 2023, according to government and industry officials. In addition, three new floating production units will start operations in the second half and several independent producers plan revitalization campaigns at important onshore and offshore fields. Petrobras installed the FPSO Anna Nery and FPSO Anita Garibaldi at the Marlim complex of heavy oil fields in May and August 2023, respectively, while the FPSO Sepetiba started operations at the Mero field in the Libra production sharing area on Dec. 31. The three floating production units are expected to reach full production capacity in 2024. Petrobras and its partners also plan to install the FPSO Marechal Duque de Caxias at the Mero field, while Enauta also expects to pump first oil from the FPSO Atlanta currently being anchored at the Atlanta field in August. Both vessels arrived in Brazilian waters from overseas shipyards in May. In June, Petrobras also said that it would pump first oil from the FPSO Maria Quiteria in the second half of 2024, which was several months ahead of schedule. The FPSO Maria Quiteria, which was previously scheduled to enter operations in the first quarter of 2025, will be installed at the Jubarte subsalt field in the northern portion of the Campos Basin off the coast of Espirito Santo state. Oil output also climbed higher for the second-consecutive month in June, the ANP said. Oil companies produced 3.409 million b\/d in June, up 1.2% from 3.367 million b\/d in June 2023. June's oil output also advanced 2.7% from 3.318 million b\/d in May. Subsalt fields continued to lead production, pumping 2.683 million b\/d and 117.9 million cu m\/d, or 3.424 million boe\/d, from 150 wells in June, up from 2.599 million b\/d and 113.7 million cu m\/d from 145 wells in May, the ANP said. The Tupi subsalt field remained the country's top oil and gas producer in June, the ANP said. Tupi pumped 787,080 b\/d and 39.7 million cu m\/d in June, up from 755,460 b\/d and 37.0 million cu m\/d in May. The FPSO Guanabara installed at the Mero field was once again Brazil's top oil and gas production platform in June, producing 178,381 b\/d and 11.6 million cu m\/d, the ANP said. Gas production mixed Natural gas output, however, was stronger-but-mixed in June, the ANP report showed. Gas production had rebounded after Petrobras and its partners completed maintenance work on the Mexilhao field gas platform and Route 1 pipeline at end-March. The platform acts as a hub for gas production from subsalt fields. Brazil's gas output, in general, has trended higher in recent years as subsalt development expanded, with many of the offshore fields containing high volumes of associated gas. A majority of the gas output, however, is currently injected back into reservoirs because of a lack of offshore gas-export infrastructure. Additional support infrastructure is expected to come onstream by the end of 2024, when the Route 3 pipeline and GasLub Itaborai gas processing plant are scheduled to start operations. The Route 3 pipeline will raise offshore gas-export capacity from subsalt fields in the Campos and Santos basins by about 21 million cu m\/d. Brazil produced 150.1 million cu m\/d in June, down 1.4% from 152.3 million cu m\/d in June 2023, the ANP said. June's gas output, however, climbed 3.1% from 145.6 million cu m\/d in May. In June, 84.2 million cu m\/d were reinjected and 46.7 million cu m\/d were available for commercial sale, the ANP said. Oil companies also burned off, or flared, about 3.1 million cu m\/d in June. Flaring volumes continued to retreat from previous months, when flaring rose steadily since December because of commissioning of gas-processing units onboard the FPSO Sepetiba installed at the Mero field. ","headline":" Oil, gas production rises for second consecutive month in June","updatedDate":"2024-08-02T16:29:47.000"},{"Unnamed: 0":391,"body":" Fracking activity in Vaca Muerta, the biggest shale play in Argentina, shot up 20.1% to 1,658 frack stages in July from 1,380 stages in the year-earlier month, led by increased activity by the country\u2019s state-run YPF and Mexico-based Vista Energy, a services company said Aug. 2. The number of stages was down 2.6% from a record 1,703 in June, the Argentinian unit of Houston-based services company NCS Multistage said in a report. Of the activity in July, YPF was the busiest with 855 stages, up from 716 stages in July 2023 but down from a record 886 in June this year. The company, the biggest oil and gas producer in Argentina, is selling maturing conventional fields to focus in Vaca Muerta with the aim of stepping up production and exports, first of oil, then of natural gas. The other leading fracker in July was Vista Energy with 315 stages, trailed by US-based ExxonMobil with 192 and BP-backed Pan American Energy with 180, NCS said. Fracking activity has been on the rise since 2021 as more companies step up the drilling and completion of wells in Vaca Muerta to boost production and exports. NCS has said that it expects the number of frack stages to shoot up 22% to nearly 18,000 in 2024 from a total of 14,747 in 2023. The total was 10,981 stages in the first seven months of this year, up 31.6% from 8,342 stages in the year-earlier period. Vaca Muerta leads Argentina\u2019s oil and gas production growth, with national oil output rising a year-over-year 6.5% to 660,414 b\/d in June and gas increasing 6.8% to 147.5 million cu m\/d over the same period, according to the latest Energy Secretariat data. Oil production in Neuqu\u00e9n, home to most of the in-production acreage in Vaca Muerta, shot up a year-over-year 25% to a new record of 400,931 b\/d in June, while gas output increased 14.5% to 104.2 million cu m\/d over the same period, the local Energy Ministry said July 22. Neuqu\u00e9n has set targets of reaching 1.2 million b\/d of oil production and 180 million cu m\/d of gas by 2028. ","headline":"Oil fracking activity in Argentina's Vaca Muerta play rises 20% in July on year","updatedDate":"2024-08-02T15:55:52.000"},{"Unnamed: 0":392,"body":" G&G Service won a license to develop the Vega Grande oil field in Mendoza in the latest push to increase production in the western province of Argentina, the local government said Aug. 2. The San Rafael, Mendoza-based company will take over operations of the block from Mendoza\u2019s state-owned energy company Emesa, the government said in a statement. Vega Grande was previously operated by UK-based Phoenix Global Resources, but it turned the block back over to Mendoza in 2018 and production subsequently fell to zero in 2021. Emesa stepped in to put the block into conditions for the auction, helping to revive output before awarding the license. G&G will now take over operations and deploy rigs with the aim of increasing production, the government said. Mendoza, the fourth-biggest oil province in Argentina, has been providing tax breaks and other incentives to rebuild production, which slumped during the coronavirus pandemic in 2020 and 2021 after years of decline as conventional reserves mature. The province has also awarded more blocks, helping to widen exploration, including for heavy crude in northern basis and light shale oil in southern parts of the province with access to Vaca Muerta, a huge shale play. Argentina\u2019s state-run YPF, for example, is investing $17 million in a two-well pilot project in the Paso de las Bardas Norte and CN VII A blocks, targeting Vaca Muerta. The efforts have turned around a production decline from 70,000 b\/d in 2019, with output recovering 0.8% to 55,832 b\/d in the first half of this year from 54,932 b\/d in the year-earlier period, according to data from the Argentinian Energy Secretariat. Vega Grande produced a peak of 120 b\/d under Emesa, compared with the largest Vaca Muerta fields producing up to nearly 80,000 b\/d. Yet G&G\u2019s entrance is part of a wider trend of bigger companies pulling out of maturing or low-production wells to focus on larger assets, in particular Vaca Muerta. YPF is selling 55 mature conventional fields around the country this year to focus on Vaca Muerta, which it is developing to step up exports, first of oil and then of gas. ","headline":"Argentina\u2019s Mendoza awards license to G&G to develop Vega Grande oil block","updatedDate":"2024-08-02T15:34:14.000"},{"Unnamed: 0":393,"body":" London-listed Tower Resources has secured a license extension for its oil exploration block in the \u201chugely prospective\u201d Walvis Basin off Namibia, the firm announced Aug. 2. In a statement, Tower said the Namibian authorities had agreed to extend its Initial Exploration Period for the PEL 96 license to the end of October 2024. The African country\u2019s Ministry of Mines and Energy has also invited the company to apply to enter its \u201cfirst renewal period\u201d on the exploration license, which will run for two-to-three years, it said. Tower acquired an 80% stake in blocks 1910A, 1911 and 1912B, covered by PEL 96, off Namibia\u2019s Skeleton Coast in 2018, and holds the acreage in partnership with state-owned Namcor. The license covers 23,297 sq km, according to Tower\u2019s website. The UK-based firm added that remaining work commitments agreed to under the initial exploration period are \u201calready substantially complete,\u201d but it would push its commitment to acquire 1,000 sq km of new 3D seismic data into the first renewal period. The company, whose main oil and gas projects are in Cameroon, is currently evaluating various exploration leads and prospects and plans to reprocess 2D seismic data over large chunks of PEL 96 in the coming months. That work will help guide future 3D data acquisition. \u201cOur view of the prospectivity of PEL 96 has improved greatly since we began the current phase of work in 2019, and we look forward to having sufficient data quality to share a more detailed picture of the structures we wish to explore further with the 3D data acquisition, as soon as we have it,\u201d Jeremy Asher, Tower\u2019s CEO, said in a statement. The Walvis Basin has played second fiddle to the Orange Basin, which has become the world\u2019s most exciting exploration play since multi-billion barrel oil discoveries were made there at TotalEnergies' Venus and Shell's Graff project in 2022. ExxonMobil and Africa Energy Corp both hold interests in the quieter Walvis. According to Tower, the basin is \u201can under-explored region in which recent drilling results have proven the presence of a working oil-prone petroleum system, along with good quality turbidite and carbonate reservoirs.\u201d Tower has been seeking a strategic partner for drilling, Asher told S&P Global Commodity Insights in an interview in March . \"We are working on the assumption that we'll have to fund the 3D seismic acquisition ourselves,\u201d he said. \u201cA lot of companies have been talking to us about the Walvis, and one reason is because there are only so many spots left in the Orange basin.\u201d Namibia does not currently produce any oil but is set for an economic overhaul when production begins, likely in 2029, according to Commodity Insights forecasts. On the same day as the announcement of its Namibia extension, Tower said it had added Africa-focused oil and gas lawyer Stacey Kivel to its board. The company is hoping to produce 8,000 b\/d of oil from 2025 through its Cameroon licenses and also holds exploration acreage in South Africa. ","headline":"UK's Tower Resources granted Namibia oil license extension","updatedDate":"2024-08-02T15:02:56.000"},{"Unnamed: 0":394,"body":" The majority of cargoes of Dated Brent basket crudes Brent, Forties, Oseberg, Ekofisk and Troll remained in Northwest Europe through July, data from S&P Global Commodities at Sea showed. Top destinations by number of cargoes for BFOET grades loading in July included the UK, Lithuania and the Netherlands, with the UK taking six cargoes, and the Netherlands and Lithuania both taking four. Other buyers included South Korea, Canada, Germany and Poland. CAS data showed two cargoes of Brent Blend loading in July, with both stems loading onto Aframax size vessels with destinations of the Netherlands and Lithuania respectively. Looking to Forties, five cargoes had loaded, including two VLCCs, one Suezmax, one Long Range 1, and one Aframax. The VLCC C. Spirit is reportedly bound for the port of Yosu in South Korea, whilst the VLCC Baltic Loyalty -- seen to have loaded via STS earlier in the month -- was seen to discharge in Rotterdam. Of the remaining Forties cargoes, Lithuania, Germany and Italy received cargoes loaded on board an Aframax, LR1, and Suezmax respectively. Six Oseberg parcels loaded in July, bound for the UK, Poland, Sweden, Denmark and the Netherlands. Ten parcels of Ekofisk loaded onto vessels bound for the UK, Lithuania, Germany and Poland. One Aframax cargo of Ekofisk is bound for discharge in Canada. Price differentials for North Sea crudes were well supported in July amid strong seasonal demand for light sweet crude and surging refinery runs. Traders also cited a buoyant US domestic market and healthy refinery demand from both US Gulf Coast and Chinese refiners as contributing to a tightening market for North Sea crudes. Comparing export destinations to June, July saw an increase in the number of BFOET cargoes bound for the UK and Lithuania, with both countries taking two more cargoes in July than in June, at six and four respectively. Sweden notably received fewer imports, taking one cargo in July after importing four in June. July loading BFOET cargoes June loading BFOET cargoes United Kingdom 6 4 Lithuania 4 2 Netherlands 4 3 Poland 2 4 Canada 2 2 Germany 2 1 Korea (South) 1 0 Italy 1 0 Sweden 1 4 Denmark 1 0 Spain 0 1 France 0 1 Finland 0 0 US 0 0 ","headline":"Majority of July loading BFOET crude volumes remain in CAS","updatedDate":"2024-08-02T14:48:09.000"},{"Unnamed: 0":395,"body":" Brazil's soybean and biodiesel sector is projected to face a 5.33% GDP decline in 2024, according to a study released Aug. 1 by the Brazilian Association of Vegetable Oil, or ABIOVE, and the Center for Advanced Studies on Applied Economics, or CEPEA. This downturn follows a robust 21% growth in 2023, with soybean GDP expected to drop by 13.07% and agro-services set to decline by 4.28%. The decline is attributed to unfavorable weather conditions and production constraints. Despite these challenges, the agro-industrial sector is forecast to grow by 2.95% in 2024, driven by increased biodiesel production and strong soybean meal exports. Biodiesel production is expected to surge by 36.47%, while the soybean crushing and refining industry is projected to see a modest growth of 0.59%. In addition, biodiesel is expected to surge by 36.47%. The soybean crushing and refining industry is set to see modest growth of 0.59%. The US Department of Agriculture in its July 12 World Agricultural Supply and Demand Estimates report forecast Brazil\u2019s 2024-25 soybean production at 169 million mt, up 10.45% year on year, while domestic crush is projected to remain unchanged at 54 million mt. Soybean meal and soybean oil production are projected at 41.58 million mt and 10.8 million mt, respectively, both unchanged year on year. Falling prices and margins Rising soybean inventories in Brazil and globally are depressing prices, signaling a potentially smaller planted area. Soybean prices are currently trading at some of their lowest levels in the last three years. Analysts at S&P Global Commodity Insights forecast Brazil\u2019s soybean stocks in 2023-24 at a record 6 million mt, resulting in a stock-use ratio of 4%, the largest in the last 25 years. For profitability and margins, analysts foresee a risk of below-average levels due to high global supplies and slowing demand growth from China. \"We see a risk for below-average levels as we forecast CME soybean futures declining due to high global supplies and slowing demand growth from China,\" the analysts said. Increasing biodiesel demand may not sufficiently promote soybean expansion, while keeping soybean carryout at lower levels and providing sufficient price stimulus. \"The increase in the industry\u2019s crush capacity is limited and much below the capacity of soybean exports,\" the analysts said. More demand required to meet blending mandate Analysts anticipate additional soybean demand to meet the government\u2019s proposed blending mandate of 20% by 2030. This expansion may face risks related not to soybean supplies but the industry\u2019s capacity. To meet the biodiesel blending mandate, an equivalent of 7.8 million hectares will be required, 17% more than Brazil\u2019s 2023-24 area. In the event of lower demand prospects from China, such expansion could face many downside risks alongside a declining soybean and biodiesel sector GDP, unless attractive margins, currently at around 3% for crushers, are provided. Soybean oil accounts for about 72% of raw materials used in Brazil\u2019s biodiesel production in 2024, compared with 69% in 2023, according to Abiove. Brazil\u2019s current biodiesel blending mandate is B14, or 14%, the largest in the country\u2019s history. In September 2023, the government introduced a proposal under the \"fuel of the future\" bill to increase the blend by 1 percentage point each year until it reaches 20% by 2030. Market sources do not rule out growing blending mandates, with some optimistic projections reaching as high as 25% by 2030. However, challenges remain for the country\u2019s soybean production and area, including divergent weather conditions that add volatility to output prospects. ","headline":"Brazil soybean and biodiesel sector faces 5.33% GDP decline in 2024: study","updatedDate":"2024-08-02T14:42:13.000"},{"Unnamed: 0":396,"body":" Western Canadian Sedimentary Basin producer ARC Resources has elected to curtail some 250 MMcf\/d of natural gas production in response to weak natural gas prices, the company said. The shut-in volumes are at its Sunrise facility in British Columbia, output from which is committed to the 12 million mt\/year LNG Canada that is due to start warming up its gas liquefaction trains in late fall. Sunrise has a designed capacity of 360 MMcf\/d, according to information on ARC\u2019s website and the facility is committed to supply 150 MMcf\/d of feedgas to LNG Canada. The producer has curtailed output to preserve value for periods when prices are higher, the company said in its second-quarter earnings release late Aug. 1. \u201cSunrise is a low-cost natural gas asset, with a full cycle breakeven of about C$1.10\/MMBtu ($0.80\/MMBtu), inclusive of both cash costs of C$0.65\/MMBtu that includes operating, transportation and royalties) and finding and development cost,\u201d it said. Despite the curtailment at Sunrise, ARC\u2019s 2024 production guidance is unchanged with current expectations of 350,000 b\/d of oil equivalent to 360,000 boe\/d and a planned capital spending of C$1.75 billion to C$1.85 billion, it said. The inclusion of the natural gas curtailment at Sunrise is expected to result in average third-quarter production between 330,000 boe\/d and 335,000 boe\/d, with a higher percentage of crude oil and liquids relative to the second quarter of 2024, the release said. Last quarter, ARC\u2019s total production was 330,046 boe\/d, nearly 4% lower than 343,630 boe\/d in the same quarter the prior year. A prime reason for the decline was planned maintenance work at ARC\u2019s assets at Greater Dawson and Kakwa in the WCSB, it said. Of the total second-quarter 2024 production, light oil stood at 74,713 b\/d and NGL was 40,994 b\/d, while natural gas output was 1.286 Bcf\/d. The average prices realized last quarter for its crude oil and natural gas were C$100.28\/b and C$1.86\/MMBtu respectively. This compared with C$88.13\/b and C$2.83\/MMBtu for its crude oil and natural gas in the same quarter the prior year, the release said. Fourth-quarter production is expected to average 380,000-385,000 boe\/d, which includes restored volumes at Sunrise, increased condensate-rich production from Kakwa and Greater Dawson relative to the first half of 2024, and initial production contribution from the Attachie facility. Attachie Phase I update The 40,000 b\/d NGL processing Attachie Phase I plant remains on schedule and budget, with initial commissioning volumes planned for the fourth quarter of 2024 and full productive capacity in first-quarter 2025, the release said. ARC has spent C$362 million in the first half of 2024 on the project, with plant construction 75% complete and 30 wells being drilled. The transmission line, natural gas sales line, and water ponds are all complete, it said. Looking ahead, for 2025 ARC Resources is eyeing an 8% year-on-year increase in its gas and liquids output in 2025 to 375,000 boe\/d to 400,000 boe\/d, on the back of a major spurt in demand driven primarily by the startup of new LNG facilities along coastal British Columbia. ARC already has three long-term gas supply deals\/MOUs for LNG developments in North America that are indexed to Western Canadian and the Platts JKM (Japan Korea Marker) pricing. They include: firm deal with Cheniere Energy on the USGC for supply of 140,000 MMBtu\/d (140 MMcf\/d) of natural gas, along with another 150 MMcf\/d for LNG Canada and 200 MMcf\/d for the Cedar LNG project in British Columbia, according to information on ARC's website. The company also announced late 2023 it had entered into a long-term natural gas supply agreement with Sabine Pass Liquefaction Stage V, a subsidiary of Cheniere Energy, for nearly 140 MMcf\/d day that is expected to commence by 2029. ","headline":"Canada\u2019s ARC Resources shuts in 250 MMcf\/d of gas output due to low prices","updatedDate":"2024-08-02T14:41:02.000"},{"Unnamed: 0":397,"body":" S-OIL, the leading South Korean refiner, is aiming to make a significant expansion in the biofuels sector, focusing on sustainable aviation fuel (SAF) and renewable diesel as part of its commitment to sustainability and decarbonization, the company said in its ESG report Aug. 1. The company plans to raise production of SAF after 2028 by constructing a dedicated SAF plant. According to the report, this comes as part of a strategy to deal with a predicted shift in demand towards renewable fuels amid tighter carbon reduction regulations globally. S-OIL has achieved a major milestone by obtaining ISCC CORSIA certification, which qualifies its products as CORSIA-eligible sustainable aviation fuels. This certification paves the way for S-OIL to penetrate global markets, including Europe, where demand for sustainable aviation fuel is on the rise. Moreover, the company anticipates that SAF demand will soar to approximately 1.3 million barrels per day by 2035, driven by the International Civil Aviation Organization\u2019s (ICAO) Carbon Offsetting and Reduction Scheme for International Aviation (CORSIA). The company also aims to introduce renewable diesel fuel and bio-circular products to the market in 2024. A feasibility study for a dedicated SAF plant is slated for the second half of 2024. The company aims to expand the petrochemical business proportion by moving away from a fuel oil-centered business structure and seeking out various low-carbon solutions that take into account technological maturity and economic feasibility, such as carbon capture, utilization, and storage (CCUS) and hydrogen businesses in the mid to long term to achieve the strategic goal of eco-friendly growth. The Shaheen Project is being promoted with the goal of increasing the chemical business proportion to 25% by 2030. SAF is expected to account for 0.61% of global aviation fuel consumption in 2024, up from 0.31% in 2023, according to S&P Global Commodity Insights. This is expected to rise to 3.24% in 2040 and 24.06% in 2050, from 20,000 b\/d in 2023. Platts, part of Commodity Insights, assessed SAF production costs (palm fatty acid distillate) in Southeast Asia at $1,613.3\/mt on Aug. 1, up $2.97\/mt from the previous assessment. ","headline":"S-OIL plans for strategic investments in SAF and renewable diesel","updatedDate":"2024-08-02T12:29:13.000"},{"Unnamed: 0":398,"body":" Fuel oil stocks in the Amsterdam-Rotterdam-Antwerp refining hub fell by 2.1% to 1.393 million mt in the week to Aug. 1, Insights Global data showed. This represents the lowest level since February 2024. Fuel oil\u2019s share of overall oil product inventories in the ARA region remained at 24%. Insights Global does not differentiate by type of fuel oil. The Northwest European high sulfur (3.5%) fuel oil complex was characterized by \u2018steady demand\u2019, sources said in the week to July 25, following expectations of a rise in supply from the Americas to arrive in the first half of August. Despite the arrival of cargoes from the Americas entering the Mediterranean, sources have indicated that bitumen season has resulted in a tightening of supply for HSFO. As the European summer is associated with warm weather which is optimal for road construction, refineries are maximizing bitumen yields, reducing the output of high sulfur fuel oil molecules. Elsewhere, continued Middle Eastern demand for HSFO in the Mediterranean persists as their current supply of power generation for cooling purposes is insufficient due to the extreme heat the region is facing. The Med North saw fluctuations on the week, with a momentary flipping in structure erased by offers seen in the Platts Market on Close process, and the month roll occurring. Platts, part of S&P Global Commodity Insights, assessed front-month paper 3.5% FOB Mediterranean cargoes at a $5.25\/mt discount to their Rotterdam barge counterparts Aug. 1, $4.75\/mt higher than July 26. Within the very low sulfur (0.5%S) fuel oil markets, traders indicate that bunkering demand is slightly better compared to a couple of months ago. However, lower volumes of ships using the Suez Canal and a larger proportion of scrubber-fitted tankers opting for the use of HSFO has meant that overall demand for the very low sulfur fuel remains underwhelming. The backwardation for 0.5% fuel oil balmo\/m1 strengthened on the week, as the months rolled, as market participants looked to price in strong bunkering demand for prompt months. Retail bunker demand remained weak in Northwest Europe and the Mediterranean in the week to August 2, while no supply issues were reported. Activity levels in Northwest Europe were subdued, with the exception of Hamburg which experienced \u2018moderate\u2019 demand levels. Supplies were healthy for all fuel grades. Lower market activity was attributed to the holiday season. Meanwhile, in the Mediterranean, activity levels were in a similar state, with low demand levels reported. That being said, Istanbul and Piraeus saw a higher level of activity, due to the conflict in the Middle East. Platts assessed the price of 3.5%S delivered Rotterdam bunker fuel at $449\/mt August 1, down 1.54% on the day. Meanwhile, the Gibraltar 3.5%S equivalent was assessed at $515\/mt Aug. 1, down 1.9% on the day. ","headline":"ARA fuel oil stocks fall 2.1% on week to 1.393 million mt: Insights Global","updatedDate":"2024-08-02T12:22:47.000"},{"Unnamed: 0":399,"body":" Crude oil prices slipped in the late morning London trade Aug. 2 amid poor macroeconomic data from the US and China, despite continued tensions in the Middle East At 1141 GMT, NYMEX September WTI futures contract was down 37 cents\/b at $76.49\/b and ICE October Brent futures contract fell 39 cents\/b to $79.70\/b. Despite the ongoing tensions in the Middle East, crude oil prices fell on the day, with market participants pointing towards little tangible change in the current conflict. Currently, the ongoing disruption from Houthi strikes on commodity ships in the Red Sea poses more of a threat to the wider market, as supply lines are under threat, and shipping charters are opting to move around the Cape of Good Hope, increasing shipping costs as well as freight times. This, however, could change if Iran gets more hands-on in the current development, with any change in output of their current oil supply altering the wider oil market as a whole. \u201cThe market will continue to follow developments in the Middle East and, in particular, on what form Iranian retaliation might take and whether that poses a risk of escalation,\u201d Callum Macpherson, head of commodities at Investec said in a note Aug. 2. Both Iran and Hezbollah have indicated they are primed to retaliate against Israel, who recently claimed responsibility for the assassination of a slew of high-ranking militant leaders in the Middle East, but have not commented directly on the strikes. \u201cThe more Iran gets directly involved, the more risks of oil supply disruption grows,\u201d Ewa Manthey, commodities strategist and Warren Patterson, head of commodities strategy at ING said in a note. Appetite from China has also been poor in recent days, with the negative sentiment from Asia currently outweighing sentiment coming from the Middle East. In addition, weaker-than-expected macroeconomic data from the US should only weigh even further on the market, with demand concerns being raised for oil globally. The OPEC + Joint Ministerial Monitoring Committee (JMMC) meeting followed the anticipated course Aug. 1, with the committee recommending no changes to output policy for the wider OPEC group. In a statement from OPEC, the JMMC emphasized the gradual phase-out of supply cuts from October 2024 could be put on halt or completely reversed with market fundamentals in mind. \u201cIf the market continues to be soft, as it has been lately, despite fresh geopolitical developments in the Middle East, those core OPEC+ members might well decide to delay the phasing out of cuts for another quarter,\u201d Macpherson indicated. ","headline":" Crude slides amid poor China demand, weak US economic data","updatedDate":"2024-08-02T11:35:29.000"},{"Unnamed: 0":400,"body":" Traded volumes of fuel oil within the Platts market on close assessment process surged 82% on the month to 634,000 mt in July. Within the high sulfur (3.5%S) fuel oil markets, the barge market saw the largest volumes with 342,000 mt having traded compared to 214,000 mt the month prior. The largest buyers were Orim Energy and Peninsula while the largest sellers were Totsa and Gunvor. A HSFO cargo trade was also observed where Mercuria sold a 30,000 mt cargo to Galaxy on a CIF Malta basis. No HSFO cargo trades were observed in June. Within the very low sulfur (0.5%S) fuel oil markets, the barges market saw 262,000 mt trade compared to 134,000 mt the month prior. The largest buyers were BP and Totsa while the primary sellers were Glencore and Trafigura. No VLSFO cargo trades were observed during the MOC process in July. Within the low sulfur (1%S) fuel oil markets, no trades were seen either in the barge or cargo markets echoing the lack of activity last month. This lack of activity highlights the quiet and thinly traded nature of the LSFO market despite a seasonally more demanding period. ","headline":"Fuel oil traded volumes for Platts EMEA MOC jump 82% in July","updatedDate":"2024-08-02T11:30:48.000"},{"Unnamed: 0":401,"body":" A fire at Gazprom Neft's Omsk refinery, Russia's largest, was unrelated to \"external interference\", Russian media reported, after an incident at its pump station on Aug. 1. The 428,000 b\/d Siberian refinery reported that a fire had been quickly contained Aug. 1 after erupting at a pump station in an auxiliary area. Sources told Russia's Tass news agency that external interference was not the cause of the fire, contrasting to incidents in which plants have been targeted by drone strikes in recent months. According to media reports, the fire occurred at the crude and vacuum distillation complex AVT-10, which has an 8.6 million mt\/year capacity, though the refinery reported that it continues to operate normally and no casualties had occurred. The refinery was selling products on the St. Petersburg exchange Aug. 2. However, according to market sources it has temporarily suspended shipments of oil products by truck until next week. Located in Siberia, the refinery is a key supplier of motor fuels to the domestic market, processing Siberian Light crude and gas condensate and exporting products via pipeline and rail to demand hubs east and westward. The refinery is connected to the diesel pipeline network that ships products to domestic users as well as to export destinations via the sea ports of Primorsk and Novorossiisk. Meanwhile, a group of lawmakers have submitted a draft law to Russia's Duma aimed at improving protection of energy infrastructure against drone attacks, the Duma said late Aug. 1. The document would increase the rights of private security organizations, oil companies and pipeline operator Transneft to better counter drone attacks. The new document follows some amendments to existing legislation. ","headline":"Fire at Russia's Omsk refinery 'unrelated to external interference': report","updatedDate":"2024-08-02T11:26:40.000"},{"Unnamed: 0":402,"body":" Marine fuel prices across the globe were little changed in the week ended Aug. 1 amid moderate demand and ample stocks, but fundamentals could loosen towards late summer with rising supply in some key markets. The 0.5% sulfur fuel oil index ended the week at $610.87\/mt, up $2.53\/mt on the day, $0.28\/mt week on week but still down $25.01\/mt month on month. The BW380 index ended the week at $523.95\/mt, down $0.79\/mt on the day, $1.26\/mt week on week and $25.47\/mt month on month. In crude futures markets, traders have shifted their attention from OPEC+ talks to macroeconomic conditions and geopolitical tensions. A US interest rate cut could be forthcoming following a higher-than-expected US jobless claims report, which could boost demand prospects, while worries persist over an escalation of regional warfare in the Middle East. Iran and Hezbollah have both vowed to respond against Israel, who they claim is responsible for the assassination of militant leaders in the region. Israel has not commented directly on the strikes. \"As the situation remains fluid, market participants will be closely monitoring developments in the Middle East and their potential impact on global oil supplies and prices,\" said IG's chief market analyst Chris Beauchamp. In Singapore, the world\u2019s largest bunkering hub, demand for low sulfur fuel oil has been moderate, whereas high sulfur fuel oil requirements have improved over the past couple of weeks. However, Asian LSFO fundamentals are likely to come under pressure in August, as higher arbitrage arrivals from the West add to already increasing stockpiles in the region. Moderate LSFO demand in the UAE bunker port of Fujairah has limited the potential for higher bunker premiums, as demand for August refueling dates fell short of stronger market expectations, according to bunker suppliers. Stockpiles of heavy distillates at the Fujairah hub -- used for power generation and as ship fuel -- climbed 3% week on week to a two-week high of 9.702 million barrels in the week ended July 29, the latest data from the Fujairah Oil Industry Zone showed. Weak Mediterranean demand In Northwest European bunker markets, participants will continue to focus on whether activity in the Amsterdam-Rotterdam-Antwerp hub will pick up. Despite weak market conditions, bunker prices have been firming in recent days, and traders will be monitoring prices to see whether that continues. Heading south to the Mediterranean, demand levels have been low, with activity in both the East and West Mediterranean low. That said, more recently there has been an improvement in activity levels in Piraeus and Istanbul due to the conflict in the Middle East. Activity levels are set to remain elevated in the region, in part due to the conflict. Latin American bunker markets opened the month with mixed movement, with one source predicting Chilean trade would be back to normal from seasonal weakness by September or October, when cruise ships start to arrive. The BW Indexes are weighted daily indexes made up of price assessments at 20 key bunkering ports. To obtain a representative geographical spread, the ports were selected by size with reference to their geographical importance. The BW 0.5% Sulfur Index ports are Hong Kong, South Korea, Shanghai, Singapore, Japan, Las Palmas, Durban, Fujairah, Gibraltar, Piraeus, Rotterdam, St. Petersburg, Houston, Los Angeles, New York, Balboa and Santos. The BW380 Index ports are Busan, Canary Islands, Colombo, Durban, Fujairah, Gibraltar, Hong Kong, Houston, Los Angeles, New York, Offshore Nigeria, Panama Canal, Piraeus, Rotterdam, Santos, Shanghai, Singapore, St. Petersburg, Suez and Tokyo. ","headline":" Prices largely flat; fundamentals may weaken in August","updatedDate":"2024-08-02T10:36:27.000"},{"Unnamed: 0":403,"body":" The Middle East sour crude complex saw cash differentials for key sour crude markers slip on the day, while activity in the broader market was thin with traders awaiting the release of producers' September official selling prices. Platts, part of S&P Global Commodity Insights, assessed October cash Dubai and cash Oman at a premium of 96 cents\/b to same-month Dubai futures at the market close, both down 8 cents\/b on the day. October cash Murban was also assessed at a premium of 96 cents\/b to same-month Dubai futures, down 10 cents\/b on the day. During the Market on Close assessment process, 21 October Dubai partials of 25,000 barrels each traded. The sellers were Trafigura, Mitsui, Unipec, Reliance and Idemitsu, while the buyers were Vitol, Gunvor and Glencore. No convergences were reached during the MOC. A convergence occurs when 20 partials are traded between two counterparties, resulting in a full 500,000-barrel physical cargo being declared from the seller to the buyer. Activity in the broader market remained muted with the October-loading cycle is still in its early days, though Japan's Inpex was heard to have sold its early-cycle October ADNOC crudes. The producer sold its Upper Zakum crude cargoes at discounts in the range of 8-10 cents\/b to the grade's official selling price, FOB, while the Murban crude cargoes were sold at a premium of around 17 cents\/b to its OSP, FOB, traders said. ","headline":" Middle East sour crude cash differentials slip","updatedDate":"2024-08-02T10:06:12.000"},{"Unnamed: 0":404,"body":" ENEOS, Japan's largest refiner, shut the sole 145,000-b\/d crude distillation unit at its Sendai refinery in northeast Japan on Aug. 1 due to technical issues, a company spokesperson said Aug. 2. The refinery continues to ship oil products to both the rack and seaborne markets, although no date has been set for the restart of the CDU, the spokesperson said. Meanwhile, ENEOS restarted the sole 129,000-b\/d CDU at its Chiba refinery in Tokyo Bay on July 28 after it was shut July 23 due to technical issues. The Platts-assessed gasoline, kerosene and gasoil prices across the Chiba, Kanagawa, Chukyo and Hanshin regions averaged Yen 77,250\/kiloliter, Yen 77,800\/kl and Yen 76,400\/kl, respectively, on Aug. 2, S&P Global Commodity Insights data showed. ","headline":" Japan's ENEOS shuts Sendai CDU on glitches","updatedDate":"2024-08-02T10:02:13.000"},{"Unnamed: 0":405,"body":" China\u2019s state-owned CNOOC was likely to have injected up to 400,000 mt (2.93 million barrels) of Russian ESPO crude into its storage in Dongying, Shandong province, in July as strategic petroleum reserve (SPR), according to data collected by S&P Global Commodity Insights Aug. 2. \u201cCNOOC took at least two Aframax [cargoes] of ESPO to store in its tanks in Dongying as SPR last month,\u201d one of the sources said. The company\u2019s crude storage in Dongying occasionally received crude barrels as SPR, other sources said. In July, CNOOC received at least 400,000 mt of ESPO by four Aframax ships at Dongying port, according to information collected by Commodity Insights. The company is also a leading feedstock supplier in Shandong, home to independent refineries. Sources with CNOOC were not available for comments. There were talks about Beijing asking its state-run oil companies to add 8 million mt (58.64 million barrels) of crude oil to SPR, with the stockpiling program running from July 2024 to March 2025. Data from Ursa Space Systems showed China\u2019s SPR rose to 212.7 million barrels in July from 211.8 million barrels in June. CNOOC\u2019s 4.25 million mt (31.15 million barrels) crude storage was commissioned in February 2023, which connects 50 tanks, each 100,0000 cu m, with Dongying port and CNOOC's Bohai oil block via an offshore pipeline. The storage was designed for commercial usage. However, it is common for Beijing to rent commercial storage owned by state-owned or private oil companies for SPR usage, such as the crude tanks in east China Zhoushan City and Hainan Island. Most of China\u2019s crude storages for SPR are situated next to neighboring state-owned refineries, while the Dongying one owned by CNOOC is closer to independent refineries rather than state-run plants. ","headline":"China's CNOOC likely injected ESPO to Dongying storage for SPR in July: sources","updatedDate":"2024-08-02T09:15:40.000"},{"Unnamed: 0":406,"body":" Crude oil futures were higher in afternoon Asia trade Aug. 2 as investors bought the dip following an overnight selloff, although analysts warned of increasing market volatility. At 2:11 pm Singapore time (0611 GMT), the ICE October Brent futures contract was up 56 cents\/b (0.7%) from the previous close at $80.08\/b, while the NYMEX September light sweet crude contract rose 55 cents\/b (0.72%) at $76.86\/b. Crude slumped overnight after OPEC and its allies announced they will stick with their plan to unwind some voluntary crude production cuts from October. The announcement compounded a higher-than-expected US jobless claims report that had dampened demand expectations. However, renewed expectations of a forthcoming US interest rate cut following the report, along with simmering Middle East tensions, kept a floor on prices. \"A disappointing US nonfarm payroll will likely confirm a September rate cut, boding well for a recovery in industrial activity. This should see commodity prices stabilizing,\" ANZ Research analysts said Aug 2. The market will continue to watch changes to US stockpiles as a gauge for demand strength until September after a fifth straight week of drawdowns most recently reported by the US Energy Information Administration, they added. \"Oil's three-month implied volatility rose to 26.6% from a low of 22.6% in mid-July,\" ANZ Research added, noting escalating tensions in the Middle East. Iran and Hezbollah have both vowed to respond against Israel, who they claim is responsible for the assassination of militant leaders in the region. Israel has not commented directly on the strikes. \"As the situation remains fluid, market participants will be closely monitoring developments in the Middle East and their potential impact on global oil supplies and prices,\" said IG's Chief Market Analyst, Chris Beauchamp. \"Unless diplomatic efforts succeed in de-escalating tensions in the Middle East, oil prices are expected to continue their upward trajectory,\" he said. In the coming week, investors await cues on services activity from key regions including the US, China and Japan. China's trade data will also be in focus with analysts expecting export demand to potentially ease. Dubai crude Dubai crude swaps and intermonth spreads were lower in afternoon Asian trading Aug. 2 from the previous close. The October Dubai swap was pegged at $84.11\/b at 2 pm Singapore time (0600 GMT), down $1.01\/b (1.27%) from the previous Asian market close. The September-October Dubai swap intermonth spread was pegged at 63 cents\/b, down 1 cent\/b over the same period, and the October-November intermonth spread was pegged at 46 cents\/b, down 5 cents\/b. The October Brent-Dubai exchange of futures for swaps was pegged at $1.75\/b, down 10 cents\/b. ","headline":" Crude price continues uptrend while market volatility rises","updatedDate":"2024-08-02T06:30:42.000"},{"Unnamed: 0":407,"body":" Singapore's commercial stockpiles of heavy distillates slipped 1.5% to a three-week low of 19.6 million barrels in the week to July 31, due to lower imports from the Middle East and Europe, Enterprise Singapore data showed late Aug. 1. The stocks were the lowest since 17.8 million barrels in the week ended July 10. This week\u2019s stockpiles fell 14.7% from the corresponding week in 2023. Residual fuel inventories in Singapore have averaged about 20.41 million barrels so far in 2024, compared with a weekly average of 20.43 million barrels in 2023 and 20.9 million barrels in 2022. Singapore's fuel oil imports dropped 32.4% week on week to 817,512 mt, with inflows from Asian suppliers making up about 47% of the volume, reaching 380,909 mt, a 46% rise on the week. The city-state's fuel oil imports from Malaysia surged 53% on the week to 244,340 mt, while inflows from Japan soared 78.2% week on week to 29,612 mt. Singapore imported 53,696 mt fuel oil from India and about 29,820 mt from Indonesia, compared with almost no volumes from these countries in the preceding week. Fuel oil imports from the Middle East fell for the second straight week to 220,266 mt, with about 160,845 mt from Oman and the rest from the UAE. Inflows from Europe plunged 85.5% week on week to 32,447 mt, all of which came from Sweden. There were no fuel oil imports from Russia during the week, while inflows from Brazil nearly halved on the week to 104,421 mt. Singapore exported 245,895 mt of fuel oil in the week to July 31, down from 460,335 mt in the previous week. The city-state's fuel oil outflows to China inched 0.4% higher on the week to 136,665 mt, but exports to Bangladesh tumbled 64% to 20,181 mt. Singapore's inventory data counts only stocks at onshore terminals. Enterprise Singapore describes heavy distillates as \"residues,\" which include cracked and straight run fuel oil and low sulfur waxy residue. Downstream valuations surge Low sulfur fuel oil demand in Singapore, the world\u2019 largest bunker hub, has been moderate, whereas high sulfur fuel oil requirements have improved over the past recent couple of weeks, traders said Aug. 2. Amid tighter product availability for very prompt LSFO requirements, sellers that are able to supply could potentially capture steeper premiums and drastically improve downstream margins in the delivered market, according to bunker suppliers. Product availability has tightened as some market participants have been awaiting replenishment cargoes in the wake of some off-specification supply issues since late July. The Platts Singapore-delivered marine fuel 0.5%S bunker premium over the benchmark FOB Singapore marine fuel 0.5%S cargo value hit a near six-month high of $30.66\/mt on Aug. 1, rising $3.72\/mt on the day. The premium was last higher at $34.15\/mt on Feb. 8. Platts is part of S&P Global Commodity Insights. \u201cLevels are all over the place these days in the LSFO market,\u201d a Singapore-based bunker supplier said, adding that buyers can expect to pay steep premiums for early-August refueling requirements. The spread between the Singapore delivered marine fuel 0.5%S price and the ex-wharf grade widened to an average of $6.04\/mt in July, from an average of $4.26\/mt in June and jumped to a near six-month high of $19\/mt on Aug. 1, according to Platts data. In the HSFO market, stable demand has led to stronger downstream valuations, reflecting a significant improvement since the second half of July because of a decent flows of spot inquiries, while inventories around the Singapore hub are expected to remain ample in the near term due to higher arbitrage inflows toward Asia, traders said. The Singapore-delivered 380 CST HSFO bunker premium over FOB Singapore 380 CST HSFO cargo values averaged $13.49\/mt in July, down from $15.12\/mt in June. Platts assessed the premium $2.30\/mt lower on the day at $19.50\/mt on Aug. 1. ","headline":" Fuel oil stocks drop to 3-week low of 19.6 mil barrels as of July 31","updatedDate":"2024-08-02T05:48:49.000"},{"Unnamed: 0":408,"body":" Taiwan's crude oil imports rose 6.2% on the month and 6.5% on the year to 923,460 b\/d, or 27.7 million barrels, in June, the latest data from the Ministry of Economic Affairs' Energy Administration showed. The US took over as Taiwan's top supplier with 318,286 b\/d, or 9.55 million barrels, of crude, up 46.7% on the month and 58.8% on the year, amid a still narrow Brent-Dubai price spread. The Brent-Dubai exchange of futures for swaps, or EFS, spread -- a key indicator of Brent's premium to the Middle Eastern benchmark -- averaged $1.36\/b in the first half of 2024, compared with $2.53\/b in the same period last year, S&P Global Commodity Insights data showed. A weaker EFS makes various sweet crude grades produced in the Americas, North Sea and Africa that are linked to the European benchmark more economical than Dubai-linked grades. Meanwhile, volumes from Saudi Arabia -- Taiwan's top crude supplier in May -- slid 9.2% on the month and 4.4% on the year to 294,876 b\/d, or 8.85 million barrels, in June, as the state-owned Saudi Aramco likely allocated fewer June-loading Arab Medium crude term oil supplies to some Asian refiners for the third straight month. Some reduced volumes of Arab Medium were also likely made to Chinese buyers, according to traders, ahead of the expected increased direct crude burn by Saudi Arabia to meet peak summer power generation demand. In July, Taiwan's CPC purchased via a tender three VLCC cargoes of US WTI Midland crude for October arrival, at a premium in the $4s\/b to September Dated Brent assessments, CFR Taiwan. Traders remarked that the traded premiums for WTI Midland were \"not cheap,\" although Asian refiners continued to purchase the US crude due to its preferred quality. In comparison, CPC previously purchased via a tender two VLCCs of US WTI Midland crude for September arrival from Mercuria and Oxy, at a premium of around mid-$3s\/b to August Dated Brent crude assessments, CFR Taiwan. Additionally, Taiwan's Formosa Petrochemical purchased 2 million barrels of Oman crude for October delivery at an unknown premium to Platts Dubai crude assessments, according to industry sources. The Platts-assessed second-month gasoil and jet fuel swaps crack spreads stood at $17.83\/b and $17.12\/b, respectively, at the Aug. 1 Asian close, compared with an average of $17.51\/b and $16.52\/b, respectively, in July, Commodity Insights data showed. Taiwan's crude suppliers in June: (Unit: b\/d) June '24 May '24 % change June '23 % change US 318,286 216,926 46.73% 200,455 58.78% Saudi Arabia 294,876 324,686 -9.18% 308,376 -4.38% Kuwait 131,358 126,257 4.04% 164,702 -20.25% Qatar 68,309 30,666 122.75% 34,143 100.07% Oman 62,511 62,903 -0.62% 63,371 -1.36% UAE 48,120 76,896 -37.42% 96,395 -50.08% Total imports* 923,460 869,254 6.24% 867,442 6.46% *includes other suppliers Source: Ministry of Economic Affairs' Energy Administration ","headline":" June crude oil imports rise 7% on year; US takes over as top supplier","updatedDate":"2024-08-02T04:54:48.000"},{"Unnamed: 0":409,"body":" The volume of Singapore fuel oil derivatives traded during the Platts Market on Close assessment process rose 17.1% on the month in July to a four-month high of 15.47 million barrels, S&P Global Commodity Insights data showed. The total volume traded in July was the highest since March, when 16.31 million barrels traded. The July volume, however, was nearly 24% lesser compared with the corresponding month in 2023, the data showed. Singapore 0.5%S marine fuel swaps trade volume increased to 4.79 million barrels in July, about 81.4% higher from 2.64 million barrels in June. On a year-on-year basis though, the July LSFO trade volume was 54.4% lower, Commodity Insights data showed. The monthly rise in traded volumes comes on the back of wider prompt time spreads for Singapore LSFO swaps. The M1-M2 intermonth spread for FOB Singapore 0.5%S marine fuel swaps averaged at a backwardation of $7.06\/mt in July, up from $5.68\/mt in June, Commodity Insights data showed. However, Asian LSFO fundamentals would likely come under pressure in August as higher arbitrage arrivals from the West adds to already increasing stockpiles in the region, which has recently been witnessing relatively lackluster bunker demand, market sources said. Alongside the low sulfur straight-run fuel oil barrels from Nigeria\u2019s new Dangote refinery coming into Asia in recent weeks, traders said they were expecting potentially more exports from Kuwait\u2019s Al-Zour refinery in coming months. Platts assessed the Singapore 0.5%S marine fuel cargo's cash differential with the Mean of Platts Singapore Marine Fuel 0.5%S assessment at a premium of $5.75\/mt Aug. 1, down from $7.34\/mt on July 31, when the premium posted a monthly gain of 62%, Commodity Insights data showed. Meanwhile, Singapore high sulfur fuel oil swap trade volume inched up 1.04% on the month to 10.68 million barrels in July, hitting a fresh high since December 2023 when 13.1 million barrels were traded, the data showed. Of the total HSFO swaps traded in July, 8.26 million barrels were 380 CST HSFO trades, down about 5% on the month, the data showed. The M1-M2 spread for the 380 CST grade averaged at a backwardation of plus $13.98\/mt in July, compared with the June average of plus $7.65\/mt, Commodity Insights data showed. The Asian HSFO market currently remains well supported, partly buoyed by summer power generation demand, while growing numbers of scrubber-installed ships were boosting bunker fuel demand for the high-sulfur grade, market sources said. The Singapore 380 CST HSFO cargo\u2019s cash premium over the MOPS 380 CST HSFO assessment, which posted a monthly rise of 55% in July, was assessed at a premium of $5.35\/mt Aug. 1, Commodity Insights data showed. In July, 180 CST swaps trades rose to 480,000 barrels from 350,000 barrels in June, Commodity Insights data showed. In the physical cargo market, FOB Singapore fuel oil trade volumes during the MOC in July dropped 24.4% on the month to 620,000 mt (about 127,000 b\/d), drifting lower from a five-month high registered in June, as volumes of both high and low sulfur marine fuel cargo deals shrank, Commodity Insights data showed. Physical trades for FOB Singapore 0.5%S marine fuel dropped about 11% on the month to 480,000 mt in July, while 60,000 mt of the mainstream 380 CST HSFO traded during the MOC, Commodity Insights reported earlier. Platts Singapore MOC swaps traded volume: ('000 barrels): July 2024 June 2024 Monthly change (%) July 2023 Yearly change (%) Total Platts HSFO 10,680 10,570 1.04% 9,780 9.2 Total Platts Marine Fuel 4,790 2,640 81.44% 10,510 -54.42 ","headline":"Platts Singapore MOC fuel oil swaps traded volume gains about 17% on month in July","updatedDate":"2024-08-02T04:50:50.000"},{"Unnamed: 0":410,"body":" Singapore's bitumen exports jumped 46.4% week on week to 45,151 mt in the week ended July 31, data released by Enterprise Singapore showed Aug. 1. Thailand received 9,014 mt bitumen in the week, surging from 1,001 mt in the preceding week and to the highest weekly volume in 10 weeks. Singapore\u2019s bitumen exports to Australia climbed 40.8% on the week to 7,061 mt and outflows to China rose 36.7% to 6,499 mt. Singapore also exported 2,081 mt bitumen to Brunei and 1,452 mt to Cambodia in the week ended July 31 -- the first shipments to these destinations in 2024. Exports to Malaysia rose 44% on the week to 7,526 mt, while exports to Indonesia dropped nearly 19% to 7,257 mt. Regional bitumen demand could pick up further in the coming weeks as the monsoon season wanes and firmer demand from Australia may bolster the market fundamentals, trade sources said. Platts, part of S&P Global Commodity Insights, assessed the FOB Singapore bitumen price at $489.25\/mt at the Asian close Aug. 1, buoyed by a competitive bid from Trafigura during the Platts Market on Close assessment process. The Singapore bitumen price climbed 8.3% in July and has averaged at $486.78\/mt over July 25-31, compared with $473.70\/mt in the preceding week over July 18-24, Platts data showed. The differential for PEN 60-70 grade bitumen loading in Singapore to benchmark Singapore 380 CST high sulfur fuel oil turned positive July 25 for the first time since late February and has averaged at a premium of $14.37\/mt over July 25-31, compared with an average discount of $12.41\/mt in the previous week. ","headline":" Bitumen exports climb 46% on week as Thailand, Australia outflows soar","updatedDate":"2024-08-02T04:08:17.000"},{"Unnamed: 0":411,"body":" South Korea's top refiner SK Innovation has no plans to shut its crude distillation units for maintenance in the third quarter as it forecasts solid products crack margins, but has remained cautious in raising crude throughput, a company official said Aug. 1. \u201cThe company will not shut down other facilities such as heavy oil upgraders in the third quarter as we conducted massive maintenances so far this year,\u201d the official said. The refiner has restarted its 240,000 b\/d No. 4 CDU in the Ulsan complex since June 20 after a month-long maintenance. SK Innovation has also restarted the 260,000 b\/d No. 5 CDU since April 15 after a month-long maintenance focused on replacing the preheater for boosting efficiency. The refiner\u2019s No. 1 residue hydrodesulfurization unit with a capacity of 72,000 b\/d in the Ulsan complex has restarted since June 20 after a month-long maintenance. The company also restarted two vacuum residue desulfurization units, both in the Ulsan complex and each with a 40,000 b\/d capacity, in early April after weeks-long maintenance. SK Innovation's crude run rate averaged 81% in the second quarter, up from 80% a year earlier but down from 85% in the first quarter, according to the company official. Its crude run rate was still well below the prepandemic level of around 90%, though it has bounced back from 77% in 2022, 66% in 2021 and 75% in 2020. The refiner could slightly raise crude throughput later this year, but would remain cautious due to lingering market uncertainties. \u201cStrong refining margins are expected in the second half as OPEC+ production cuts buoy oil prices and demand for transportation, cooling and industrial use picks up as the peak oil demand season begins, although delayed demand recovery from China and emerging markets along with prolonged high interest rates could slow down the real economy,\u201d the company official said. \u201cThere\u2019s still worries about dampening oil products demand due to the US Fed\u2019s prolonged high interest rate policy.\" SK Innovation operates the Ulsan complex on the southeast coast that runs five CDUs with combined capacity of 840,000 b\/d. Its another complex in Incheon on the west coast runs two CDUs with 275,000 b\/d, which makes its total refining capacity of 1.115 million b\/d in addition to a 100,000 b\/d condensate splitter. ","headline":" South Korea's SK Innovation to skip CDU turnaround in Q3 on rebounding margins","updatedDate":"2024-08-02T03:19:46.000"},{"Unnamed: 0":412,"body":" IFAD Murban crude futures trades inched higher by 1.4% on the month to 595,002 lots in July, hitting a record high for the second straight month, data from Intercontinental Exchange's ICE Futures Abu Dhabi market showed Aug. 2. Trading activity in the crude futures had also hit a record high in June, reaching 586,723 lots. However, the traded volume for front-month September Murban first line futures fell to 115,091 lots in July, from 123,901 lots for front-month August Murban first line futures in June. The traded volume for Murban crude futures rose as stronger US domestic prices led to a closed arbitrage for flows of light, sweet WTI Midland into Asia, buoying differentials for Murban crude despite poor end-user margins across the region. WTI Midland's premium over Murban crude hit its highest in more than two years of $3.40\/b on July 25. The premium was last higher at $3.56\/b on June 14, 2022. WTI Midland averaged at a premium of $1.82\/b over Murban crude in July, rising from a premium of $1.48\/b in June. A firmly backwardated structure across Western crude markers further hindered flows of West African and Mediterranean crudes into the region, pivoting end-user demand to shorter-haul Middle Eastern crudes. The above factors helped lift the Platts-assessed front-month cash Murban differential over same-month Dubai futures to an average premium of $1.60\/b in July, increasing 72 cents\/b on the month. Platts is part of S&P Global Commodity Insights. Meanwhile, open interest for the futures contract on July 31 rose to 54,139 lots, from 51,867 lots as of June 28. Open interest for front-month September first line futures climbed to 13,841 lots on July 31, from 12,334 lots for front-month August Murban first line futures on June 28. Murban crude -- a light sour crude that has a gravity of 40.5 API and sulfur content of 0.74% -- is ADNOC's largest crude by volume, accounting for about 2 million b\/d of production capacity. The company forecast its flagship crude volume available for export in July 2025 of 1.768 million b\/d, an increase from 1.747 million b\/d set for June 2025 and a new record high for exports of the grade. For October 2024, 1.665 million b\/d is available for export, up from a forecast of 1.643 million b\/d for September. ADNOC sets the official selling price of its flagship Murban crude based on the monthly average of the Murban's Singapore marker price on IFAD, while the OSP for its other grades, Upper Zakum, Das Blend and Umm Lulu is set as a differential to the Murban OSP. The IFAD Murban contract is underpinned by ADNOC's flagship Murban crude grade and is backed by ICE, ADNOC, BP, GS Caltex, INPEX, ENEOS, PetroChina, PTT, Shell, TotalEnergies and Vitol. Total traded volume: July June Monthly change Murban crude futures 595,002 586,723 1.41% Murban first line 115,091 123,901 -7.11% Total open interest: As of July 31 As of June 28 Monthly change Murban crude futures 54,139 51,867 4.38% Murban first line 13,841 12,334 12.22% Source: ICE Futures Abu Dhabi ","headline":"IFAD Murban crude futures trades hit record high for second straight month in July","updatedDate":"2024-08-02T03:12:02.000"},{"Unnamed: 0":413,"body":" The volume of Singapore gasoline swaps traded during the Platts Market on Close assessment process fell 31.5% on the month to 7.83 million barrels in July, data from S&P Global Commodity Insights showed Aug. 1. On a year-on-year basis, the volume of traded gasoline swaps declined 23.46%, the data showed. The Asian gasoline complex softened in July due to tepid demand from Indonesia after the festive season as the country moved away from the Eid al-Adha period, trade sources said. The ongoing monsoon season in India also dampened demand for transportation fuels, leading to an estimated 84,000 b\/d decline in gasoline demand, analysts at Commodity Insights said in their latest South Asia short-term outlook. Demand for gasoline in Vietnam -- one of the region's largest buyers of higher octane gasoline -- also fell on the back of heavy flooding, sources said. Additionally, traders may have exited their positions ahead of July or were unwilling to commit to fresh positions amid potential market volatility, market sources noted. Looking ahead, Indonesia's import demand for gasoline is expected to remain stable to weaker in August at 10 million-11 million barrels, possibly due to increased production following the return of Pertamina's Balikpapan refinery, sources said. The 360,000-b\/d No. 4 crude distillation unit at the Balikpapan refinery in East Kalimantan, Indonesia resumed normal operation as of July 26, Commodity Insights previously reported. While Mexico's PMI Comercio Internacional was heard pulling several gasoline cargoes from Asia amid favorable arbitrage, some market participants expressed skepticism that this year's outflow of Asian gasoline to Mexico would match previous years. The regional supply outlook also looked set to grow amid fresh signs that China would export additional cargoes in August, a Singapore-based trader said. For now, China's clean oil product exports in 2024 are anticipated to remain stable on the year at around 40 million mt due to less favorable export margins and a slight domestic surplus. Singapore MOC traded gasoline swaps volume in July: (Unit: '000 barrels) July '24 June '24 MoM change (%) July '23 YoY change (%) Total Platts gasoline 92 7,830 11,430 -31.50% 10,230 -23.46 Source: S&P Global Commodity Insights ","headline":"Singapore July MOC gasoline swaps trades fall 32% on month as fundamentals soften","updatedDate":"2024-08-02T03:08:08.000"},{"Unnamed: 0":414,"body":" The volume of Singapore gasoil swaps traded during the Platts Market on Close assessment process fell 7.96% on the month to 9.25 million barrels in July, marking a five-month low, S&P Global Commodity Insights data showed Aug. 1. The volume was last lower in February when 7.4 million barrels were traded, the data showed. The decline in the volume of swaps traded was in contrast to the volume of physical cargoes traded during the Platts MOC process which logged a nine-month high of 2.15 million barrels in July. While stockpiling demand for winter heating is due to begin in the coming months, current gasoil demand remains under pressure amid a seasonal lull due to the monsoons. Furthermore, Asia continued to witness a supply glut amid poor arbitrage economics to the West as elevated freight rates trapped barrels in the region. Reflecting stability in the swaps market, the Platts-assessed FOB Singapore 10 ppm sulfur gasoil front month derivative time spread was mostly unchanged across June and July, averaging about minus 10 cents\/b in both months. Looking ahead, Commodity Insights analysts revised down their forecast for Asian diesel\/gasoil demand growth by 60,000 b\/d to 90,000 b\/d in 2024. \"This reflects a downward revision to demand in mainland China, where the real estate sector continues to lag despite stimulus measures, and growing LNG heavy truck penetration driven by economic benefits,\" the analysts said in their latest outlook. China's 2024 clean oil product exports have been widely expected to remain steady on the year at about 40 million mt, due to less attractive export margins and a slight surplus in the domestic market. Singapore July MOC traded swaps volume: (Unit: \u2018000 barrels) Jul '24 Jun '24 MoM Change (%) Jul '23 YoY Change (%) Total Platts GO 9,250 10,050 -7.96% 6,100 51.64 Source: S&P Global Commodity Insights ","headline":"Singapore July gasoil swaps traded on Platts MOC extend decline to 5-month low","updatedDate":"2024-08-02T00:07:21.000"},{"Unnamed: 0":415,"body":" California governor Gavin Newsom put forth a proposal authorizing the California Energy Commission (CEC) to require the state\u2019s nine refineries to maintain a minimum fuel reserve to avoid supply shortages and prevent the gasoline pump price spikes seen in 2023, providing a supply cushion during the state\u2019s energy transition period toward electric vehicles. \u201cPrice spikes at the pump are profit spikes for Big Oil. Refiners should be required to plan ahead and backfill supplies to keep prices stable, instead of playing games to earn even more profits. By making refiners act responsibly and maintain a gas reserve, Californians would save money at the pump every year,\u201d Newsom said in his Aug. 15 statement. Under Newsom\u2019s proposal, California refiners would have to share resupply plans with the CEC to show they have ample supplies to counter production loss during times of refinery maintenance. It would give the CEC authorization to force refiners to maintain enough fuel inventory to keep supplies stable, and impose penalties on refiners who do not follow these requirements. Earlier this year, the state\u2019s Division of Petroleum Market Insight sent the Governor a letter outlining the role low inventories played in price spikes, but did not provide any storage volume requirement guidance. Newsom\u2019s proposal comes on the heels of a very comprehensive state transportation fuel assessment study by the CEC which took a deep dive into California\u2019s refined product markets and supply. The Transportation Fuels Assessment report, released earlier in August is a leading component of SB X1-2, the California Gas Price Gouging and Transparency Act which took effect in June 2023. The study came up with several possible solutions to address the state\u2019s continued gasoline demand drop as the use of ZEV (zero emission vehicles) increases, which, under the most radical scenario for gasoline production from the state\u2019s refineries, could leave the state with one or no refineries by 2044. The proposed solutions ranged from state-takeovers of refineries and securing Jones Act Tankers to storage options, including requiring refiners and terminals to maintain contingency reserves of gasoline in order to release minimum requirements to supply the market during supply shortages. A second storage-related option outlined in the report was to establish state-owned product reserves in the North and South Regions to allow rapid deployment of fuel when needed by leasing tankage at closed refineries to hold gasoline in reserve in the event of supply shortages. However, the report noted that current possibilities at two Northern California refineries recently converted to renewables production in Martinez and Rodeo plan to use their tankage for renewables storage. Refiners find California challenging and expensive Refiners operating in California universally agree that the state is a hard place for them to operate because the cost of business is high and the refining economics, marginal. \u201cWhen you think about our portfolio, the West Coast clearly is the highest cost region we operate in\u2026just by virtue of everything that goes on in the West Coast,\u201d said Lane Riggs, Valero\u2019s CEO on the company\u2019s Q2 results call on Aug. 1 One of the reasons California\u2019s gasoline supplies are limited is that the state is considered an \u201cisland\u201d in terms of importing gasoline from other parts of the US. California uses a cleaner burning gasoline grade called CARBOB, which is not widely available in other parts of the US, although that is changing. \u201cReferring to CARBOB as such a unique and difficult-to-produce fuel is a bit anachronistic,\u201d said Robert Auers, manager of refined fuels at RBN Energy and analyst with Refined Fuel Analytics in an Aug. 14 email. He said that new cleaner federal gasoline regulations like MSAT2 (Mobile Source Air Toxics), which restricts benzene concentrations, and Tier 3, which reduces sulfur, brings the CARBOB spec closer to other fuels including some RBOB and CBOB formulations with strict RVP requirements, including East Texas CBOB and Arizona\u2019s AZRBOB, although the CARBOB reporting and certification remains unique. However, Auers said that a California refinery \u201cthat now barely breaks even (or even loses money) during 'normal' conditions, but still makes money due to the occasional price spike may close if these price spikes are removed or mitigated.\u201d Auers said that the stock minimums for refineries and terminals are like to be ineffective. If the minimum is set too low it would have minimal impact on actual inventories and could be incredibly costly, leading to increased consumer costs and possibly accelerated refinery closures. \u201cAlso, refineries generally do not have significant excess terminal capacity. The capacity they have is necessary for their operations, so there\u2019s limited ability to effectively set minimum gasoline storage levels that provide an actual supply cushion at refineries without negatively impacting their operations,\u201d he said, adding that California\u2019s terminalling capacity is also tight. ","headline":"California\u2019s governor looks to regulate gasoline price shocks during the energy transition period","updatedDate":"2024-08-16T18:19:41.000"},{"Unnamed: 0":416,"body":" Orsted has ceased the development of its pioneering FlagshipONE eMethanol project under construction in northern Sweden, citing slow market progress and an inability to sign long-term offtake contracts, the company said Aug. 15. The company took a final investment decision on the project in 2022 after acquiring it from Liquid Wind and was targeting emerging demand in the marine fuel sector. \u201cWhile we were aware of the substantial uncertainties and risks associated with the development of a pioneering and immature liquid e-fuel project and market at the time of the FID, it was a strategic choice to take a leading position in shaping the industry,\u201d Orsted said in a results statement. FlagshipONE in Ornskoldsvik was to make green hydrogen from a 70-MW electrolyzer to produce up to 55,000 metric tons per year of e-methanol from 2025 using renewable energy and biogenic CO2 captured from the nearby biomass-fired Horneborgsverket heat and power plant. \u201cWe continue to believe in the long-term market for e-fuels, but the industrialization of the technology as well as the commercial development of the offtake market have progressed significantly slower than expected,\u201d it said. Demand issues The cancelation of FlagshipONE, previously described by the Danish renewable energy firm as \u201cthe largest eMethanol project under construction in Europe,\u201d came as most shipping firms remained reluctant in committing to long-term procurement contracts for methanol produced via sustainable means. While methanol has emerged as the most popular alternative population in newbuild orders over the past year, ship operators are not willing to swallow the high costs of sustainable methanol with limited scope of passing incremental expanse onto their customers, industry participants said. Platts bunker assessments for 0.5% sulfur fuel oil, the world\u2019s most common type of marine fuel, stood at $13.39\/Gj in Rotterdam on Aug. 14, compared with $18.01\/Gj for fossil-based methanol. Industry estimates suggest sustainable methanol would be at least two to five times more expensive. Platts is part of S&P Global Commodity Insights. Orsted said the FlagshipONE\u2019s business case had deteriorated since taking FID, \u201cdue to the inability to sign long-term offtake contracts at sustainable pricing and significantly higher project costs.\u201d The company has ceased execution of the project and is to de-prioritize work within the liquid e-fuel sector, it said. Orsted regional CEO for Europe Olivia Breese told Commodity Insights the company had advanced dialogues with several possible offtakers, but these did not progress to signing long-term contracts, despite market interest. \u201cWe believe that this reflects the immaturity of the regulatory environment for the decarbonization of industry,\u201d Breese said. While the EU has extended its Emissions Trading System to cover maritime transportation from 2024 and the International Maritime Organization could introduce a carbon levy from 2027, most shipping professionals said the measures would not be able to bridge the price gaps between fossil and synthetic marine fuels until the 2030s at least. Project viability Breese said that decarbonization projects across the board were challenged by higher energy, equipment and capex costs. \u201cThe industry is facing a significant cost-gap between e-fuels and fossil fuels,\u201d she said, noting other decarbonization options for many offtakers are seen as more competitive. \u201cThe e-fuels industry doesn\u2019t have firm commercial visibility on the offtake side.\u201d And although much of the needed EU regulation is in place, short- and medium-term regulatory requirements, such as sub-quotas for e-fuels and greenhouse gas reduction requirements, do not deliver a clear enough incentive, while national implementation and enforcement is not yet in place, Breese added. \u201cAs a result, timelines no longer match the most matured projects, where developers struggle to find offtakers willing to match the industry production costs for such commercial scale first-of-a-kind projects,\u201d she said. However, the company maintains a focus on renewable hydrogen, seeing it as a critical part of European industrial decarbonization, particularly in steel, chemicals and refineries. Longer term, it expects the liquid e-fuels market to develop further. The decision to scrap the project led to cancellation fees of DKK300 million ($44 million) and impairments of DKK1.5 billion, the company said. Orsted had previously secured EU funding for the project under the EU-Catalyst program and from the Swedish government, and the company was also expecting to receive a grant from Horizon Europe. However, Orsted told Commodity Insights that no funds had been exchanged at the time of its decision. Funding schemes were still \u201ctoo complex, ill-funded and not targeted enough\u201d to kick-start the first commercial e-fuels projects, Breese said. The company had previously given a carbon capture contract for the project to Carbon Clean to capture 70,000 t\/y of biogenic CO2. Carbon Clean didn't immediately respond to an email seeking comment on the contract. ","headline":"Orsted scraps Swedish FlagshipONE eMethanol project under development","updatedDate":"2024-08-15T15:24:26.000"},{"Unnamed: 0":417,"body":" Ship fuel sales at the UAE\u2019s Port of Fujairah climbed 1.7% in July from a seven-month low in June, with high sulfur fuel oil taking a bigger share of the volume, Fujairah Oil Industry Zone data published Aug. 15 showed. The total of 625,883 cu m was the highest since April, according to the FOIZ data. Compared with a year earlier, July volume dropped 5.7%. HSFO bunker sales rose 18% from June to a four-month high of 177,349 cm in July, and were 1.8% higher than a year earlier, the data showed. Sales of LSFO dropped 3.9% on the month to a five-month low of 411,366 cm in July and were 10% lower than a year earlier. LSFO volumes held a 66% share of the total sales in July, down from almost 70% a year earlier, while HSFO accounted for 28.3%, up from 24.4% in June. The Platts Fujairah-delivered low sulfur marine fuel ended July at $593 a metric ton, down from $624\/t at the end of June. Platts is part of S&P Global Commodity Insights. The Platts-assessed Fujairah-delivered high sulfur fuel ended July at $471\/t, down from $518\/t at the end of June. By Aug. 15, HSFO was $450\/t and LSFO was $590\/t. Port of Fujairah bunker sales Total LSFO Jul-24 Jun-24 MOM Jul-23 YOY MOM YOY Low sulfur fuel oil 180 CST 1,411.00 1,088.00 29.7% 1,272 10.9% -3.83% -10.45% Low sulfur fuel oil 380 CST 411,366.00 428,138.00 -3.9% 459,665 -10.5% Marine fuel oil 380CST 177,349.00 149,951.00 18.3% 174,227 1.8% 412,777.00 Marine gasoil 241.00 216.00 11.6% 1,387 -82.6% 429,226.00 460,937 Low sulfur marine gasoil 31,312.00 31,372.00 -0.2% 23,015 36.1% Lubricants 4,204.00 4,792.00 -12.3% 4,151 1.3% Total 625,883 615,557 1.7% 663,717 -5.7% Unit: cubic meters LSFO proportions 66.0% 69.7% 69.4% HSFO proportions 28.3% 24.4% 26.3% LSMGO proportions 5.0% 5.1% 3.5% Total sales (bbl) 3,936,687.49 3,871,738.87 4,174,656.30 Total sales (mt) 619,950.79 609,722.66 657,426.19 Source: Fujairah Oil Industry Zone ","headline":" July bunker sales rebound 1.7% from June's 7-month low","updatedDate":"2024-08-15T13:35:36.000"},{"Unnamed: 0":418,"body":" Chinese refineries' crude throughputs continued on a downtrend in July, falling 2.0% from June to a 21-month low of 13.96 million b\/d (59.06 million metric tons), data from the National Bureau of Statistics showed Aug. 15, reflecting weak domestic demand similar to the period of tight movement controls during the pandemic in late 2022. This is the first time runs have dropped below the 14 million b\/d mark since October 2022, when they were at 13.86 million b\/d in, the data showed. Year-on-year, July throughputs were down 6.1%, marking the steepest decline since the 6.5% drop in August 2022. The NBS releases data in metric tons, which S&P Global Commodity Insights converts to barrels using a conversion factor of 7.33. In metric tons, the country's throughput in July edged 1.3% higher from 58.32 MMt in June. The fourth straight monthly fall in daily average runs was broadly in line with macroeconomic indicators. Industrial production growth narrowed to 5.1% in July, continuing to slow from the 6.7% rate seen in April. The Manufacturing PMI, at 49.4 in July, remained in contraction, extending the downtrend started in April, NBS data showed. Meanwhile, S&P Global Commodity Insights analysts estimate small independent refineries\u2019 average refining margin flipped to negative, at about minus 33 cents\/b in July, from plus $1.85\/b in June, according to a monthly report published July 31. Data from local energy information provider OilChem showed that independent refineries in Shandong operated at a utilization rate of 49.1% in July, down by about two percentage points from June. Shandong\u2019s independent refineries are swing players in China\u2019s refining sector, with their level of activity directly reflecting the country\u2019s overall oil demand. Throughputs lower than expected Crude throughputs in July were lower than expected, with market watchers anticipating an increase in runs as a number of state-owned and privately owned mega plants lifted utilization following the end of maintenance. Commodity Insights data collected from 53 leading refineries, both state-owned and private, showed their combined throughput reached 10.23 million b\/d in July with an 83% utilization rate, rising from 9.94 million b\/d in June with an 80.6% average run rate. \u201cI penciled the throughput at about 14.3 million b\/d in July, the NBS number is surprisingly low,\u201d a Beijing-based analyst said. The July figures took refinery throughputs for the first seven months of the year to an average of 14.42 million b\/d (419.15 MMt in total) of crude, down 1.7% on the year. Looking forward, \u201cWe anticipate a continuous year-on-year decrease of approximately 300,000 b\/d in Q3 2024, driven by various headwinds, including weak profit margins, higher-than-usual maintenance activities, and persistent bearish market sentiment on domestic demand,\u201d said Mengbi Yao, a senior research analyst with Commodity Insights. But August runs are likely to rebound month-on-month due to seasonal demand, she added. September-October is peak demand season in China, with autumn bringing elevated harvesting and fishing activity, while typically the weather is ideal for construction work and travel rises with the Middle-Autumn Festival and National Day holidays. Typhoon Gaemi dents crude output In the upstream sector, China's crude production averaged 4.23 million b\/d (17.90 MMt) in July, down from 4.39 million b\/d in June, which was the second highest volume on record, NBS data showed. Despite the month-on-month fall, output was up 3.4% year on year and was the highest for the month of July since the 4.28 million b\/d seen in 2015. July is a typical typhoon season. The Super Typhoon Gaemi, which made landfall in southeast China on July 25 and moved westward and northward, brought record-breaking daily precipitation in Liaoning, Hunan and Jiangxi provinces, according to China Meteorological Administration. Heavy rain and floods forced the closure of some wells at PetroChina's 197,000 b\/d Liaohe oil field in Liaoning province until early August, according to the operator\u2019s official WeChat channel. For the January-July period, China's crude production was up 1.6% on the year at 4.30 million b\/d (124.96 MMt), NBS data showed, driven by state-owned oil giants' efforts to boost domestic supplies. China's crude output and throughput (MMt) July '24 July '23 Change June '24 Change Crude output 17.90 17.31 3.4% 17.95 -0.3% Crude throughput 59.06 62.90 -6.1% 58.32 1.3% Jan-July '24 Jan-July '23 Change Crude output 124.96 122.39 2.1% Crude throughput 419.15 424.24 -1.2% Source: National Bureau of Statistics ","headline":" July crude throughput falls to 21-month low of 13.96 mil b\/d","updatedDate":"2024-08-15T11:34:38.000"},{"Unnamed: 0":419,"body":null,"headline":"Petronas sets September Malaysian crude OSP at Dated Brent plus $7.90\/b","updatedDate":"2024-08-15T06:21:36.000"},{"Unnamed: 0":420,"body":" Iraq\u2019s ambitions to expand its refining capacity to capture more exports of higher-valued refined products is closer to being achieved with two more refineries in the works even with existing plants operating below capacity. Refining capacity at OPEC\u2019s second biggest crude producer, excluding all but one refinery in the Kurdish region, has reached 1.215 million b\/d, according to oil ministry data provided exclusively to S&P Global Commodity Insights. The two refineries in the works consist of the Fao Investment refinery with China to add 300,000 b\/d of capacity while another one in Kirkuk to add 150,000 b\/d was approved by the council of ministers on May 7. The Kurdish refinery included in the total is the 40,000 b\/d Bazian site. Inside the Kurdish region, local authorities have ordered dozens of unlicensed topping plants to close and the licensed refineries to adopt environmental protection requirements or face shutdown. A major step ahead was set in motion in July when Iraq completed the upgrade of a gasoil pipeline from the Shuaiba projects depot next to the Basrah refinery to the southern port of Khor Al-Zubair to resume exports of gasoil, signaling the first exports of the product since 2003. That was on top of the new 70,000 b\/d crude distillation unit at the Basrah refinery started in December 2023 and the 150,000 b\/d Baiji North refinery completed in February. \"It is expected that the ramp-up of these new capacities will be a gradual process,\" said Rahul Chatterjee, a principal research analyst at Commodity Insights. After the Kirkuk refinery was approved, BP announced on Aug. 1 that it had signed a memorandum of understanding with Iraq\u2019s government on its potential return to the Kirkuk oil project in the north of the country. The MOU includes the Baba and Avanah domes and three adjacent fields operated by Iraq\u2019s North Oil Co. NOC currently produces about 380,000 b\/d of crude, which is just sufficient to supply refineries in northern Iraq, particularly since the reopening of the 150,000 b\/d North refinery in Baiji in February. Light sour Kirkuk crude has an API gravity of 34.2 and average sulfur content of 2.24%, according to the Platts Periodic Table of Crude by Commodity Insights. The Platts-assessed Kirkuk FOB Ceyhan was $80.01\/b on Aug. 14, according to Commodity Insights data. In May, Iraq's oil minister Hayan Abdul Ghani said the goal of the refinery expansions is to become self-sufficient in domestic products demand and possibly export products. Iraq has declared self-sufficiency in gasoil since the start of this year and reduced gasoline imports by 50% by March from the end of the 2023, ministry data showed. Exports of refined exports rose to a record 701,000 b\/d in May, with shipments so far this year more than doubling from last year to destinations including South Korea, Malaysia, Saudi Arabia, Oman, Spain, Bahrain, Thailand, Vietnam and Sri Lanka, according to Kpler data. Any more expansion of Iraq's refining is considered unlikely with existing plants producing below capacity, averaging 980,000 b\/d, or about 80% of capacity, the oil ministry data showed. Fuel oils have been Iraq\u2019s largest export product, with other shipments including naphtha, bitumen\/asphalt, gasoil and gasoline, Kpler data showed. Iraq mostly relies on natural gas to generate electricity from the country\u2019s power plants and has received US waivers to import Iranian gas and electricity without violating sanctions on Iran\u2019s energy industry reimposed by the US administration of former President Donald Trump. ","headline":"Iraq\u2019s ambition to become refinery powerhouse moves closer to fruition","updatedDate":"2024-08-15T04:36:05.000"},{"Unnamed: 0":421,"body":null,"headline":"China's July crude throughput falls to 13.96 mil b\/d, a 21-month low: NBS","updatedDate":"2024-08-15T02:59:44.000"},{"Unnamed: 0":422,"body":null,"headline":"China's July crude output down 3.5% to 4.23 mil b\/d on month amid typhoon: NBS","updatedDate":"2024-08-15T02:59:43.000"},{"Unnamed: 0":423,"body":" A fire on a crude oil pipeline connecting Libyan oilfields to the Es Sider terminal has disrupted oil flows as operator Waha Oil has worked to restore operations through the impacted supply link. In a statement Aug. 14, Waha Oil said a fire broke out on its Gazout - Es Sider pipeline link Aug. 13, and was extinguished overnight after breaking out around 30 km from the port, according to sources. Oil and shipping sources said that Waha Oil had curbed crude flows through the pipeline as it conducts maintenance on the impacted area, with work expected to last several days. The pipeline link is the larger, more modern of Waha Oil's two crude links between its oilfields and the export terminal, increasing its reliance on its older Dahra pipeline as an outlet for its sweet Es Sider crude while works are underway. In 2023, Waha Oil produced 290,000 b\/d of crude oil from its 28 wells, while the company had eyed ambitious expansions in 2024. Some 264,500 b\/d Es Sider crude was dispatched from the terminal in July, down from the 2023 average of 277,300 b\/d, according to S&P Global Commodities at Sea . A shipbroker said two cargoes due to load at Es Sider in the coming weeks -- the Aegean Harmony and Sea Panther -- could face delays of several days while maintenance is underway, while CAS data was yet to show any tankers leaving the port since Aug. 12. Some 11 crude cargoes had left Es Sider over Aug. 1-13, indicating a likely increase in exports for the full-month relative to July volumes, when 13 cargoes loaded at the terminal. Waha Oil was not available for comment. Libyan production woes Disrupted flows from the Es Sider terminal would add an additional source of strain to Libyan crude flows following the shutdown of the 300,000 b\/d Sharara oilfield Aug. 5 that caused NOC to declare force majeure Aug. 7. Extended shut-ins and disrupted pipeline flows could hinder Libya's ambitions to restore its oil output to the 1.6 million b\/d it was producing in 2011, before Libyan National Army blockades in 2022 reduced capacity. The country has gradually restored its capacity since 2022, and in June pumped 1.16 million b\/d, according to the latest Platts OPEC Survey from S&P Global Commodity Insights. Libya's Sharara and Es Sider crudes are a popular feedstock for European refiners due to high middle distillate and gasoline yields, meaning prolonged supply disruptions could spell tightness for the light, sweet market in the Mediterranean. Unlike previous incidents of Sharara shut-ins , ample crude availability tempered the market reaction to news of the Aug. 7 force majeure, with traders pointing to healthy supplies from West Africa and other outlets. Platts, part of Commodity Insights, assessed Es Sider FOB Libya at $80.89\/b on Aug. 13, down 0.2% on the day but up from $76.23\/b the previous week. The differential for Es Sider crude has been steady at a 35 cents\/b discount to Dated Brent in the week started Aug. 12. ","headline":"Crude flows to Libya's Es Sider impacted by pipeline fire","updatedDate":"2024-08-14T16:47:35.000"},{"Unnamed: 0":424,"body":" The world is seeing a major deceleration in oil demand growth led by China, with inventories set to rise next year even if OPEC+ were to postpone its plans to ease output cuts, the International Energy Agency said Aug. 13. The IEA, in its monthly oil market report, reiterated the impact of China's slowdown, with the US and particularly its service sector driving demand growth. It highlighted preliminary data for July showing China's crude oil imports fell to their lowest since September 2022. A current supply deficit, typical for the northern hemisphere summer, is set to evaporate in Q4 2024, according to the IEA's projections. \"In June, Chinese oil demand contracted for a third consecutive month, driven by a slump in industrial inputs... By contrast, demand in advanced economies, especially for US gasoline, has shown signs of strength in recent months. The US economy, where one third of global gasoline is consumed, has outperformed peers, with a resilient service sector buttressing miles driven,\" the IEA said. On the implications for oil producers, it said, \"Despite the marked slowdown in Chinese oil demand growth, OPEC+ has yet to call time on its plan to gradually unwind voluntary production cuts starting in the fourth quarter [of 2024]... Our current balances suggest that even if those cuts remain in place, global inventories could build by an average [of] 860,000 b\/d next year as non-OPEC+ supply increases of around 1.5 million b\/d in 2024 and again in 2025 more than cover expected demand growth.\" The IEA trimmed its estimate of the \"call\" or demand for OPEC+ crude by 100,000 b\/d for 2025, to 41 million b\/d. On oil inventories, the IEA said global \"observed\" inventories had fallen by 26.2 million barrels in June, following four consecutive months of increases. Oil inventories \"on water\" in tankers declined for a third consecutive month, by 24.2 million barrels, it said. On the supply side, the report included a reduction in estimated non-OPEC oil supply growth in 2024 to 900,000 b\/d from 1.1 million b\/d in the previous version, likely reflecting the complexity of Kazakhstan's Chevron-led Tengiz field expansion underway this year as well as North Sea maintenance. Americas growth In terms of supply outside the OPEC+ group, the report increased the growth estimate for 2025 to 1.6 million b\/d from 1.5 million b\/d. \"The Americas quartet of the United States, Guyana, Canada and Brazil account for three-quarters, or roughly 1.1 million b\/d, of non-OPEC+ supply gains in each of the two years 2024 and 2025,\" it said. The IEA's downbeat views on oil demand growth followed a more bearish turn in OPEC's own monthly oil market report, published Aug. 12. OPEC, in its report, said the \"call\" on the OPEC+ alliance's crude would be 43.0 million b\/d in 2024 and 43.6 million b\/d in 2025, down 100,000 b\/d and 300,000 b\/d, respectively, for the two years compared with its previous estimate. It now estimates global demand growth at 2.1 million b\/d in 2024 and 1.8 million b\/d in 2025. Analysts at S&P Global Commodity Insights forecast global oil demand to grow by 1.6 million b\/d in 2024 and 1.3 million b\/d in 2025. ","headline":"Oil demand seeing 'major deceleration' led by China: IEA","updatedDate":"2024-08-14T12:44:07.000"},{"Unnamed: 0":425,"body":" OPEC sees weaker demand for OPEC+ crude in 2024 and 2025 than it did a month ago, with estimates of global oil consumption revised down and supply from non-OPEC+ countries ticked up. Striking a bearish tone in its closely watched monthly oil market report Aug. 12, the producers group said the \u201ccall\u201d on the OPEC+ alliance\u2019s crude -- the volume of oil it must produce to balance the market -- would be 43.0 million b\/d in 2024 and 43.6 million b\/d in 2025. That is down 100,000 b\/d and 300,000 b\/d respectively from July\u2019s forecast and marks the second successive monthly reduction. OPEC noted, however, that July output by the OPEC+ alliance -- which includes its Russia-led allies -- averaged 40.91 million b\/d, according to seven secondary sources including the Platts OPEC+ Survey from S&P Global Commodity Insights. This means it would have a strong hand to influence the market if its expectation for the call on OPEC+ crude comes to pass. The report nevertheless struck a less optimistic tone than in recent months, with downward revisions to forecasts for both world oil demand and year-on-year demand growth. \u201cMarket sentiment was further affected by uncertainty surrounding central bank monetary policies, particularly prospects for prolonged high interest rates in the US as a means of addressing ongoing inflation. Additionally, concerns about China's economic performance and demand growth, coupled with a slower-than-expected onset of the driving season, contributed to the downward pressure on prices,\u201d the report said. OPEC\u2019s expectation for 2024 world oil demand had remained unchanged at 104.46 million b\/d since March, but the group has now dropped its forecast by 140,000 b\/d to 104.32 million b\/d, leaving its expectation for year-on-year demand growth in 2024 at 2.11 million b\/d, down from 2.25 million b\/d. \"This slight revision reflects actual data received for Q1 and in some cases Q2, as well as softening expectations for China\u2019s oil demand growth in 2024,\" the report noted. Its long-held view of oil demand and demand growth in 2025 has also been revised down by 200,000 b\/d and 70,000 b\/d respectively to 106.11 million b\/d and 1.78 million b\/d respectively, although they remain more bullish than forecasts by Commodity Insights analysts. The only key indicator nudged up in August is expectations of non-OPEC+ supply, which has been increased by 20,000 b\/d for both 2024 and 2025. OPEC sees the US, Brazil, Canada and Norway driving output growth. Sluggish demand A weaker demand outlook comes as OPEC+ ministers are fighting to shore up global oil markets, after seeing prices weaken in recent weeks. Platts Dated Brent fell from almost $90\/b in early July to as low as $76.27\/b on Aug. 6, but then rallied to $81.62\/b on Aug. 9. Platts is part of Commodity Insights. Analysts have attributed the price dip to sluggish Chinese demand, high interest rates in major economies and impressive output from non-OPEC members, particularly in the Americas. Meanwhile, elevated Middle East tensions stemming from the Israel-Hamas war and 5.8 million b\/d of overlapping supply cuts by the OPEC+ alliance have put a floor under prices. Those efforts could still be jeopardized by poor quota compliance, with Iraq, Kazakhstan and Russia continuing to overproduce their quotas in July, according to the secondary sources, despite the trio submitting compensation plans to OPEC on July 24. On Aug. 9, Russia\u2019s energy ministry said it remained committed to its OPEC+ compensation plan despite overproducing its quota by 67,000 b\/d in July. Secondary sources saw Iraqi production rising 57,000 b\/d in July to 4.251 million b\/d, according to the August report, while Russian and Kazakh output fell by 26,000 b\/d and 34,000 b\/d respectively. On Aug. 1, at the last meeting of the Joint Ministerial Monitoring Committee, which oversees production cut implementation, ministers agreed to proceed with plans to slowly unwind 2.2 million b\/d of voluntary cuts -- undertaken by a core group -- from October, subject to market conditions. Analysts said such action could weaken oil prices further. An additional 3.6 million b\/d of group-wide cuts are currently in place until the end of 2025. The JMMC will convene again Oct. 2, followed by the OPEC+ alliance\u2019s next full ministerial meeting scheduled for Dec. 1 in Vienna. Rounding off its August report, OPEC estimated total OECD commercial oil and product stocks -- which are subject to a two-month delay -- were down by around 14.1 million barrels on the month in June to 2.831 billion barrels. It estimates that crude stocks fell 17.3 million barrels month-on-month to 1.366 billion barrels, and products stocks rose by 3.1 million barrels to 1.467 billion barrels in June. ","headline":"'Call' on OPEC+ crude in 2024, 2025 trimmed again in bearish update","updatedDate":"2024-08-14T11:46:44.000"},{"Unnamed: 0":426,"body":" South Korea's electricity demand has increased to a new all-time high this week as the country has been suffering from the record-breaking heat wave, but the government ruled out any power supply disruptions on nuclear reactors and LNG-fired power plants. \u201cThe government would make all possible measures to meet the power demand such as higher operation rates of nuclear reactors and LNG-fired power plants,\u201d an official at the Ministry of Trade, Industry and Energy said Aug. 14. South Korea\u2019s peak power demand came to 94.6 GW at 6 pm Aug. 13, over the previous record of 94.5 GW set on Dec. 23, 2022 when the country was hit by a cold spell, according to the ministry. The peak power demand also beat the previous summer season record of 93.8 GW set Aug. 5 this year and 93.6 GW set Aug. 7, 2023. Despite the record demand, the country was able to supply electricity with no disruptions by providing 104.8 GW, helped by increased power production from nuclear reactors and LNG-fired power plants, the ministry official said. \u201cThe country maintained electricity reserves of 10.2 GW with a power reserve ratio of 10.7%,\u201d the ministry official said, noting that the state-run power operator should have a reserve ratio of 10% or more in order to maintain a stable power supply and prepare for emergencies. \u201cIf the power reserve ratio declines, several LNG-fired power plants that are currently under test runs will start commercial production earlier than scheduled,\u201d the official said. Six nuclear reactors with a combined capacity of 5.05 GW are currently offline for maintenance, accounting for 19.4% of the country's overall capacity of 26.05 GW across 26 nuclear reactors, compared with 13.6% from the shutdown of four reactors a year earlier, according to state-owned nuclear power operator Korea Hydro & Nuclear Power Co. The record-high power demand came as the country has been gripped by sweltering weather, with the average national temperature from June through August being well higher than usual. The Seoul metropolitan area, home to half of the country\u2019s total population of 51.8 million, has experienced its 24th tropical night, marking the second-longest streak since 1907, which has boosted power demand even overnight. A tropical night refers to a phenomenon when temperatures stay above 25 degrees Celsius, from 6 pm to 9 am the following day, according to the Korea Meteorological Administration. The weather agency predicted that the ongoing heat wave may continue over the next weeks, potentially setting a new record for power demand. ","headline":"South Korea\u2019s power demand increases to new record high amid heat wave","updatedDate":"2024-08-14T09:32:03.000"},{"Unnamed: 0":427,"body":" Stockpiles of oil products at the UAE\u2019s Port of Fujairah declined 1.7% in the week ended Aug. 12 to a 10-month low, according to Fujairah Oil Industry Zone data. The total fell to 16.458 million barrels, the lowest since Sept. 25, 2023, FOIZ data published Aug. 14 showed. Stockpiles have dropped 5.1% since the end of 2023. Heavy distillates used for power generation and as ship fuel dropped 8.7% to 8.510 million barrels, the lowest since Feb. 19. Middle distillates such as jet fuel and diesel rose 6.5% to 1.792 million barrels, rebounding from a four-month low. Light distillates such as gasoline and naphtha gained 6.5% to a two-week high of 6.154 million barrels. Demand for high sulfur fuel oil contributed to the decline in heavy distillates, with demand for low sulfur fuel oil has lagged, bunker suppliers told S&P Global Commodity Insights. \u201cHSFO [barging schedules] might be a bit tighter\u201d on the week, a Fujairah trader said. More HSFO supplies are being offered starting around the week of Aug. 19, indicating minimal barge availabilities for the time being, the trader said. Shipowners are seeking \u201csizable\u201d supplies of HSFO but heavy distillates may still increase in the next few weeks as peak demand from the power sector for air conditioning has passed, traders said. The Platts-assessed Fujairah-delivered 380 CST HSFO bunker premium over the FO 380 CST 3.5% FOB Arab Gulf slipped to average $19.96\/metric ton Aug. 1-13 from $23.9\/t in July, Commodity Insights data showed. \u201cThere\u2019s no shortage of oil in the market,\u201d a Fujairah-based bunker supplier said, referring to LSFO. The Platts-assessed Fujairah-delivered marine fuel 0.5% sulfur bunker premium over benchmark FOB Singapore marine fuel 0.5%S cargo averaged $11.85\/t Aug. 1-13, down from $12.13\/t for all of July, according to Commodity Insights data. Oil product exports from Fujairah totaled 2.39 million barrels in the week started Aug. 5, down from 4.1 million barrels a week earlier, according to Kpler shipping data. Fuel oils dominated the shipments to destination countries Malaysia, Mozambique and Comoros Islands, the data showed. Naphtha was also exported in the latest week, although the destination country was still unknown, Kpler data showed. So far since the end of 2023, stocks of light distillates have climbed 31%, heavy distillates have dropped 16% and middle distillates have dropped 28%. ","headline":" Oil product stocks drop to 10-month low","updatedDate":"2024-08-14T07:00:05.000"},{"Unnamed: 0":428,"body":" The Indian government has approved a proposal by state-run Oil and Natural Gas Corp. for additional investments in order to boost its stake in ONGC Petro-additions Limited (OPaL), a move that will help the state-run upstream producer to have a bigger footprint in the petrochemicals segment. The decision comes at a time when state-run oil companies are looking to expand their petrochemicals footprint in the hope that business models remain profitable in the future even if energy transition and the growth of electric vehicles take a toll on consumption of transport fuels, such as gasoline and diesel. ONGC will invest an additional Rupee 183.65 billion ($2.2 billion) resulting in an increase in ONGC\u2019s stake in OPaL from 49.36% to 95.69%, ONGC said in a recent statement. \"This significant move paves the way for capital restructuring leading to the operational and financial sustainability of OPaL. The decision aligns with ONGC\u2019s strategic vision to become an integrated global energy major by increasing its presence across the downstream and petrochemical value chain as well,\" it added. OPaL, situated at Dahej in the western state of Gujarat, is a petrochemical complex having the largest standalone dual feed cracker in Southeast Asia. Commissioned in 2017, OPaL has a capacity to produce 1.5 million mt\/year of polymers and 500,000 mt\/year of chemicals. It has a 12% market share in India's polymer segment. \"The said government approval also assures a sustained supply of gaseous feed to OPaL by ONGC from its new gas from nomination fields at a premium of up to 20% over administered price mechanism,\" ONGC added. ONGC has been looking at petrochemical projects as part of its long-term growth strategy. ONGC chairman and CEO Arun Kumar Singh told S&P Global Commodity Insights earlier that the state-run firm was looking to set up two crude-to-chemicals projects in the country -- one in the northern region and another in the south. New projects ONGC contributes around 74% of India's crude oil and around 63% of its natural gas production. The company is deepening its technical and operational expertise in deepwater E&P and is increasingly assessing the prospect of high pressure-high temperature and ultra-deepwater plays in India. In the April-June quarter or Q1, ONGC posted a 1.4% year-on-year fall in crude production to 5.2 million mt, the company said in a statement. It's natural gas output fell 4.1% on the year to 5 Bcm in Q1. Analysts attributed the decline in the output mainly to falling production from old and maturing fields and to non-realization of production ramp up targets at the KG basin. According to the company officials, ONGC hopes to witness growth in its overall oil and gas output in the financial year 2024-25 (April-March) on the back on incremental production from new projects in the subsequent quarters, which would reverse the trend seen in previous quarters. It would continue with its strategy to advance new well drilling activities to raise overall production for the year. \"The commencement of production from new projects, particularly from KG 98\/2 development in Krishna Godavari basin, will help the NOC to boost near-term production volumes,\" according to Commodity Insights. \"Sanctioned projects such as North Karanpura, and Daman Upside Development Project and unsanctioned projects such as GS-29 & DWN-F1, Cluster I and R-Series & Ratna Revival, will be key contributors to production volumes. However, any delays in bringing these projects onstream will accelerate the decline in ONGC's domestic production,\" it added. Assuming the economy grows annually at a rate of 6%-7% in the coming years, ONGC expects annual primary energy growth to be about 4%-5%, while new energy would take the remaining 1%-2% share. Overseas ambitions The company's wholly-owned subsidiary and overseas arm, ONGC Videsh Ltd, owns participating interests in 32 oil and gas assets across 15 countries. Combined output from its overseas assets is currently around 10.5 million mt of oil equivalent. ONGC Videsh has also agreed to buy small additional stakes in Azerbaijan's ACG crude complex and BTC pipeline from Equinor for up to $60 million as the Norwegian national company plans to exit the Caspian country. It has recently signed an agreement with Equinor to buy an additional 0.615% stake in the Azeri Chirag Deepwater Gunashli oil complex in the Caspian Sea, as well as an additional 0.737% stake in the Baku-Tbilisi-Ceyhan pipeline, the country's main artery for crude exports to Turkey's Mediterranean coast. The purchases add to an existing ONGC 2.31% stake in ACG and a 2.36% stake in BTC. \"This acquisition is consistent with its strategic objective of energy security of the nation by adding high-quality international assets with equity oil to its existing portfolio,\" ONGC said.\" Russia accounts for 60% of total international production and is OVL\u2019s largest international holding, comprising 18 onshore blocks. OVL has two major assets in the country -- a 20% stake in the Sakhalin LLC-operated Sakhalin I, and a 26% stake in the PJSC Rosneft Oil Co.-led consortium, developing the Vankor group of fields, according to Commodity Insights. ","headline":"India's ONGC eyes new investments in diversification push, boost petrochemicals footprint","updatedDate":"2024-08-14T04:00:13.000"},{"Unnamed: 0":429,"body":null,"headline":"IEA cuts estimated non-OPEC oil supply growth estimate for 2024","updatedDate":"2024-08-13T08:00:34.000"},{"Unnamed: 0":430,"body":null,"headline":"Oil demand seeing \u201cmajor deceleration\u201d in 2024 led by China: IEA","updatedDate":"2024-08-13T08:00:32.000"},{"Unnamed: 0":431,"body":null,"headline":"IEA trims estimated \u201ccall\u201d for OPEC+ crude in 2024 and 2025","updatedDate":"2024-08-13T08:00:32.000"},{"Unnamed: 0":432,"body":" ExxonMobil's Joliet refinery in Channahon, Illinois, has safely restarted after the plant was abruptly shut July 15 by a tornado that destroyed local power infrastructure. \"We\u2019ve safely restarted our refinery and are grateful to our workforce and community for all their hard work to get us back online,\" said ExxonMobil spokesperson Lauren Kight in an email Aug. 12. The refinery was forced to shut after the tornado, which caused supply issues for gasoline and diesel in the Chicago market. Both gasoline and diesel prices spiked on the news. Units affected by the storm include a crude distillation unit, a gasoline-making fluid catalytic cracking unit, and a catalytic reformer. Prices dropped Aug. 1, however, after the US Environmental Protection Agency issued an emergency waiver of summer gasoline specifications due to volatility to address supply issues in four Midwestern states. The waiver took effect Aug. 1 and is valid through Aug. 21, but the EPA could extend the waiver through Sept. 15, which is when the gasoline specification switches to a transitional winter grade. Gasoline prices in both Midwest markets fell after news surfaced of the refinery restart. In Oklahoma, Platts, part of S&P Global Commodity Insights, assessed the Group-3 V grade differential down 6.25 cents to NYMEX September RBOB futures minus 6.50 cent\/gal, while the A grade fell in tandem to close at futures plus 17.75 cents\/gal. Platts also assessed the Chicago Generics CBOB differential down 3.25 cents to close at futures minus 13.50 cents\/gal, while the Buckeye Complex CBOB differential also fell to close at futures minus 9.25 cents\/gal, down 3.25 cents from last week's close. The Chicago Generics RBOB differential fell 2.75 cents on the day to futures plus 5 cents\/gal, while the BCX RBOB also fell 2.75 cents to close at futures minus 5 cents\/gal. ","headline":" ExxonMobil says Joliet refinery restarted; Midwest gasoline prices fall","updatedDate":"2024-08-12T21:24:17.000"},{"Unnamed: 0":433,"body":" NYMEX WTI rallied more than 4% to above $80\/b on Aug. 12 as the US ramped up its Middle East strike forces, stoking concerns of a near-term escalation in the Middle East. NYMEX September WTI settled $3.22 higher at $80.06\/b and ICE October Brent rallied $2.64 to $82.30\/b. US Defense Secretary Lloyd Austin ordered the deployment of a guided missile submarine to the Middle East, as well as the USS Abraham Lincoln carrier strike group to accelerate its deployment to the region, the Pentagon said in an Aug. 11 statement, amid concerns that Iran is preparing to launch a significant strike against Israel in coming days. \u201cA rise in geopolitical risks appears imminent, with military analysts pointing to Tisha B'av on August 13th as a potential date for Iran's retaliatory strike, corroborated by reports that intelligence officials expect an imminent attack,\u201d TD Securities Senior Commodity Strategist Daniel Ghali said. The rally pushed prompt-dated NYMEX WTI to the highest level since July 19, while front-month ICE Brent was last higher on July 25. \"A fair amount of uncertainty over Iran's response to last month's assassination of a top leader of Hamas in Tehran has been supportive of the risk premium for crude oil,\" ING's Warren Patterson and Ewa Manthey said. NYMEX September RBOB settled up 5.26 cents at $2.4429\/gal and September ULSD climbed 6.68 cents to $2.4065\/gal. Geopolitical risk concerns supported crude prices despite OPEC striking a more bearish tone in its monthly oil market report released Aug. 12. The producers group said the \"call\" on the OPEC+ alliance's crude -- the volume of oil it must produce to balance the market -- would be 43.0 million b\/d in 2024 and 43.6 million b\/d in 2025. That is down 100,000 b\/d and 300,000 b\/d, respectively, from July's forecast. Meanwhile, US-based refiners are reducing their run rates amid lower refining margins, raising concerns about a potential oversupply of crude. \"Marathon Petroleum plans to operate its 13 plants at an average of 90% capacity in [the third quarter],\" analysts at ANZ said. \"This follows similar announcements from PBF Energy, Phillips 66 and Valero Energy. Together, these refiners account for 40% of US refining capacity.\" Forward demand concerns have been reflected in a decline of net long bets gasoline. Positioning data from the US Commodity Futures Trading Commission shows money managers' net long bets on gasoline at 7,624 lots in the week ended Aug. 9, the lowest total volume since July 2017. ","headline":" US crude jumps 4% as market eyes potential near-term escalation in Middle East","updatedDate":"2024-08-12T20:05:58.000"},{"Unnamed: 0":434,"body":" Kazakhstan\u2019s challenging Kashagan oil project in the Caspian Sea is dogged by uncertainty over planned production increases and particularly gas handling capacity, as authorities fear targets may be missed, relations with partners grow strained, and the possible outlines of a way forward emerge. Kashagan, developed by a consortium of global majors plus China's CNPC and Japan's Inpex as well as KazMunaiGaz, is estimated at to be at 9 billion-13 billion barrels of reserves. It has long been viewed as one of the world\u2019s most complex oil projects; investment exceeded $50 billion by the time stable production was achieved in 2016. Tensions over what is Kazakhstan\u2019s second-highest producing oil field are reflected in a national development plan signed July 30 by President Kassym-Jomart Tokayev, which stresses the \u201cparamount\u201d importance of increasing Kashagan output to 700,000 b\/d by 2030 -- up from around 400,000 b\/d -- and warns of problems with a lack of gas processing facilities. The document notes oil and gas account for 50% of national exports, the largest part being the 1.5 million b\/d CPC Blend crude grade, to which Kashagan is the second-highest contributor behind the Chevron-led Tengiz project. The industry has long wrestled with how to handle the sulfurous gas associated with production from Kazakhstan\u2019s three largest oil fields. The third-highest producing field, Karachaganak, reinjected 12.7 Bcm of gas in 2023, or 57% of the gas it produced, and relies on gas processing facilities in neighbouring Russia; oil output from the field was 230,000 b\/d. A particularly fraught issue is how much gas reinjection is needed to maintain reservoir pressure over the life of projects, and how much to direct to a domestic market hungry for gas and still dependent on coal. Adding gas injection facilities at the offshore artificial islands built for Kashagan is pricey, but without a solution there can be no oil output increase. Increasing pressure and uncertainty Plans recently outlined by state gas company QazaqGaz for an increase in gas processing capacity on the Caspian seashore to handle Kashagan gas and send it to market reflect these concerns, but risk adding to confusion. QazaqGaz is not a member of the consortium that operates Kashagan, the North Caspian Operating Company, unlike its oil counterpart KazMunaiGaz, and the views of NCOC are unclear. In February, QazaqGaz signed a contract with Qatari contractor UCC Holding during a visit to the country by Tokayev for the construction of two new gas processing plants of 1 Bcm\/year and 2.5 Bcm\/year, respectively, with the first to be completed in 2026 and the second in 2028-29. Tokayev\u2019s office confirmed these were intended for Kashagan gas. Sanzhar Zharkeshov, the CEO of QazaqGaz, asserted on July 16 that each additional 1 Bcm\/year of gas processing capacity would increase Kashagan oil output by 25,000 b\/d, in a seemingly automatic process. But there has been no public indication of support by NCOC for the plans, or approval for any upstream investment that might be needed. Some analysts say the need to reinject gas into the reservoir is increasing, not diminishing, as oil reserves are tapped -- although some of the NCOC scenarios foresee the field producing into the next century. NCOC is involved in one gas processing plant under construction, with a capacity of 1 Bcm\/year; it was approved in 2020, as part of the initial Kashagan development and should enable a 25,000 b\/d increase in oil output to around 430,000 b\/d from mid-2026. But NCOC confirmed that plant is not connected to the new plants envisioned by QazaqGaz, and no decision has been taken on Kashagan\u2019s planned Phase 2 expansion. The Phase 2 plans outlined in the annual report of KazMunaiGaz do include adding gas processing plants, but at 2.5 Bcm\/yr and 6 Bcm\/year these do not correspond with the agreement with UCC Holding. QazaqGaz did not respond to a request for comment. Analysts at S&P Global Commodity Insights say that a modified expansion plan that could raise crude output to 500,000 b\/d under a \u201cPhase 2A\u201d to be completed in 2026 is under discussion, with a \"Phase 2B\" looking to achieve 710,000 b\/d in 2032, but this has yet to be agreed. When asked if it was involved in the agreements with UCC Holding, NCOC answered only indirectly. Phase 2 \u201cof the potential Kashagan full field development is split into sub-phases. Successful implementation of these sub-phases could potentially increase the Kashagan oil production and is subject to a number of technical and non-technical considerations,\u201d NCOC said to Commodity Insights. \u201cCurrently, the shareholders and operator of the North Caspian Project continue to discuss plans for further development, with the government of the Republic of Kazakhstan and other stakeholders,\u201d they added. Payment stand-off Lurking in the background is a dispute over the field\u2019s overall development costs, with the government reportedly claiming more than $150 billion from the consortium in costs it does not agree with, and the matter to be resolved at arbitration. TotalEnergies CEO Patrick Pouyanne pledged in April 2023 to \u201cfight\u201d the claims, saying the partners, which also include ExxonMobil, Shell and Italy\u2019s Eni, were \u201creally united.\" Eni said in April 2024 that neither the basis of the claim or the amount were \u201creasonably substantiated or credible.\u201d Commodity Insights\u2019 Eurasian Energy Research team said recently: \u201cKazakhstan once again is applying pressure on its most important upstream foreign investors. The country may even be pushing for entirely new arrangements that would give the government greater control over the assets.\u201d CPC Blend was assessed by Platts, part of Commodity Insights, at a $1.77\/b discount to Dated Brent Aug. 9. ","headline":"Uncertainty, tension shroud Kazakhstan's Kashagan oil expansion","updatedDate":"2024-08-12T15:10:17.000"},{"Unnamed: 0":435,"body":null,"headline":"OPEC forecast for 2024, 2025 non-OPEC+ supply nudged up by 20,000 b\/d","updatedDate":"2024-08-12T10:45:28.000"},{"Unnamed: 0":436,"body":null,"headline":"OPEC cuts demand growth forecast for 2025 by 70,000 b\/d in Aug report","updatedDate":"2024-08-12T10:45:28.000"},{"Unnamed: 0":437,"body":null,"headline":"OPEC lowers 2024 world oil demand forecast by 140,000 b\/d, first change since March","updatedDate":"2024-08-12T10:45:27.000"},{"Unnamed: 0":438,"body":null,"headline":"\u2018Call\u2019 on OPEC+ crude cut by 100,000 b\/d for 2024, 300,000 b\/d for 2025","updatedDate":"2024-08-12T10:45:27.000"},{"Unnamed: 0":439,"body":" Saudi Aramco has allocated full term volumes to Asian refiners for September-loading crude supply, Asian traders and end-users said Aug. 12, while volumes to Asia's largest crude importer, China, were seen easing on the month. Aramco could not be immediately reached for an official comment. \"We got allocation as usual,\" a source at one Asian refiner said. In China, total Saudi crude allocations for September were heard at around 43 million barrels, down from the 43 million-47 million barrels range previously reported for August-loading cargoes. September volumes to Chinese majors Unipec and CNOOC were seen rising on the month by some, although this was offset by falling volumes to PetroChina and Fujian Refining and Petrochemical over the same period. Zhenhua Oil was seen taking no Saudi crude for September after taking 1 million barrels in August. Fujian Refining's fall in volumes comes as the company's 280,000 b\/d refinery is expected to undergo turnaround over Nov. 1-Dec. 20. Elsewhere, at least two South Korean refiners and one Japanese refiner reported being granted full allocation for September-lifting term barrels, with the companies' logistics management teams seeking the most ideal tanker fixtures to lift the Saudi barrels and co-load some other Persian Gulf crude grades next month. \"Aramco has always respected [Asian] customers' term contractual volumes regardless of the OPEC+ production cuts in the past few years, so the monthly term supply was never an issue for us ... We are mainly focusing on improving logistical efficiency, both in terms of cost and voyage timing in times of dismal refining margins,\" a feedstock and logistics management source at a major South Korean refiner based in Seoul said. Market structure Sentiment for the current month's October-loading Middle East crude cycle was mixed. While Asian end-user demand remained on a path of fragile recovery, fundamentals have tightened after Libya's giant 300,000-b\/d Sharara field was forced to shut down Aug. 5. Although Libyan crude flows to Asia have fallen significantly in recent years, the shutdown will nonetheless have a knock-on effect, as European refiners that typically import Sharara crude will now have to compete for the same barrels as Asian refiners. Crude oil differentials in both Middle Eastern and European crude markets have rebounded in recent days as a result. The Platts-assessed front-month Dubai cash-futures spread -- an indicator of sentiment in the Middle East sour crude market -- reached its highest for the month at a premium of $1.07\/b on Aug. 8, up 37 cents\/b on the day, S&P Global Commodity Insights data showed. Nonetheless, the spread has averaged sharply lower this month, at a premium of 83 cents\/b in the month to Aug. 8, down from an average premium of $1.60\/b in July. ","headline":"Saudi Aramco allocates full Sep crude term supply to Asian refiners","updatedDate":"2024-08-12T08:32:13.000"},{"Unnamed: 0":440,"body":" Global tankers' freight may rebound after winter demand sets in, coming out of the current weak phase amid slower refinery runs while diverging trends in clean and dirty tankers are no longer sustaining, analysts and market participants across Asia and Europe said on Aug. 11 Several factors are pulling the market in opposing directions. The drop in freight may reflect seasonal factors, still an uptick is expected in the fourth quarter, Tim Smith, the London-based director of shipping consultancy, Maritime Strategies International, said in a recent report. He said the lingering Suez Canal crisis and only a trickle of new deliveries are supportive fundamentals while slowdown in oil demand growth in China is keeping the downside potential intact. Ole Rikard Hammer, an Oslo-based senior oil and tankers analyst with Arctic Securities, said the tanker freight market is currently at crossroads and diverging trends in clean and dirty tankers, mainly VLCC, did not last. Historically, tanker rates are highly correlated between segments but not so in Q2 when Medium Range, or MRs and Long Range, or LRs did \"very well while the supertankers could only limp along\". A large part of this divergence is already disappearing with the latest decline in clean tankers' freight to their lowest levels so far for this year on the key Persian Gulf-North Asia routes, while the slower growth in crude trade is impacting the VLCC freight. Freight on the LR1 benchmark Persian Gulf-Japan route as of Aug. 8 has fallen w86 since the start of July and more than halved in the last 10 weeks, S&P Global Commodity Insights data showed Crude oil trade in the first half of 2024 was 1% higher on the year and this comes after the trade grew almost 5% in 2023 and 9% in 2022, said Enrico Paglia, a Genoa-based research manager with shipping brokerage and consultancy Banchero Costa, or Bancosta. Lower earnings MSI has forecast the daily average spot VLCC earnings at $33,700 in Q3, basis voyages to China from the US and the Persian Gulf, compared with $40,600 in Q2. The VLCCs are suffering from China's weak crude demand with both refinery runs and imports declining in Q2, said Arctic's Hammer. OPEC+ countries such as Russia and Saudi Arabia have responded to lower demand to shore up prices and therefore the VLCC activity has been slow, he said. The number of spot cargoes for VLCCs in the Persian Gulf and the Red Sea, including Contracts of Affreightment are estimated around 140 in July, down from 160 in March, according to brokers' estimates. Historically, oil demand is higher in Q3 by around 1.0 million-1.5 million b\/d compared with Q2 but if there is any further slowdown in the Chinese economy, demand for crude shipments may get even slower. MSI projected that the Q3 Long Range 2 tanker earnings at $39,000\/d on the Persian Gulf-Japan route are likely to be significantly lower by a fourth compared with $52,500\/d in Q2. In H1 2024, trade in refined products was 2% lower on the year, Paglia said. According to the estimates of brokers, at least 60 dirty tankers, of all sizes combined, have turned clean so far this year, adding to supply and dragging down freight. The clean market has still benefited more than crude from the Red Sea trade disruptions as the East-to-West product trade is proportionately more impacted, said Hammer. However, West Africa's imports have declined after Dangote refinery ramped up output, added Paglia. Slow fleet growth; oil shipments to rise The crude tanker fleet has grown only marginally so far this year with only a VLCC and Suezmax each being delivered, and the small growth recorded coming from five uncoated Aframaxes, said Bancosta's Paglia. Another dozen dirty tankers are expected to hit the water in 2024 but after factoring in the demolitions, the fleet size will remain largely unchanged, he said. Even next year, the fleet size will mostly remain unchanged even though the EIA has forecast global output to rise by 2.2 million b\/d, he added. Paglia also pointed towards OPEC+ plans to begin bringing back some barrels in October and phase out the voluntary 2 million b\/d of cuts over the following 12 months. There will then be more volumes to be shipped on tankers, brokers said. US exports have been strong and VLCC chartering activity can bounce back, said Hammer. US is steadily producing more than 13 million b\/d, added Paglia. OPEC+ needs to regain some of the market share lost to the cuts in favor of other exporters, in particular the US, he said. Rates have also got support because both crude and refined products are traveling longer distances due to unrest in the Red Sea, sanctions against Russia, and the drought affecting the Panama Canal. A large section of the fleet has been purchased and specializes in only moving Russian crude and refined products, thereby tightening supply for other origins. The bidding for over 15-year-old tankers has led to a monumental transfer of wealth from Russian interests to mostly Greek shipowners, said Edward Finley-Richardson, a Bordeaux-based shipping analyst with Contango Research. The irony is that the oldest and therefore most undesirable tankers have been bid up the most, causing horrendous market distortions, he said. ","headline":"Global tankers' freight likely to rebound on winter demand in Q4","updatedDate":"2024-08-12T07:21:19.000"},{"Unnamed: 0":441,"body":null,"headline":"Kuwait's KPC cuts Med and NWE-bound September crude OSPs by $2.80\/b on month","updatedDate":"2024-08-12T05:31:33.000"},{"Unnamed: 0":442,"body":null,"headline":"Kuwait's KPC keeps Asia-bound September KEC crude OSP steady on month","updatedDate":"2024-08-12T05:31:31.000"},{"Unnamed: 0":443,"body":null,"headline":"Kuwait's KPC cuts US-bound September crude OSPs by 75 cents\/b on month","updatedDate":"2024-08-12T05:31:31.000"},{"Unnamed: 0":444,"body":" Russia remains committed to its OPEC+ compensation plan, despite overproducing its quota by 67,000 b\/d of oil in July, the country\u2019s energy ministry said Aug. 9. In a statement, the ministry said its \u201cproduction in July has further decreased comparing to June, coming at 67,000 b\/d above the target levels.\u201d Given Russia\u2019s output target of 8.978 million b\/d that would take Russian July production to 9.045 million b\/d. It blamed the overproduction on \u201cone-off supply scheduling issues\u201d and said its August and September levels would \u201cremedy this\u201d. Along with other serial overproducers Iraq and Kazakhstan, Russia submitted plans on July 24 to compensate for high crude output in recent months. The Russian plan covers overproduction in Q2 2024, when it pledged to implement deeper reductions to bring its quota in line with Saudi Arabia\u2019s. However, all three countries produced over their quota in July, the Platts OPEC+ Survey from S&P Global Commodity Insights found, with Russian production staying flat month-on-month at 9.10 million b\/d. Taking into account promised monthly compensation targets, Russia, Iraq and Kazakhstan pumped 122,000 b\/d, 400,000 b\/d and 120,000 b\/d above their respective quotas, the Platts Survey found. Unlike its two peers, Russia\u2019s compensation cuts are not due to begin until October. In its statement, the ministry said Russia \"reaffirms its commitment to its compensation schedule which has earlier been submitted to the OPEC Secretariat and urges other OPEC+ countries who have submitted their compensation plans to adhere to them.\u201d Deputy Prime Minister and lead OPEC+ negotiator Alexander Novak had said July 23 that Russia had almost reached its production target. Iraq and Kazakhstan are yet to comment on their July overproduction. Iraq\u2019s high production is due in part to output of roughly 250,000 b\/d in the autonomous Kurdistan region, over which Baghdad exerts little control. Weak prices OPEC+ is engaged in a series of overlapping production cuts totaling some 5.8 million b\/d. The latest round of voluntary cuts by a core group \u2013 Saudi Arabia, Russia, Iraq, the UAE, Kuwait, Kazakhstan, Algeria, and Oman \u2013 are set to be gradually unwound from September, subject to market conditions, as agreed at the last OPEC+ ministerial meeting in June. Meanwhile the remaining 3.6 million b\/d of group-wide cuts have been extended until the end of 2025. The OPEC secretariat is due to release its latest monthly oil market outlook on Aug. 12, which should include full July production figures for all 22 members of the OPEC+ alliance, based on an average of seven secondary sources, including the Platts survey. The producers\u2019 group has been battling to shore up oil prices with cut extensions in recent months, amid sluggish Chinese demand, high interest rates in major economies and impressive output from non-OPEC members such as the US, Canada, Brazil and Guyana. Poor quota compliance could jeopardize those efforts, analysts say. Meanwhile, prices have seen some support from elevated Middle East tensions. The Platts-assessed Dated Brent fell from almost $90\/b in early-July to $76.27\/b on Aug. 6, but has rallied since to $81.10\/b on Aug. 8, Commodity Insights data showed. ","headline":"Russia reaffirms OPEC+ compensation plan despite exceeding July quota","updatedDate":"2024-08-09T14:01:51.000"},{"Unnamed: 0":445,"body":" OPEC+ crude production in July made its biggest jump in almost a year, as Iraq and Kazakhstan raised their output despite committing to deeper cuts, while Russia also remained well over its quota. The group's overall production was up 160,000 b\/d compared with June, totaling 41.03 million b\/d, the Platts OPEC+ survey from S&P Global Commodity Insights showed Aug. 8. Member countries with quotas produced 437,000 b\/d above target in July, up from 229,000 b\/d in June. July was the first month of compensation plans introduced by three countries that overproduced in the first half of 2024. Iraq pledged to cut an additional 70,000 b\/d in July and Kazakhstan pledged to cut a further 18,000 b\/d. Russia's compensation plan does not include additional cuts until October 2024. The survey found that Iraq produced 4.33 million b\/d in July, 400,000 b\/d above its quota. This contributed to growth in OPEC production of 130,000 b\/d to 26.89 million b\/d. Non-OPEC producers added a further 14.14 million b\/d, up 30,000 b\/d month on month. This was driven by Kazakhstan, which increased output by 30,000 b\/d. It is now producing 120,000 b\/d above quota, taking into account its compensation cut. Russia is also producing above quota, with output at 9.10 million b\/d in July, against a quota of 8.98 million b\/d. The overproducers are part of a group that is implementing a combined 2.2 million b\/d of voluntary cuts, currently in place until the end of the third quarter. The group then plans to gradually bring some of those barrels back to market from September if conditions allow. A further 3.6 million b\/d of group-wide cuts are in place until the end of 2025. The rise in output in July came despite the poor performance of the alliance's African contingent, with production in Nigeria, South Sudan, Gabon and Libya falling by a collective 80,000 b\/d. Pressure on overproducers has increased in recent weeks, as recession fears have driven oil prices below $80\/b. Platts, part of Commodity Insights, assessed Dated Brent at $79.91\/b Aug. 7. A long-awaited rise in Chinese demand and high production from non-OPEC countries in the Americas -- including the US, Canada, Brazil and Guyana -- have also weakened prices in recent months. OPEC+ has pledged to stick to its strategy of major production cuts through the third quarter, before gradually bringing barrels back to market. Overproduction and depressed oil prices threaten these plans. The next meeting of the Joint Ministerial Monitoring Committee overseeing the agreement, which is co-chaired by Saudi Arabia and Russia, is scheduled for Oct. 2. A full ministerial meeting is scheduled for Dec. 1. The Platts survey measures wellhead production and is compiled using information from oil industry officials, traders and analysts, as well as by reviewing proprietary shipping, satellite and inventory data. OPEC+ crude production (million b\/d) OPEC-9 July-24 Change June-24 Quota Over\/under Algeria 0.90 0.00 0.90 0.908 -0.008 Congo-Brazzaville 0.26 0.00 0.26 0.277 -0.017 Equatorial Guinea 0.05 0.00 0.05 0.070 -0.020 Gabon 0.21 -0.01 0.22 0.169 0.041 Iraq*\u2020 4.33 0.11 4.22 3.930 0.400 Kuwait 2.42 0.00 2.42 2.413 0.007 Nigeria 1.46 -0.04 1.50 1.500 -0.040 Saudi Arabia 8.99 0.01 8.98 8.978 0.012 UAE 2.99 0.02 2.97 2.912 0.078 TOTAL OPEC-9 21.61 0.09 21.52 21.157 0.453 OPEC EXEMPT Change Quota Over\/under Iran 3.20 0.00 3.20 N\/A N\/A Libya 1.15 -0.01 1.16 N\/A N\/A Venezuela 0.93 0.05 0.88 N\/A N\/A TOTAL OPEC-12 26.89 0.13 26.76 N\/A N\/A NON-OPEC WITH QUOTAS Change Quota Over\/under Azerbaijan 0.49 0.01 0.48 0.551 -0.061 Bahrain 0.18 0.00 0.18 0.196 -0.016 Brunei 0.07 0.01 0.06 0.083 -0.013 Kazakhstan\u2020 1.57 0.03 1.54 1.450 0.120 Malaysia 0.35 0.00 0.35 0.401 -0.051 Oman 0.76 0.00 0.76 0.759 0.001 Russia 9.10 0.00 9.10 8.978 0.122 Sudan 0.03 0.00 0.03 0.064 -0.034 South Sudan 0.04 -0.02 0.06 0.124 -0.084 TOTAL NON-OPEC WITH QUOTAS 12.59 0.03 12.56 12.606 -0.016 NON-OPEC EXEMPT Change Quota Over\/under Mexico 1.55 0 1.55 N\/A N\/A TOTAL NON-OPEC 14.14 0.03 14.11 N\/A N\/A OPEC+ MEMBERS WITH QUOTAS Change Quota Over\/under TOTAL 34.20 0.12 34.08 33.76 0.437 OPEC+ Change Quota Over\/under TOTAL 41.03 0.16 40.87 N\/A N\/A * Includes estimated 250,000 b\/d production in the semi-autonomous Kurdistan region of Iraq \u2020 Iraq and Kazakhstan quotas reduced in line with compensation plans Source: Platts OPEC+ survey by S&P Global Commodity Insights ","headline":"OPEC+ produces 437,000 b\/d above quota in first month of compensation cuts","updatedDate":"2024-08-08T17:36:29.000"},{"Unnamed: 0":446,"body":null,"headline":"Non-OPEC July output up 30,000 b\/d at 14.14 mil b\/d: Platts survey","updatedDate":"2024-08-08T14:00:12.000"},{"Unnamed: 0":447,"body":null,"headline":"OPEC+ producers with quotas 437,000 b\/d above target in July: Platts survey","updatedDate":"2024-08-08T14:00:11.000"},{"Unnamed: 0":448,"body":null,"headline":"OPEC crude output up 130,000 b\/d at 26.89 mil b\/d in July: Platts survey","updatedDate":"2024-08-08T14:00:11.000"},{"Unnamed: 0":449,"body":null,"headline":"OPEC+ July crude output up 160,000 b\/d at 41.03 mil b\/d: Platts survey","updatedDate":"2024-08-08T14:00:10.000"},{"Unnamed: 0":450,"body":null,"headline":"Iraq, Russia, Kazakhstan overproduce in first month of compensation cuts: Platts survey","updatedDate":"2024-08-08T14:00:10.000"},{"Unnamed: 0":451,"body":" UK-based upstream producer Harbour Energy plans to start its new Talbot oil and gas tie-in project at the J-Area hub in the North Sea by the end of 2024, boosting Ekofisk blend volumes, it said Aug. 8. Harbour, in a statement, reported a 19% year-on-year drop in its UK oil and gas production in the first half of 2024 to 149,000 b\/d of oil equivalent. It noted a significant maintenance impact, including a planned shutdown in June at the J-Area, which sends oil and gas to Teesside, with the liquids loaded as Ekofisk blend. Ekofisk is a component in the Platts Dated Brent price assessment process. Talbot, a multiwell development, is expected to recover 18 million boe of light oil and gas over 16 years. It will add to oil volumes flowing through the J-Area into the Norpipe route to Teesside, contributing to the predominantly Norwegian Ekofisk blend. Harbour also flagged an ongoing maintenance impact on production through much of the Q3 2024, including a 40-day shutdown at the Britannia hub starting in August, which will impact flows into the Forties blend. The maintenance was expected to start in the next few days and be completed in September, according to a source close to the situation. Britannia was also expected to be impacted by a four-week shutdown of the SAGE gas pipeline starting Aug. 27 . Harbour has made \"good progress to date on the maintenance shutdowns and our UK capital projects, which are on track to materially increase production in the fourth quarter,\" it said. The North Sea typically sees a drop in production volumes in the summer due to maintenance. Non-UK diversification Harbour reiterated its efforts to diversify away from the UK, with an acquisition of Wintershall Dea assets underway, having strongly objected to punitive tax rates. It said its overall effective tax rate in the first half of 2024 was 85%, partly reflecting not-fully deductible costs under the UK tax regime. Harbour reported 10,000 boe\/d of additional production outside the UK in the first half of the year, in Indonesia and Vietnam. It noted progress in Mexico, where Front End Engineering and Design has begun for the Zama oil project, estimated at 700 million barrels of light crude. Harbour is set to increase its Zama stake from 12% to 32% following the Wintershall acquisition. In the first half of 2024 \"we made significant progress towards completing the Wintershall Dea acquisition, which is now expected early in the fourth quarter,\" CEO Linda Cook said. \"The acquisition will transform the scale, geographical diversity and longevity of our portfolio and strengthen our capital structure, enabling us to deliver enhanced shareholder returns over the long run while also positioning us for further opportunities.\u201d Platts Dated Brent was assessed at $79.91\/b on Aug. 8, up $3.64 on the day. Platts is part of S&P Global Commodity Insights. ","headline":"UK's Harbour Energy says on track with North Sea Talbot oil tie-in","updatedDate":"2024-08-08T13:54:45.000"},{"Unnamed: 0":452,"body":" The INPEX-operated Ichthys LNG project in Australia has recovered to an 85% overall production rate after Train 2 restarted on July 28 following an outage on July 20 that was caused by a glitch, an INPEX spokesperson told S&P Global Commodity Insights Aug. 8. Currently, the onshore Ichthys LNG plant is running at 100% at Train 1, and about 70% at Train 2, putting the overall production rate at about 85%, the spokesperson said. The Ichthys LNG project is slated to resume full runs in October, when it plans to carry out some scheduled maintenance work lasting around a week, the spokesperson said. INPEX has estimated that fewer than five LNG cargoes of Ichthys LNG shipments will be affected as a result of the glitch, the spokesperson said. However, the INPEX spokesperson declined to elaborate on actual production volumes at the Ichthys LNG plant, which has yet to reach its operational capacity of 9.3 million mt\/year. INPEX has been building a framework for a stable supply of 9.3 million mt\/year of LNG at its operated Ichthys project by debottlenecking the facility, upgrading the cooling systems for liquefication and taking measures to address vibration issues. As of July, the Ichthys project has shipped a total of 76 LNG cargoes this year, with July shipments having slipped to 10 cargoes from 11 cargoes in June. Ichthys LNG shipments will slow to 10 cargoes per month in the second half of 2024, the spokesperson said, compared with an average of 11 cargoes per month in the first half of the year. In the first seven months of the year the Ichthys project shipped 14 plant condensate cargoes, 18 field condensate cargoes and 20 LPG cargoes. In the January-June period INPEX produced 662,000 b\/d of oil equivalent, and it now expects its 2024 production to be 644,800 boe\/d, down from its May outlook of 645,300 boe\/d for the year as a result of the Ichthys LNG production issues, the spokesperson said. The project, operated by INPEX with 67.82%, involves piping gas from the offshore Ichthys field in the Browse Basin in Northwestern Australia more than 890 km (552 miles) to the onshore LNG plant near Darwin, which has an 8.9 million mt\/year nameplate capacity. At peak, it has the capacity to produce 1.65 million mt\/year of LPG and 100,000 b\/d of condensate. ","headline":"Australia's Ichthys LNG recovers 85% output after Train 2 outage; to recover full runs in Oct","updatedDate":"2024-08-08T11:53:44.000"},{"Unnamed: 0":453,"body":" NTPC Limited, India\u2019s largest power generation utility, has partnered with LanzaTech to implement carbon recycling technology at its new facility in central India, in a significant move towards sustainable energy. The project will convert CO2 emissions and green hydrogen into ethanol using LanzaTech's second-generation bioreactor, the US-based company said in a statement Aug. 7. NTPC's upcoming plant will be the first in India to deploy this advanced technology, which captures carbon-rich gases before they enter the atmosphere. The LanzaTech bioreactor uses proprietary microbes to transform these gases into sustainable fuels, chemicals, and raw materials. The microbes convert CO2 and H2 into ethanol, a critical component for producing green energy products such as sustainable aviation fuels (SAF) and renewable diesel. This in turn boosts NTPC's goals by producing ethanol from waste-based feedstocks, promoting a circular carbon economy. According to the statement, the project was conceptualized and designed in collaboration with NTPC's research and development arm, NETRA (NTPC Energy Technology Research Alliance). The facility aims to demonstrate the commercial viability of LanzaTech\u2019s technology in producing ethanol from waste-based feedstocks by leveraging CO2 as sole carbon source. Jakson Green, a new energy firm, is responsible for development of this Chhattisgarh-based facility, handling from design and engineering to procurement and construction. This first-of-its-kind plant is projected to abate 7,300 mt\/year of CO2 annually, equivalent to the carbon sequestered by 8,523 acres of forest land. The carbon and hydrogen to renewable ethanol facility is slated to begin operations within two years. Dr. Jennifer Holmgren, CEO of LanzaTech, emphasized the strategic importance of this partnership, stating, \u201cOur collaboration with NTPC and Jakson Green sets a roadmap for the commercial deployment of CO2 as a key feedstock.\u201d Jakson Green is already developing India\u2019s largest green hydrogen fueling station and a low-carbon methanol plant for leading government companies. LanzaTech technology is also being used at various other operations in India, producing ethanol at Indian Oil Corporation\u2019s Panipat facility which will also be used for SAF. The company has also partnered with GAIL and Mangalore Refinery and Petrochemicals Limited on similar projects. Platts, part of Commodity Insights, assessed SAF production costs (palm fatty acid distillate) in Southeast Asia at $1,589.91\/mt Aug. 7, down $19.50\/mt from the previous assessment. ","headline":"NTPC advances clean energy goals with LanzaTech CO2-to-ethanol technology","updatedDate":"2024-08-08T11:30:49.000"},{"Unnamed: 0":454,"body":" UAE-based Dana Gas said it expects to resume drilling activities in Egypt after the country\u2019s parliament ratified a law to consolidate its concessions to operate in the country under a new concession with Egyptian Natural Gas Holding Co. The new agreement ratified by the Egyptian parliament was already approved by the Egyptian Cabinet in March, authorizing the country\u2019s minister of oil and Egyptian Natural Gas to finalize a new concession agreement with Dana Gas, the company said in an Aug. 8 statement. Since 2001, Dana Gas has been in discussions with Egyptian Natural Gas to consolidate three of its four concessions into a new concession with improved terms, according to Dana Gas\u2019s website. \u201cThe revised terms should enable meaningful future investments alongside a resumption of drilling activities, positively impacting the company\u2019s production levels in Egypt and helping the country meet its growing gas demand,\u201d Dana Gas said in the statement. Egypt has halted LNG exports during the summer months and has turned to LNG imports instead to meet high seasonal demand amid declining domestic production. The development comes as delivered spot LNG prices to the East Mediterranean continue to trade above $10\/MMBtu. Platts, part of S&P Global Commodity Insights, assessed the DES LNG East Mediterranean marker at $12.47\/MMBtu Aug. 7, the highest since the assessment started in December 2023. The company\u2019s first-half 2024 production in Egypt was 59,800 boe\/d, down 25% from the same period a year earlier, mostly due to natural field declines, according to the statement. Dana Gas did not state when it expects to bring new production streams online in the country. Dana Gas's production in the Kurdish region of northern Iraq increased 3% over the same period to 37,600 boe\/d due to increased demand for gas from local power plants, the company said. ","headline":"Dana Gas expects to resume drilling activities in Egypt after new concession","updatedDate":"2024-08-08T11:23:48.000"},{"Unnamed: 0":455,"body":null,"headline":"Indonesia sets Minas crude price at $84.95\/b for July, rising $3.35\/b from June","updatedDate":"2024-08-08T01:41:13.000"},{"Unnamed: 0":456,"body":" ExxonMobil is working to get its Joliet refinery in Channahon, Illinois, back up and running after a July 15 tornado touched down nearby destroying the Commonwealth Edison's power transmission lines, shutting down power supply to the plant and surrounding areas, a company spokesperson said on Aug. 7. \"We\u2019ve safely restarted select units at our refinery and are carefully ramping up production. We\u2019re continuing to assess our equipment and working hard to resume full operations as safely and quickly as possible,\" said Lauren Kight, a spokesperson for ExxonMobil via email. The refinery was forced to shut, which caused supply issues for gasoline and diesel in the Chicago market. Both gasoline and diesel prices spiked on the news. The units impacted by the storm include a crude distillation unit, a gasoline-making fluid catalytic cracking unit and a catalytic reformer. However, prices dropped on Aug. 1 after the US Environmental Protection Agency issued an emergency waiver of summer gasoline volatility to address the supply issues in four Midwestern states. The waiver took effect on Aug. 1 and is valid through Aug. 21. However, the EPA could extend the waiver through Sept. 15, which is when the gasoline specification switches to a transitional winter grade. ","headline":" ExxonMobil restarts some Joliet units, ramps up production","updatedDate":"2024-08-07T20:36:12.000"},{"Unnamed: 0":457,"body":" Libya's National Oil Company declared force majeure on the huge Sharara oilfield late on Aug. 7, days after disruptors entered the control room and cut production. In an internal letter, seen by S&P Global Commodity Insights, the NOC's board of directors said that due to \"circumstances\" preventing crude production at and exports from Sharara, which are out of NOC's control \"and cannot be prevented,\" it has opted to declare force majeure. Interruptions to output at Libya's largest field began Aug. 4, with Commodity Insights reporting a full shutdown on Aug. 5. The NOC in an Aug. 6 statement blamed the Fezzan Movement in southwest Libya, which has shut the 300,000 b\/d field in the past over poor socioeconomic conditions. However, three sources and the Fezzan leader Bashir al-Sheikh said the shutdown had instead been ordered by the son of warlord Khalifa Haftar who dominates Libya's eastern government in Benghazi. The Fezzan had nothing to do with the closure, Sheikh said. The country also has an internationally recognized government in Tripoli in the west, reflecting the political chaos that followed the fall of Moammer Qadhafi in 2011. Saddam Haftar, son of Khalifa Haftar, was understood to have ordered the closure in response to a European arrest warrant, related to an alleged botched drone deal under investigation by Spanish authorities, sources told Commodity Insights. Spain's Repsol is one of the operators of the Sharara field, alongside the NOC, France's TotalEnergies, Norway's Equinor and Austria's OMV. The Libyan National Army, under Haftar's command, was not reachable for comment. Haftar and his son have not addressed the accusations or the Sharara shutdown. The field, whose crude supplies European refiners, was producing roughly 250,000 b\/d prior to the shutdown, sources said, with output initially falling to around 100,000 b\/d, before gradually reducing further. Under 10,000 b\/d of oil was still understood to be flowing to the Awbari power station. On Aug. 5, OMV acknowledged a reduction in output, adding it was unaware of the causes. The other joint-venture partners did not respond to requests for comment. A closure backed by the Libyan National Army bodes ill for Libya's oil sector and international oil companies operating in the fragile, oil-dependent country. In June 2022, the Libyan National Army's blockades reduced Libyan output to just 650,000 b\/d, but the shutdowns ground to a halt after the appointment of current NOC chief Farhat Bengdara in July 2022 and crude output gradually ticked up. In a statement of its own, the Tripoli government slammed the latest closure as \"new attempts at political blackmail.\" In another indication of the instability plaguing the oil sector on Aug. 7, Libya's prosecutor general ordered the arrest of the country's oil minister on allegations of conduct \"inconsistent with their job duties,\" according to media reports. The country currently has two self-declared oil ministers -- Mohamed Aoun and Khalifa Rajab Abdulsadek -- after Aoun returned to work following an investigation. It was not clear which of the two the prosecutor general was seeking to arrest. Libya has been attempting to push oil output up towards the 1.6 million b\/d it was producing in 2011. In June, the North African country pumped 1.16 million b\/d, according to the latest Platts OPEC Survey from S&P Global Commodity Insights. Libya's crudes are a popular feedstock for European refiners, meaning a prolonged Sharara shutdown could tighten the light, sweet market in the Mediterranean, Commodity Insights analysts said. ","headline":"Libyan NOC declares force majeure on Sharara oilfield after shutdown","updatedDate":"2024-08-07T19:05:07.000"},{"Unnamed: 0":458,"body":null,"headline":"Libya NOC declares force majeure on Sharara oilfield after shutdown","updatedDate":"2024-08-07T18:17:47.000"},{"Unnamed: 0":459,"body":" London-listed Savannah Energy cancelled its long-delayed $1.25 billion acquisition of Petronas\u2019 oil assets in South Sudan, but hopes to purchase the assets on alternative terms, the company said Aug. 7. The Africa-focused company agreed to buy the projects from the Malaysian state oil company in December 2022, but the deal has faced continued delays in recent months, related to slow regulatory approvals. \u201cDespite the substantial efforts of all parties since that time, it has not been possible to complete the proposed transaction on the envisioned terms and the original sale and purchase agreement is terminated,\u201d Savannah said in its statement. The firm added that it remains \u201cin active discussions with the relevant parties around an alternative potential transaction in relation to an acquisition of the Petronas assets.\u201d The update came hours after Petronas announced \u201cthe withdrawal of its operations in the Republic of South Sudan\u2026following a two-year period of divestment initiatives.\u201d The Malaysian company added that it \u201cwill continue to work with all relevant stakeholders to ensure an amicable transition while being mindful of the rights of its employees, in accordance with applicable laws, petroleum agreements as well as Petronas\u2019 policy and procedures.\u201d Sources familiar with the transaction said Savannah aims to conclude a new transaction this year with a different deal structure with the same parties. Since February, one of the two oil export pipelines from South Sudan -- which runs through troubled Sudan -- has been offline due to a maintenance issue, which could affect the value of the assets. Reverse takeover The deal was initially expected to close in September 2023 but was later pushed back to Q4 2024. Savannah aimed to finance the purchases with a combination of cash resources and debt, it said at the time, adding the deals technically qualified as reverse takeovers so required approval from its shareholders. The Petronas deal would make Savannah a key shareholder in Blocks 3\/7, 1\/2\/4 and 5A, giving it stakes in 64 producing fields. The projects pumped an average of 153,200 b\/d of oil in 2021, according to Petronas. Oil fields in the country are managed by joint operating companies such as Dar Petroleum Operating Co. in the case of Block 3\/7. China\u2019s CNPC holds a 41% stake in DPOC, alongside Petronas with 40%, while Sinopec has a 6% stake and state-owned Nilepet the remainder. South Sudanese output peaked at 350,000 b\/d of crude after independence from Sudan in 2011, but it has more than halved since then. The coronavirus pandemic hampered efforts to boost flows from aging wells, while exploration activity has been minimal. In recent months, production and exports have slowed dramatically due to the Sudan pipeline outage. Fixing it is understood to be affected by the ongoing war in Sudan, triggered last July by a row between feuding generals. The country produced just 60,000 b\/d in June according to the latest Platts OPEC Survey from S&P Global Commodity Insights. The oil-dependent country hopes to reach 300,000 b\/d by 2030. AIM-listed Savannah, which also boasts assets in Nigeria and Niger, is no stranger to setbacks. In early 2023 the government of Chad nationalized the oil assets that Savannah had agreed to purchase from ExxonMobil. ","headline":"Savannah cancels South Sudan oil acquisition, seeks alternative deal","updatedDate":"2024-08-07T17:54:40.000"},{"Unnamed: 0":460,"body":" Plans for a four-week maintenance shutdown of the North Sea SAGE gas pipeline from Aug. 27 were confirmed by contractor Wood on Aug. 7, with knock-on impacts expected for numerous oil and gas fields, including in the Forties area. The Scottish Area Gas Evacuation system is a vital logistical underpinning for oil and gas production in the UK and Norwegian waters, and the intended shutdown was first flagged by the operator in April. A spokesperson for Wood, which runs SAGE on behalf of Ancala Midstream Partners, said there was \"no slippage,\" with \"all on track,\" when asked to confirm the original notice. North Sea oil producers have a variety of routes for shipping associated gas volumes, many of them not running adjacent to oil pipelines, but to separate gas processing terminals. The SAGE system gathers gas from 46 North Sea fields through nine \"primary hubs,\" according to Ancala. Norwegian fields that send gas via SAGE include Alvheim and some that deliver the Grane heavy crude blend. Also reliant on SAGE is the UK Beryl hub, operated by Houston-based APA, and some fields that feed UK Forties crude flows, including Harbour Energy's Britannia hub. China's CNOOC is another user of Sage for its Golden Eagle oil facility. The gas that SAGE transports reaches the mainland at St Fergus in eastern Scotland, where it is processed before entering the distribution system. The Wood spokesperson said the shutdown was \"part of our ongoing, routine maintenance schedule.\" The exact impact on oil production volumes was not determined. The Forties oil stream, derived partly from gas condensate fields, typically accounts for the highest share of UK crude exports. It is a component in the Platts Dated Brent price benchmark. Karl Johnny Hersvik, CEO of Aker BP, which operates some of the Norwegian fields affected, said earlier the \"main driver\" of the Sage shutdown was to repair an inlet valve. The Platts Dated Brent benchmark was assessed at $76.28\/b on Aug. 6, down 43 cents. Platts is part of S&P Global Commodity Insights. Loadings of the BFOET crudes in the Dated Brent basket were expected to average 536,667 b\/d in September, down 27,849 b\/d from August, according to loading program data compiled by Commodity Insights July 30. Maintenance is particularly common in the summer months in the North Sea, with a number of other shutdowns also expected. ","headline":"North Sea SAGE gas pipeline four-week shutdown confirmed for Aug. 27: operator","updatedDate":"2024-08-07T15:49:07.000"},{"Unnamed: 0":461,"body":" The LNG deal between Taiwan\u2019s CPC and Woodside for the supply of 6 million mt LNG over 10 years between 2024 and 2034 has hybrid pricing and includes JKM in the pricing consideration for the deal\u2019s early years, sources told S&P Global Commodity Insights. According to sources, the deal is priced to JKM for the early years of July 2024 to 2026, when Scarborough LNG project starts. Once the Scarborough LNG project starts, the deal is priced at a slope of approximately 12.7% to crude oil, the sources said. This two-tier pricing is largely in line with the market as global LNG balances are expected to be tight for the next two to three years until new supply from projects begins later in the decade. Near-term LNG contracts and volumes have been increasingly linked to spot market pricing. Woodside declined to comment and CPC did not respond at the time of publishing. However, the July 11 statement said the LNG delivered to CPC under the sale and purchase agreement will be sourced from volumes across Woodside\u2019s global portfolio. Woodside may also deliver around 8.4 million mt of LNG to CPC over a further 10 years, from 2034 to 2043, subject to conditions and agreement on terms for this period, Woodside said while announcing the SPA. This is the second LNG SPA for CPC announced in quick succession. The previous deal was for 4 million mt\/year with Qatar Energy likely beginning in 2026-27 for a tenure of 27 years, which was priced at a 12.7%-12.8% slope to crude oil. Hybrid pricing Since the latest deal is linked to spot LNG prices for the early period of the deal, CPC would protect itself from the elevated slopes that were offered for long-term contracts earlier for supply beginning before 2026. In 2023, some of the companies that signed medium-term contracts for LNG supply beginning in 2024 for a period of one to five years were offered slopes of 13%-15%, and sometimes even higher. A 15% slope against a crude oil price of $80\/b would have meant a price near $12\/MMBtu equivalent for 2024. However, Commodity Insights data showed that the price stayed below the $12\/MMBtu mark for a large period in 2024 with the average JKM settlement for 2024 so far at $11.10\/MMBtu monthly. With the deal being priced at a slope of approximately 12.7% to crude oil when Scarborough LNG starts, which is expected to be 2026, this indicates expectations from the buyer of either stronger-than-expected spot LNG prices or weaker-than-prevailing crude oil prices. The forward curve as assessed by Platts, part of Commodity Insights, on Aug. 6 showed the average price for 2027 at $10.325\/MMBtu. For a large part of 2024, Dated Brent averaged around $80\/b, and a 12.7% slope would imply a fixed price of $10.16\/MMBtu. Given the additional supply expected to hit the market from 2026, market participants are looking to see how the additional supply and uncontracted LNG volumes affect spot prices in comparison to the slopes to crude oil that are being signed by buyers in Northeast Asia. However, Woodside is also a portfolio player in the LNG industry, and having supply from different sources allows it to tap different hybrid pricing mechanisms that a pure play producer would be unable to offer its customers. Taiwan\u2019s CPC in particular has typically been in favor of conventional long-term contracts. ","headline":"CPC's LNG deal with Woodside includes JKM in pricing formula for at least 2 years","updatedDate":"2024-08-07T13:41:08.000"},{"Unnamed: 0":462,"body":" A.P. Moller-Maersk will acquire up to 60 newbuild container ships capable of running on LNG or methanol for fleet renewal during the second half of this decade, the Danish company said Aug. 7 while reporting higher shipments and bunker consumption in the second quarter. Maersk, one of the world\u2019s top three container lines by shipping volumes, said it is in the process of ordering vessels with a total capacity of 300,000 TEU and signing time charters for 500,000 TEU. The newbuild program will amount to 50-60 ships with 800,000 TEU designed to be powered by conventional, oil-based fuels and either methanol or LNG, and the company said some contracts were already signed and the rest would be in the coming weeks. \u201cAs the shipyard order books have been filling up quickly and lead times for vessel deliveries have increased significantly, we decided to place orders and charter contracts...which ensures a steady flow of needed capacity for our network for the years 2026-30,\u201d Maersk Chief Operating Officer Rabab Boulos said in a statement. The exact split of propulsion technologies between methanol and LNG will be determined considering the future regulatory framework and green fuels supply, the company said without elaborating further. Earlier announcements suggested the company is already due to receive at least 36 methanol-capable vessels in total via newbuilds and retrofit projects between 2023 and 2027, making it potentially the largest future maritime consumer of the alternative fuel. But industry worries persist over the limited availability and high costs of methanol produced via sustainable means, and Maersk\u2019s confirmation of recent market chatter about its first contracts for LNG-fueled ships underscores the fuel\u2019s growing popularity among ship operators, partly due to its availability in a wide range of bunker hubs across the globe. In an earnings call, Maersk CEO Vincent Clerc said \u201ca high level of uncertainty\u201d over future prices and availability of \u201cgreen\u201d fuels, and over regulatory regimes for greenhouse gas emissions, prompted the company to change its previous stance of avoiding LNG propulsion with it being a fossil fuel. \u201cThis is an opportunity to balance out bets...[So] we don\u2019t suddenly have disadvantages for one reason or another,\u201d said Clerc, adding that methanol, LNG and ammonia could all be future fuels while oil-based bunker fuels would remain for many years. Maersk had previously only opted for methanol as an alternative fuel propulsion. Fleet renewal Despite methane slippage concerns, LNG bunker demand has been hitting record highs in Rotterdam , Europe\u2019s top refueling hub, in recent quarters as the fuel is mostly pricing at a discount to 0.5% sulfur fuel oil -- the prevalent bunker type. Platts, part of S&P Global Commodity Insights, assessed the delivered LNG bunker price at $12.674\/Gigajoule and 0.5%S fuel $12.683\/Gj in Rotterdam Aug. 6 even as oil prices tumbled in recent trading sessions. The gray methanol bunker price was assessed at $17.313\/Gj, and industry estimates suggest sustainable methanol could be at least two times more expensive. Maersk\u2019s newbuild projects are to renew its fleet at a pace of around 160,000 TEU\/year as older ships retire, maintaining its total shipping capacity at 4.3 million TEU, according to the company. When all the newbuilds are delivered, Maersk will have 25% of its fleet equipped with dual-fuel engines. As LNG can only reduce greenhouse gases by 20%-30% compared with oil-based fuels, Maersk said it had started to negotiate biomethane offtake agreements for deep decarbonization, a path taken by other major lines like CMA CGM and Hapag-Lloyd. Strong quarter Meanwhile, Maersk said the container freight market environment remained strong due to robust shipping demand and incremental vessel requirements amid the Red Sea crisis, despite a large number of newbuild deliveries. The Platts Container Index, a weighted average of spot rate assessments on key routes, hit a 21-month high of $4,159.27\/FEU in late June, up from $781.20\/FEU on Nov. 22, 2023. It was last assessed at $3,734.24\/FEU Aug. 6. With global container demand estimated to have grown between 5%-7% on the year during Q2, the company has adjusted its demand growth forecast to 4%-6% from 2.5%-4.5% for the whole of 2024. \u201cMarket demand has been strong, and as we have all seen, the situation in the Red Sea remains entrenched, which leads to continued pressure on global supply chains,\u201d Clerc said. \u201cThese conditions are now expected to continue for the remainder of the year.\u201d Maersk reported shipping volumes of 3.1 million FEU in Q2, up from 2.9 million TEU in the same period of last year. It achieved an average freight rate of $2,499\/FEU, up from the year-ago level of $2,444\/FEU. The company, which has joined many other ship operators in rerouting ships away from the Red Sea to sail around Africa due to Houthi attacks since late last year, chartered ships with 172,000 TEU to meet additional requirements. Its bunker consumption rose to nearly 2.9 million mt in Q2 from 2.4 million mt in the year-ago period, while bunker costs increased to $1.8 billion from $1.4 billion. Maersk reported EBITDA of $2.1 billion in April-June, down from $2.9 billion in Q2 2023. Revenue fell to $12.8 billion from $13 billion. However, the company adjusted its 2024 full-year guidance to EBITDA of $9 billion-$11 billion from $7 billion-$9 billion and capital expenditure to $10 billion-$11 billion in 2024-2025 from $9 billion-$10 billion due to a brightened market outlook. ","headline":"Maersk confirms first LNG-fueled ship contracts; Q2 volumes up","updatedDate":"2024-08-07T12:41:45.000"},{"Unnamed: 0":463,"body":" China's crude oil imports dropped to 10.01 million b\/d (42.34 million mt) in July, the lowest since 9.83 million b\/d in September 2022, data from the General Administration of Customs showed Aug. 7, pointing to weak demand from the world's second biggest economy. The country was in tight movement controls in 2022 from May to November. The low inflows in July this year led more and more analysts to expect an annual reduction in China's crude imports in 2024, unless Beijing release efficient stimulators to boost demand in order to meet the 5% GDP growth target. The July volume represented a 3.1% year-on-year decline and a 11.8% reduction from June on a barrels-per-day basis. The GAC releases data in metric tons that S&P Global Commodity Insights converts to barrels using a 7.33 conversion factor. On a metric-ton basis, the volume in July fell 8.9% from June. State-run refineries were likely the main contributor of the reduction, despite they lifted average utilization from 78% in June to 80% in July as maintenance ended. Independent refineries also cut their crude shipments by 2.97% from June to 3.65 million b\/d, led by the small ones with capacity range between 40,000-214,000 b\/d which remain running at low utilization , Commodity Insights data showed. China's average crude imports over January-July broke below the 11 million b\/d mark to 10.94 million b\/d, down 2.9% or 324,000 b\/d year on year, GAC data showed. \"We now believe China's crude imports to fall 150,000-200,000 b\/d [year on year] in 2024 as gloomy economy caps demand, while alternative energy continues displacing transportation fuels, and crack are not strong enough to encourage product exports,\" said a Beijing-based analyst with an international trading company. \"Bet the government will release more measures to boost economy to hit the 5% GDP growth target. Hence, it is still possible to see rebounds in domestic oil demand,\" a Hong Kong-based analyst said. China's crude import growth is expected to weaken significantly in 2024, almost coming to a halt, in contrast to the 1.1 million b\/d growth rate observed in 2023, according to a monthly report released by Commodity Insights on July 31. \"However, due to the low base effect and seasonal demand in the third quarter, August imports are very likely to increase month on month,\" said Mongbi Yao, a senior research analyst with Commodity Insights. \"We anticipate a year-over-year decline of 272,000 b\/d in crude imports for the third quarter as demand pressures lead to subdued refining operations,\" she added. Oil product exports down Meanwhile, oil product exports fell 7.1% month on month to a three-month low of 4.98 million mt in July, GAC data showed. Market sources estimated clean oil products exports to be steady on the month in August, at about 3.27 million mt, with jet fuel to account for about 1.7 million mt. GAC's oil product import and export data are believed to have included a basket of oil products, with gasoline, gasoil, jet fuel and fuel oil accounting for the majority. The breakdown of products will be released Aug. 18. There has been talks about the Chinese government may release 15 million mt of oil product export quotas in September, that would bring the country's total clean oil product export quota to as high as 48 million mt for 2024. China's 2024 clean oil product exports have been widely expected to remain steady on the year at about 40 million mt, due to less attractive export margins and a slight surplus in the domestic market. In July, oil product imports gained 9.3% from June to 3.25 million mt, despite independent refineries slashing feedstock fuel oil imports due to high cost and weak margin, GAC data showed. The increase in imports and decrease in exports, however, failed to turn China into a net oil product importer in July, as the net oil product exports fell 27.5% month on month to 1.74 million mt. China's oil trade (million mt): Jul-24 Jul-23 Change Jun-24 Change Crude imports 42.34 43.69 -3.1% 46.45 -8.9% Oil product imports 3.25 4.50 -27.9% 2.97 9.3% Oil product exports 4.98 5.31 -6.2% 5.37 -7.1% Net oil product exports 1.74 0.81 115.2% 2.40 -27.5% Jan-Jul 2024 Jan-Jul 2023 Change Crude imports 317.81 325.70 -2.4% Oil product imports 28.32 27.09 4.6% Oil product exports 35.08 36.59 -4.1% Net oil product exports 6.76 9.51 -28.9% Source: General Administration of Customs ","headline":" July crude oil imports drop to 10.01 mil b\/d, lowest since Sep 2022","updatedDate":"2024-08-07T10:23:59.000"},{"Unnamed: 0":464,"body":" Stockpiles of oil products at the UAE\u2019s Port of Fujairah declined 5.9% in the week ended Aug. 5 to a one-month low as exports in the final week of July almost doubled, according to Fujairah Oil Industry Zone and ship-tracking data. The total fell to 16.737 million barrels, the lowest since July 1, FOIZ data published Aug. 7 showed. Stockpiles have dropped 3.5% since the end of 2023. Product exports in the week started July 29 jumped to 5.98 million barrels from 3.37 million barrels a week earlier, according to Kpler data. Saudi Arabia was set to receive 607,000 barrels of gasoline during the week, the most since January, the data showed. Product shipments destined for Singapore were set to rise to 1 million barrels from 312,000 barrels over the same period while Pakistan, South Korea, Taiwan and Mauritius were also set to get more supplies. Among the individual product categories, stockpiles of middle distillates such as jet fuel and diesel fell 12% in the latest week to 1.644 million barrels, the lowest since March 11. Light distillates such as gasoline dropped 7% to 5.777 million barrels over the same period while heavy distillates used for power generation and ship fuel declined 4% to 9.316 million barrels, a one-month low, according to the FOIZ data. So far since the end of 2023, stocks of light distillates have climbed 23%, heavy distillates have dropped 8.1% and middle distillates have declined 34%. Bunker demand average At the Middle Eastern bunker hub of Fujairah, mixed demand dynamics were seen in both the low and high sulfur fuel oil segments, with increasing competition among sellers persistently weighing on downstream valuations, traders said Aug. 7. End-user demand for LSFO grade has been moderate in recent weeks, but mostly \u201cstill slow\u201d and falling below initially stronger expectations so far in August, according to local bunker suppliers. \u201cLSFO demand was expected to perform better\u2026 Competition has been intense with at least 2-3 suppliers every day [offering] aggressive levels and [pushing] down delivered premiums,\u201d a Fujairah-based bunker supplier said Aug. 7. Sellers were also keen to fill their available barge schedules for prompt LSFO refueling dates as early as within five days, amid hopes to move cargoes and turn their barges, traders said, while expectations of buoyed cargo inflows for the rest of August also dampened sentiments. The Platts-assessed Fujairah-delivered marine fuel 0.5% sulfur bunker premium over benchmark FOB Singapore marine fuel 0.5%S cargo averaged $11.95\/mt Aug. 1-6, below the $12.13\/mt across July, according to S&P Global Commodity Insights data. Compared with the LSFO segment, traders said competition among HSFO downstream sellers were even more intense as players hurried to draw down stockpiles in anticipation of higher stockpiles for the rest of the third quarter. Thus, pressure on HSFO delivered premiums managed to attract decent demand from shipowners, but some suppliers have reported losing fair volumes of inquiries to their eager competitors, which could undercut others by fairly large margins, bunker suppliers said Aug. 7. Meanwhile, the Platts-assessed Fujairah-delivered 380 CST HSFO bunker premium over FO 380 CST 3.5% FOB Arab Gulf inched up to $24.29\/mt Aug. 1-6, marginally above the $23.92\/mt in July, but still significantly lower from the $31.79\/mt for all of June, Commodity Insights data showed. ","headline":" Oil product stocks drop to month low as exports almost double","updatedDate":"2024-08-07T08:46:53.000"},{"Unnamed: 0":465,"body":" Petro Rabigh\u2019s refinery in Saudi Arabia will be upgraded after shareholders Saudi Aramco and Sumitomo Chemical agreed to a phased waiver of their loans to the company totaling $1.5 billion after Petro Rabigh\u2019s accumulated losses reached 53% of capital as of June 30, according to Aug. 7 statements from all three companies. Aramco also agreed to acquire more Petro Rabigh shares from Sumitomo Chemical for $702 million, which will be injected into Petro Rabigh, the companies said in an Aug. 7 joint statement. Aramco will provide another $702 million to Petro Rabigh, for a total injection of $1.4 billion. \u201cThese measures are expected to improve Petro Rabigh\u2019s balance sheet and cash liquidity as part of a remedial plan that Aramco and Sumitomo Chemical intend to explore with Petro Rabigh, which also includes initiatives to upgrade the refinery to help improve the profitability of the business,\u201d the companies said in their statement \u201cThe agreement also aligns with Aramco\u2019s downstream expansion and Sumitomo Chemical\u2019s move away from commodity chemicals toward specialty chemicals.\u201d Rabigh Refining and Petrochemical Co., known as Petro Rabigh based in Rabigh on Saudi Arabia\u2019s west coast, processes 400,000 b\/d of Arabian Light crude and produces refined products including fuel oil, diesel, gasoline, kerosene, naphtha and LPG. Its ethane gas processing capacity of 1.6 million mt\/year also produces heavy and light oil, naphtha and kerosene. Its petrochemicals include HDPE, PP, LLDP and MEG. The company's accumulated losses as of June 30 were equal to Riyal 8.871 billion ($2.36 billion), Petro Rabigh said in a separate earnings statement on Aug. 7 to the Saudi stock exchange. The company was on the verge of being required to call for an extraordinary general assembly meeting to consider steps to make up for the losses or be dissolved, it said in the statement. Unexpected maintenance, global petrochemicals oversupply, higher feedstock costs announced in January from Aramco and higher freight rates due to Red Sea shipping disruptions have led to the losses. Aramco will now be Petro Rabigh\u2019s largest shareholder, with a 60% stake while Sumitomo Chemical will have 15%. Other shares are traded on the Saudi stock exchange since its IPO in 2008. ","headline":"Petro Rabigh\u2019s refinery to be upgraded after Aramco takes control","updatedDate":"2024-08-07T08:18:58.000"},{"Unnamed: 0":466,"body":null,"headline":" July oil product exports at 4.98 mil mt, down 6% from June","updatedDate":"2024-08-07T04:01:21.000"},{"Unnamed: 0":467,"body":null,"headline":" July crude imports at 10.01 mil b\/d, lowest since Sep 2022","updatedDate":"2024-08-07T04:01:21.000"},{"Unnamed: 0":468,"body":null,"headline":"QatarEnergy raises Sep Land, Marine crude OSPs by 45-75 cents\/b from Aug","updatedDate":"2024-08-07T02:29:11.000"},{"Unnamed: 0":469,"body":null,"headline":"ADNOC sets Upper Zakum September OSP at Murban OSP plus 5 cents\/b","updatedDate":"2024-08-07T01:18:36.000"},{"Unnamed: 0":470,"body":null,"headline":"ADNOC sets Das Blend September OSP at Murban OSP minus 80 cents\/b","updatedDate":"2024-08-07T01:18:36.000"},{"Unnamed: 0":471,"body":null,"headline":"ADNOC sets Umm Lulu September OSP at Murban OSP plus 20 cents\/b","updatedDate":"2024-08-07T01:18:35.000"},{"Unnamed: 0":472,"body":null,"headline":"ADNOC sets Murban September OSP at $83.80\/b, up $1.28\/b on the month","updatedDate":"2024-08-07T01:18:35.000"},{"Unnamed: 0":473,"body":" Marathon Petroleum expects third quarter refinery utilization to fall short of the record-high levels in Q2 because of planned work at some of its US Gulf Coast and Midwest refineries, keeping it in line with expected market conditions, a company executive said Aug. 6. Marathon, which ran its refinery system at 97% capacity with a 94% capture rate in Q2, expects Q3 utilization to fall to 90% of capacity. Marathon CEO Maryann Mannen said on the Q2 results call that Q2 refined product supply reached all-time seasonal highs as refineries returning from a heavy bout of turnaround activity churned out product, creating some short-term volatility. But overall, Mannen said \u201cwe expect 2024 will be another year of record refined product consumption.\u201d \u201cWithin MPC's domestic and export businesses, we are seeing steady demand year over year for gasoline and diesel and growing demand for jet fuel,\u201d she added. Run rates match market expectations Some analysts questioned, however, if the 7 percentage point drop in quarter-to-quarter refinery utilization could be construed as a result of quarter-on-quarter weaker cracks, incentivizing Marathon to exercise some economic refinery downtime and\/or acceleration of planned work. While not directly addressing economic run cuts and weaker crack spreads, Marathon CFO John Quaid noted that the company had turnaround activity planned for the Midwest and US Gulf Coast in Q3. \u201cWe are going to continue to run our assets optimally to meet the demand in the market,\u201d he said. Rick Hessling, Marathon\u2019s chief commercial officer, agreed. \u201cWe will run economically, and 90% is the guidance that we think is a fair number going forward as we're one-third of the way through the quarter,\u201d he said. Neither provided specifics on which refineries are involved and the timing included in the scope of the planned work in Q3. Midwest, USGC targeted for planned work Marathon Petroleum expects Q3 USGC crude throughput to average 1.075 million b\/d, or 88% capacity, compared with the Q2 actual crude throughput of 1.192 million b\/d, which was higher than earlier guidance of 1.150 million b\/d. Marathon\u2019s Galveston Bay refinery, one of the nation\u2019s largest with 631,000 b\/d of crude throughput capacity, was shut for at least a week after losing power when Hurricane Beryl swept through the region July 8, destroying power transmission lines. In the Midwest, Marathon expects Q3 crude throughput to average 1.055 million b\/d compared with 1.157 million b\/d in Q2. The Midwest is experiencing high margins and cracks because of several unplanned regional refinery outages, which have increased margins and cracks and pushed the region's gasoline octane spreads to record levels. US Midwest cracking margins for Bakken crude, which averaged $14.19\/b in Q2, are currently averaging $17.30\/b in Q3 as of Aug. 6. \u201cThe market is tight right now. There have been some notable disruptions in the Midwest that are straining supply and demand,\u201c said Hessling. \u201cThat's definitely been a benefit to us,\" he added. \"While it has widened significantly \u2026. I would say we do expect a slight pullback to stay where it's at probably is overly optimistic. But that being said, constructively right now, the Midwest is high.\u201d ","headline":" Marathon lowers Q3 run rates to meet market conditions","updatedDate":"2024-08-06T21:15:54.000"},{"Unnamed: 0":474,"body":" Democratic presidential candidate Kamala Harris has tapped Minnesota Governor Tim Walz as her running mate, a choice that could potentially underscore the importance of environmental and climate-friendly policies for the Democratic ticket. Environmental groups praised the move. \"The Harris-Walz ticket is one that understands the fight before us, isn't afraid to tackle climate change head-on, and will continue to build upon the legacy of the Biden-Harris administration,\" Sierra Club Executive Director Ben Jealous said in a statement. Indeed, Washington-based research firm ClearView Energy Partners saw Walz\u2019s selection as an effort by Harris to reach out to left-leaning Democratic base voters. \u201cToday\u2019s decision suggests a focus by the Harris campaign on the climate-forward youth voters who could determine outcomes in closely contested \u2018swing\u2019 states,\u201d ClearView said in an Aug. 6 note. The oil and gas industry reacted to the pick by urging policies to cement US energy leadership at a time of geopolitical instability. \u201cWe encourage the Harris-Walz campaign to detail their stance on the key issues that will shape America\u2019s energy future, from LNG exports and federal leasing to permitting reform and consumer choice,\u201d Mike Sommers, the president and CEO of the American Petroleum Institute, said in a statement. Walz has served as the governor of Minnesota since 2019. After Democrats gained full control of the Minnesota legislature in January 2023, Walz signed a clean energy law that requires electric utilities to source 100% of their power from carbon-free sources by 2040. In June, Walz signed legislation to streamline the state energy permitting process, shaving up to a year off the permitting timeline for renewable energy and transmission projects. Before becoming governor, Walz represented a conservative-leaning district of Minnesota in the US House of Representatives from 2007 to 2019. During that time, he was a member and leader of the bipartisan Energy Working Group and showed a willingness to work across the aisle. Walz co-sponsored two energy-related bills in the House, but they never became law. A 2014 bill would have facilitated offshore oil and gas leasing, implemented a loan program to reduce greenhouse gases from coal-fired power generation, and extended tax credits for renewables. Another bill introduced in 2013 would have required refinery owners to report planned outages to the government one year in advance and required the US Energy Secretary to analyze the costs and benefits of creating a national strategic refined petroleum products reserve. Support from progressives, moderates The Walz announcement drew support from both progressive and moderate voices in Congress. Representative Alexandria Ocasio-Cortez, Democrat-New York, wrote on social media that Harris and Walz \"will govern effectively, inclusively, and boldly for the American people.\" Senator Joe Manchin of West Virginia, a former Democrat who recently registered as an independent, said in a statement that Walz \"will bring normality back to the most chaotic political environment that most of us have ever seen.\" \"I can think of no one better than Governor Walz to help bring our country closer together and bring balance back to the Democratic Party,\" said Manchin, chairman of the Senate Committee on Energy and Natural Resources. In an Aug. 6 statement, the Trump-Vance campaign criticized Walz for \"proposing his own carbon-free agenda\" and advocating for \"stricter emissions standards for gas-powered cars.\" Minnesota is one of over a dozen states that have adopted California's tailpipe rules requiring an increasing percentage of zero-emission vehicle sales. However, Minnesota has signaled it has no immediate plans to follow California in banning the sale of new gas-powered vehicles beginning in 2035. Walz is expected to campaign on the Biden-Harris administration's environmental track record. Since the Inflation Reduction Act was passed in August 2022, at least 30 clean energy and manufacturing projects have been announced in the swing state of Michigan alone, representing nearly $12 billion in investment and more than 12,000 jobs, according to the business group E2. Projects representing hundreds of millions of dollars have also been announced in Pennsylvania and Wisconsin. The Harris-Walz campaign \"is far more likely to stress clean energy incentives as an example of policies that promote American energy,\" Scott Segal, co-chair of Bracewell's Policy Resolution Group, said in an interview. \"That's going to be important because there's so much money being invested in clean energy, including in those Blue Wall states.\" Segal noted that Walz is also a strong supporter of biofuels such as ethanol. Midwestern states accounted for about 93% of US ethanol production in 2023, according to the US Energy Information Administration. \"He's been supportive of carbon-free electric generation, but on the other hand, he's also supportive of biofuels,\" Segal said. \"And the amount of ethanol used in an EV is exactly zero.\" In Minnesota, Walz created the Governor\u2019s Council on Biofuels, and he signed a state sustainable aviation tax credit into law. Allan Marks, a partner at Milbank, added that Walz could prove to be a valuable governing partner for Harris under a divided government scenario. \"If you have the Republicans controlling one or both houses in Congress, that's a very different dynamic,\" Marks said in an interview. \"There, I think she'd have to lean on Tim Walz for something different, which is his ability to work across the aisle from when he was a member of the House.\" Walz\u2019s record has demonstrated his ability to \u201cwalk the walk\u201d on energy issues in a purple state, said Mona Dajani, global co-chair of energy, infrastructure, and hydrogen at Baker Botts. \u201cHe has made Minnesota a national leader on clean energy, and he was able to accomplish this in a purple state with only a very thin Democratic majority in the legislature. That\u2019s a big deal,\u201d she said. Mining interests Minnesota is home to several mining projects, including Antofagasta unit Twin Metals Minnesota's proposed copper-nickel Maturi project and Glencore and Teck Resources' joint NorthMet diversified metals project. Walz has largely avoided getting involved in the continuous legal debates and a federal land withdrawal surrounding the projects. However, Julie Lucas, executive director of industry group MiningMinnesota, told S&P Global Commodity Insights that he has expressed support for Minnesota's environmental standards for mining projects. MiningMinnesota includes Twin Metals in its ranks. That regulatory support, coupled with Walz's recognition of the critical minerals needed to achieve net-zero goals, is likely to define the governor's approach to mining issues at the federal level. Walz \"has always recognized that clean energy is built with minerals,\" Lucas said. \"Governor Walz is well aware of Minnesota's massive resources for copper and nickel, and so my hope is that he carries that into this role and that we can have a bigger conversation about what not just Minnesota, but what other states can produce as well.\" ","headline":" Harris picks climate-friendly Minnesota Gov. Tim Walz as running mate","updatedDate":"2024-08-06T20:38:53.000"},{"Unnamed: 0":475,"body":" M11 Industries, a subsidiary of MK Agrotech, has commenced operations at its biodiesel plant in the Indian state of Karnataka, the company said Aug. 6. The Rupees 3.65 billion ($43.5 million) plant will convert used cooking oil and other waste oils into biodiesel and has a production capacity of around 450 mt\/day (164,250 mt\/year), making it the largest biodiesel plant in India, according to the company. The biodiesel produced will be supplied to oil marketing companies aiming to reduce the country's import dependency and meet the 5% blending mandate. India has set a target to achieve a 5% blending mandate for biodiesel with conventional diesel by 2030, announced in the National Policy on Biofuels, 2018. The blending mandate is part of broader initiatives to encourage the production and use of biofuels in India, including the National Policy on Biofuels, which aims to increase the usage of biofuels in the energy and transportation sectors to promote sustainable development, reduce greenhouse gas emissions, and improve the overall energy mix. Platts, part of S&P Global Commodity Insights, assessed Biodiesel FOB Southeast Asia at $1,016\/mt Aug. 6, down $27 from the previous assessment. ","headline":"India's M11 starts up major biodiesel facility in Karnataka state","updatedDate":"2024-08-06T17:08:42.000"},{"Unnamed: 0":476,"body":null,"headline":"US oil output to average 13.23 million b\/d in 2024, 13.77 million b\/d in 2025: EIA","updatedDate":"2024-08-06T16:37:48.000"},{"Unnamed: 0":477,"body":null,"headline":"US EIA lowers 2024 oil price outlook by $1.82 to $80.21 for WTI, by $1.93 to $84.44 for Brent","updatedDate":"2024-08-06T16:37:48.000"},{"Unnamed: 0":478,"body":null,"headline":"US EIA lowers world liquid fuels consumption forecast to 1.6 million b\/d increase in 2025","updatedDate":"2024-08-06T16:37:48.000"},{"Unnamed: 0":479,"body":null,"headline":"US EIA forecasts average retail gasoline price at $3.38\/gal in 2024, $3.33\/gal in 2025","updatedDate":"2024-08-06T16:37:48.000"},{"Unnamed: 0":480,"body":" Saudi Aramco CEO Amin Nasser said Aug. 6 that global oil demand is expected to grow by 1.6 million b\/d to 2 million b\/d this year, with the market currently \u201coverreacting\u201d to US recession fears. The demand growth currently is being driven by jet fuel, gasoline and petrochemicals, he told reporters on a media call. In March, Nasser had forecast global oil demand growth of 1.5 million b\/d for 2024. Jet fuel demand is almost back to before COVID-19 levels, CFO Ziad Murshed also said on the call. \u201cThe market in my view is overreacting and the fundamentals do not support the drop we are witnessing today,\u201d Nasser said. \"The market is reading too much into the short-term responses to the news coming from the US with regard to the number of jobs.\" US refineries operated at a 93% utilization rate for the past three months, a record high, he noted. The Platts-assessed Dated Brent crude tumbled 2% to $76.70\/b on Aug. 5, the lowest since June 5, following declines in oil futures and global equities. In the second quarter, Dated Brent had gained 8.7% to an average $84.89\/b from $78.07\/b in the same period a year earlier, according to S&P Global Commodity Insights data. Earlier in the day, Aramco said its second-quarter capital expenditures rose almost 16% to $12.1 billion from $10.46 billion in the same period a year earlier. The forecast for total spending this year remains at $48 billion to $52 billion, Nasser told analysts on a separate call. Last year, spending was $49.7 billion. Crude oil prices were higher in Q2 over the first quarter due to \"easing inflationary pressures, expected seasonal demand growth and falling global crude oil inventory stocks,\" the company said in a statement. The Q2 revenue rose 5.8% on the year to $113.5 billion due to higher prices of crude oil, chemicals and refined products sold, along with more volumes sold from refining and chemicals. Crude oil sales, however, declined, it said. OPEC kingpin Saudi Arabia, which co-chairs the OPEC+ alliance with Russia and has led the group\u2019s efforts to bolster prices, has held its crude production below 10 million b\/d since June 2023. The country pumped 8.98 million b\/d in June after reaching 8.95 million b\/d in December 2023, the lowest since May 2021, according to the Platts survey by Commodity Insights. Refining and other downstream operations used 52% of its Q2 crude oil production, Aramco said. Exploration activity in Q2 saw seven oil and gas discoveries, including two unconventional oil fields, one Arabian light oil reservoir, two natural gas fields and two natural gas reservoirs. Exploration continues for crude oil in support of maintaining its maximum sustained capacity of 12 million b\/d and \"preserving Aramco's distinct operational flexibility,\" it said. Nasser forecast the company will have 300 rigs drilling for oil and gas by the end of this year, up from 2021, even after some contracts were canceled. In January, the government ordered Aramco to cancel a planned expansion of its maximum sustained capacity for crude oil production to 13 million b\/d, with the focus switched to increasing gas production. The Dammam project will add oil production capacity of 25,000 b\/d later in the year, while 50,000 b\/d in 2027 is under construction, the company said. Procurement and construction continued for both the Marjan project -- expected to add 300,000 b\/d of production capacity by 2025 -- and the Berri project, which is expected to add 250,000 b\/d by 2025 as well. Further, the Zuluf crude oil increment, which is expected to provide a central facility to process a total 600,000 b\/d of crude from the Zuluf field by 2026, moved forward with engineering, procurement and construction activities, according to the statement. The plan to increase gas production by more than 60% by 2030, from a 2021 base, is moving ahead at the Jafurah gas plant, the Tanajib gas plant and the Hawiyah Unayzah gas reservoir storage. The Platts-assessed LNG benchmark JKM in Asia averaged $11.25\/MMBtu in Q2, up 3.2% from $10.90\/MMBtu a year earlier, according to Commodity Insights data. Aramco also awarded 23 unconventional rig contracts for $2.4 billion and two directional drilling contracts for $600 million. Production from the Jafurah gas development is expected to reach a sustainable sales gas rate of 2 Bcf\/d by 2030, along with production of ethane, NGLs and condensate. The Tanajib gas plant -- part of the Marjan development program -- is expected to be onstream by 2025 and add 2.6 Bcf\/d of additional processing capacity from the Marjan and Zuluf fields. Moreover, the Hawiyah Unayzah gas reservoir storage -- the first underground natural gas storage in the country -- started reproduction of stored gas into the master gas system, providing up to 2 Bcf\/d of natural gas into the master gas system based on demand, the company said. ","headline":"Aramco CEO raises 2024 oil demand growth forecast to as much as 2 mil b\/d","updatedDate":"2024-08-06T11:41:28.000"},{"Unnamed: 0":481,"body":null,"headline":"Aramco CEO says oil market 'overreacting' to US recession fears","updatedDate":"2024-08-06T08:32:23.000"},{"Unnamed: 0":482,"body":null,"headline":"Aramco CEO raises 2024 global oil demand growth to 1.6 mil-2 mil b\/d from 1.5 mil b\/d","updatedDate":"2024-08-06T08:32:22.000"},{"Unnamed: 0":483,"body":null,"headline":"Global oil demand growth driven by jet fuel, gasoline: Aramco CEO Nasser","updatedDate":"2024-08-06T08:32:22.000"},{"Unnamed: 0":484,"body":null,"headline":"Aramco CEO says US refining utilization at record 93% over past three months","updatedDate":"2024-08-06T08:32:22.000"},{"Unnamed: 0":485,"body":null,"headline":"Jet fuel demand 'barely' reaching pre-COVID-19 level: Aramco","updatedDate":"2024-08-06T08:32:22.000"},{"Unnamed: 0":486,"body":" Japan's Osaka Gas said Aug. 6 it has signed a long-term heads of agreement with Abu Dhabi National Oil Company for the delivery of up to 800,000 mt\/year of LNG on an ex-ship basis, marking the first long-term LNG deal between the two companies. The LNG will be primarily sourced from the Ruwais LNG project, which is currently under development in Al Ruwais Industrial City, Al Dhafra, Abu Dhabi and expected to start commercial operations in 2028. An Osaka Gas spokesperson declined to specify the exact duration of the supply period and the contractual terms, including a pricing basis and destination restrictions, other than saying the contract spans a long-term period from the late 2020s. The Osaka Gas spokesperson, however, described the deal as a result of the company's overall consideration of \"favorable contractual terms and conditions\" being offered, noting the need for LNG as a key transition fuel for achieving carbon neutrality. Following the agreement, Osaka Gas said it will work with ADNOC to conclude a detailed sale and purchase agreement in the coming months based on the terms of the HOA. Under the agreement, LNG cargos will be shipped to the destination ports of Osaka Gas and its Singapore-based subsidiary, Osaka Gas Energy Supply and Trading (OGEST). The deal comes after ADNOC said July 10 that Japan's Mitsui alongside BP, Shell and TotalEnergies were to be awarded in the Ruwais LNG project with a 10% stake each, with the UAE's state-owned company retaining a 60% stake and serving as the lead developer and operator of the 9.6 million mt\/year Ruwais LNG plant. In a separate statement, ADNOC said the agreement with Osaka Gas brings its long-term sales commitments with international partners to 70% of the Ruwais project's total production capacity. ","headline":"Japan's Osaka Gas signs long-term deal to buy up to 800,000 mt\/year LNG from ADNOC","updatedDate":"2024-08-06T08:06:12.000"},{"Unnamed: 0":487,"body":" Saudi Aramco maintained its medium- and long-term demand forecasts on Aug. 6, with 52% of crude oil production output used in refining and other downstream operations in the second quarter of 2024. Total hydrocarbons output in Q2 was 12.3 million boe\/d, Aramco said in a statement to the Saudi stock exchange. In March, CEO Amin Nasser said he expected oil demand growth of about 1.5 million b\/d in 2024. Crude oil prices were higher in the second quarter than the first quarter due to \"easing inflationary pressures, expected seasonal demand growth and falling global crude oil inventory stocks,\" the company said. The Q2 revenue rose 5.8% on the year to $113.5 billion, due to higher prices of crude oil, chemicals and refined products sold, along with more volumes sold from refining and chemicals. Crude oil sales, however, declined, it said. Refining and other downstream operations used 52% of Q2 crude oil production. Exploration in Q2 saw seven oil and gas discoveries, including two unconventional oil fields, one Arabian light oil reservoir, two natural gas fields and two natural gas reservoirs. Exploration continues for crude oil in support of maintaining its maximum sustained capacity of 12 million b\/d and \"preserving Aramco's distinct operational flexibility.\" The Dammam project will add oil production capacity of 25,000 b\/d later in the year, while 50,000 b\/d in 2027 is under construction, the company said. Procurement and construction continued for both the Marjan project -- expected to add 300,000 b\/d of production capacity by 2025 -- and the Berri project, which is expected to add 250,000 b\/d by 2025 as well. Further, the Zuluf crude oil increment, whch is expected to provide a central facility to process a total of 600,000 b\/d of crude from the Zuluf field by 2026, moved forward with engineering, procurement and construction activities, according to the statement. In January, the government ordered the company to cancel a planned expansion of its maximum sustained capacity to 13 million b\/d, with the focus switched to increasing natural gas production. The plan to increase gas production by more than 60% by 2030, from a 2021 base, is moving ahead at the Jafurah gas plant, the Tanajib gas plant and the Hawiyah Unayzah gas reservoir storage. Aramco also awarded 23 unconventional rig contracts for $2.4 billion and two directional drilling contracts for $600 million. Production from the Jafurah gas development is expected to reach a sustainable sales gas rate of 2 Bcf\/d by 2030, along with production of ethane, NGL and condensate. The Tanajib gas plant -- part of the Marjan development program -- is expected to be onstream by 2025 and add 2.6 Bcf\/d of additional processing capacity from the Marjan and Zuluf fields. Morever, the Hawiyah Unayzah gas reservoir storage -- the first underground natural gas storage in the country -- started reproduction of stored gas into the master gas system, providing up to 2 Bcf\/d of natural gas into the master gas system based on demand, the company said. ","headline":"Saudi Aramco 'confident' in its oil demand growth forecasts","updatedDate":"2024-08-06T07:18:28.000"},{"Unnamed: 0":488,"body":null,"headline":"Aramco reports 52% downstream use of crude output in Q2","updatedDate":"2024-08-06T06:04:10.000"},{"Unnamed: 0":489,"body":null,"headline":"Aramco posts Q2 hydrocarbons output at 12.3 mil boe\/d","updatedDate":"2024-08-06T06:04:09.000"},{"Unnamed: 0":490,"body":null,"headline":"Saudi Aramco 'confident' in its forecasts for medium, long-term demand growth","updatedDate":"2024-08-06T06:04:08.000"},{"Unnamed: 0":491,"body":" Crude oil futures settled lower Aug. 5 as traders weighed recession fears and downward pressure from steep selloffs in global financial markets against mounting geopolitical risks to supply. NYMEX September WTI settled 58 cents lower at $72.94\/b and ICE October Brent declined 51 cents to $76.30\/b. Fears of slowing economic growth saw Japan's Nikkei 225 Index plunge more than 12% Aug. 5, its biggest fall since 1987. The selloff sparked concordant moves in major indexes around the globe; in the US, the tech-heavy Nasdaq was down 3.8% and the S&P 500 dipped 3.3% in afternoon New York trading. \"With demand indicators looking soft and jobless claims on the rise, the risks are skewed towards unemployment increasing more rapidly\", which in turn increases the \"likelihood of recession\", said James Knightley, the chief US economist at ING. The selloffs come on the heels of a weaker-than-expected US employment report Aug. 2 that showed a 4.3% US unemployment rate and limited payrolls growth, adding to the mounting fears of an economic slowdown. \"Rising volatility forces investors to cut exposure across the board, hence the spillover to commodities from the current rout in equities,\" said Ole Hansen, Saxo's head of Commodity Strategy, Aug. 5. Trading curbs were activated in South Korea for the first time in four years after equities tumbled through early trade. Japanese stocks also sank into a bear market. \"The talk of the town has been the contagion effect of this multi-pronged bear assault, which now seems to have shifted into a self-perpetuating mode,\" said SPI Asset Management Managing Partner, Stephen Innes. \"The global markets are facing a barrage of crises, making any hopes of a Monday recovery rally seem like a distant fantasy,\" Innes said, echoing multiple analysts of the view that the US Federal Reserve may now be behind the curve in their interest rate cut cycle. The market is now pricing an 85.5% chance that the Fed cut interest rates by 50 basis points following the September Federal Open Market Committee meeting. NYMEX September RBOB rallied 1.6 cents to settle at $2.3336\/gal, while September ULSD dipped 1.99 cents to $2.2986\/gal. Oil markets remained backstopped by rising geopolitical threats to supply, analysts said. \"Geopolitical risks continue to hang over the oil market. Participants are waiting to see how Iran responds to the assassination of the political leader of Hamas on Iranian soil,\" said ING Strategists Warren Patterson and Ewa Manthey. Meanwhile, Libya's largest oilfield was taken completely offline Aug. 5 , after the son of eastern warlord Khalifa Haftar ordered a shutdown in response to a European arrest warrant, according to sources. Output at the huge Sharara Field, which had been producing roughly 250,000 b\/d of oil, initially fell to around 100,000 b\/d after protesters entered the operations room Aug. 4, before ceasing by 1600 GM, two sources confirmed. ","headline":" Crude slides as global equity selloff stokes recession fears","updatedDate":"2024-08-05T20:11:18.000"},{"Unnamed: 0":492,"body":" Libya\u2019s largest oilfield was taken completely offline Aug. 5, after the son of eastern warlord Khalifa Haftar ordered a shutdown in response to a European arrest warrant, according to sources. Output at the huge Sharara Field, which had been producing roughly 250,000 b\/d of oil, initially fell to around 100,000 b\/d after protesters entered the operations room Aug. 4, sources told S&P Global Commodity Insights, before ceasing by 1600 GM, two sources confirmed. Under 10,000 b\/d was still flowing to the Awbari power station, a source familiar with the matter said. Akakus, the joint-venture company that operates the field, had said in a statement that production was stopping \u201cgradually,\u201d without giving any details. Akakus is a JV between Libya's National Oil Corp. and Spain\u2019s Repsol, France\u2019s TotalEnergies, Austria\u2019s OMV and Norway\u2019s Equinor. There has been no declaration of force majeure as yet and none of the partners has commented on the issue, apart from OMV, which acknowledged a reduction in output starting on Aug. 4 and extending into Aug. 5. A spokesperson for Austrian company said they were \"unaware of the causes.\" \u2018Political blackmail\u2019 Unlike a similar two-week closure by protesters in January over socioeconomic woes, three sources told Commodity Insights the latest shutdown was ordered by Saddam Haftar, whose father dominates the divided country\u2019s eastern government in Benghazi. In a statement on social media on Aug. 5, the western Government of National Unity in Tripoli -- which is recognized by the United Nations -- slammed the closure of the Sharara Field as \u201cnew attempts at political blackmail\u201d, calling the oil field an \u201ceconomic artery\u201d for the country. Bashir al-Sheikh, the leader of the southwestern Fezzan Movement, which has shut oil fields in the past, said his movement had nothing to do with the closure and that Saddam Haftar had issued the order. The shutdown is understood to relate to an investigation by Spanish authorities into Saddam Haftar, focused on an alleged botched drone deal, which led to an arrest warrant being issued. Sources said the closure was designed to pressure Spanish authorities. \u201cThis move is unlikely to influence the Spanish police, known for their independence even in high-profile cases against the Spanish king himself,\u201d a source said. \u201cUnconfirmed reports suggest some Spanish employees were arrested in Sharara yesterday during the closure incident.\" The LNA could not be immediately reached for comment. Its leaders have not commented on the shutdown, or the allegations around Saddam Haftar. Market impact A closure backed by Haftar\u2019s Libyan National Army marks a concerning return to oil output disruptions by political actors in the North African country. Zhuwei Wang, a senior analyst at Commodity Insights, said it was \"bullish\" for light sweet crude differentials in the Mediterranean region given that more than 60% of Libyan crudes are exported to the region. The LNA carried out regular oil and gas blockades until 2022, reducing Libya's output to just 650,000 b\/d in June of that year. The blockades largely stopped after the appointment of Farhat Bengdara as chairman of NOC in July 2022. Since then, production and exports have risen to multi-year highs. In June, Libya pumped 1.16 million b\/d of crude, according to the Platts OPEC Survey from Commodity Insights, still well below the 1.6 million b\/d it was producing before the NATO-backed ouster of Moammar Qadhafi in 2011, which plunged Libya into chaos. The country\u2019s light sweet crudes are a popular feedstock for refiners in the Mediterranean and Northwest Europe. Libya controls Africa\u2019s largest oil reserves, estimated at 48 billion barrels. NOC plans to increase production to 2 million b\/d within the next five years, through 45 greenfield and brownfield projects. It is planning a bid round at the end of 2024, but political unrest and difficulties attracting project financing threaten its production plans. In recent months, key oil and gas negotiations with IOCs including over the NC-7 and Waha projects, have been caught up in the country\u2019s political chaos. ","headline":"Output halted at Libya\u2019s 300,000 b\/d Sharara Field on orders of warlord's son: sources","updatedDate":"2024-08-05T16:33:16.000"},{"Unnamed: 0":493,"body":null,"headline":"Internationally recognized Tripoli government slams oil field closure as 'political blackmail'","updatedDate":"2024-08-05T16:27:08.000"},{"Unnamed: 0":494,"body":null,"headline":"Production halted at Libya\u2019s 300,000 b\/d Sharara Field on orders of warlord's son: sources","updatedDate":"2024-08-05T16:27:08.000"},{"Unnamed: 0":495,"body":" Iraq\u2019s total federal crude exports rose 76,000 b\/d on the month to 3.486 million b\/d in July, according to an export table issued by Iraqi state oil marketer SOMO Aug. 3 and seen by S&P Global Commodity Insights. This increase comes despite Iraq\u2019s plans to comply with its OPEC+ commitments and compensate for overproduction in the first half of 2024. It pledged to cut an additional 70,000 b\/d of crude output in July to compensate for producing above quota in the first half of 2024. Its compensation plan includes additional cuts of at least 70,000 b\/d through September 2025. Previously Iraq said that it would hold crude exports at 3.3 million b\/d as it aims to improve compliance. Iraq is the OPEC+ alliance\u2019s largest overproducer. It produced a total of 1.184 million barrels above target in the first half of the year. SOMO reported that Iraq exported 3.424 million b\/d from the southern Gulf terminals in July, up 24,000 b\/d on June levels. No oil was supplied by truck to Jordan -- down from 10,000 b\/d in June. While 62,000 b\/d of Qayara heavy crude was exported from the southern port of Khor al-Zubair in July, up from zero in June. Previously the Iraqi Oil Ministry released provisional export figures at the start of the month but has not done so since March. Qayara crude exports were up to around double the normal rate due to withdrawal of around 990,000 barrels from the oil field stock that accumulated due to the suspension of exports in May and June. This was due to contractual problems with trucking contractors. Gulf terminals exported 2.230 million b\/d of Basrah Medium crude, up from 2.217 million b\/d in June. Exports of Basrah Heavy crude stood at 1.194 million b\/d, compared with 1.183 million b\/d in June, the data showed. Basrah Heavy has an average API gravity of 23-24 degrees, while Basrah Medium has a contractual API gravity of 29. Crude exports via northern Iraq, including the semi-autonomous Kurdistan region, remain suspended. Pipeline exports to the Turkish port of Ceyhan were halted more than 16 months ago, when Turkish authorities closed the pipeline, in the wake of an international arbitration ruling that independent Kurdish crude sales were illegal. Iraq crude exports June July change Basrah Medium 2.217 2.230 0.013 Basrah Heavy 1.183 1.194 0.011 Trucked to Jordan 0.010 0 -0.01 Heavy Qayara crude 0 0.062 0.062 Kirkuk grade 0 0 0 Kurdish Blend Test 0 0 0 TOTAL 3.410 3.486 0.076 Unit: million b\/d Source: SOMO data Attempts to reach a deal on reopening the pipeline have stalled on political and financial disputes involving federal Iraqi authorities, the Kurdistan Regional Government and international oil companies operating in Kurdistan. Prior to the shutdown exports via the route were typically around 375,000 b\/d of Kurdish Blend Test and 75,000 b\/d of federally produced Kirkuk grade. In the absence of pipeline exports, a domestic market has sprung up in the Kurdistan region with local refineries and hundreds of topping plants buying as much as 300,000 b\/d of local crude, Commodity Insights has reported. The SOMO data also showed that stock levels of Kurdish-produced crude at Ceyhan remain stagnant at around 1.043 million barrels, and federal Kirkuk grade stocks were also steady at 531,000 barrels. But inventories at Iraq\u2019s southern depots decreased by 660,000 barrels during the month, standing at 3.700 million barrels, or around 40% of the southern storage capacity of 9.310 million barrels. Qayara stocks in northern Iraq decreased by 990,000 barrels, from 1.350 million barrels to 360,000 barrels. This withdrawal was shipped for export, resulting in Qayara exports doubling. Iraq\u2019s net decrease in stocks was 1.650 million barrels in July, equivalent to 53,000 b\/d, which was diverted to support exports. ","headline":" Crude exports rise again in July, despite OPEC+ cut commitments","updatedDate":"2024-08-05T14:29:47.000"},{"Unnamed: 0":496,"body":" ADNOC Drilling said its contract with Jordan has been extended until at least the end of 2024, adding to new exploration in the UAE and possibly Kuwait as the search for crude oil and natural gas in the Middle East spreads. The contract is for its AD-137 land rig operating in Jordan since the fourth quarter of 2023, ADNOC Drilling said in an Aug. 5 statement. That adds to the $1.7 billion contract awarded by Abu Dhabi National Oil to ADNOC Drilling in May to explore for unconventional oil and natural gas resources in the UAE. ADNOC owns 75.8% of ADNOC Drilling. Also in May, ADNOC Drilling said it received approval by Kuwait Oil Co. to tender for drilling, rig and other services, opening the door to expand its activities into Kuwait. The company on Aug. 5 said it raised its estimate for 2024 revenue to $3.7 billion-$3.85 billion, from its previous guidance of $3.6 billion-$3.8 billion, after reporting a 29% year-on-year increase in second-quarter revenue to a record $935 million. ADNOC Drilling raised the onshore business outlook for 2024 revenue to $1.65 billion-$1.75 billion, from $1.6 billion-$1.7 billion previously. For the second quarter, onshore revenue increased 27% on the year to $441 million, mainly due to new rigs put into operation. The offshore jack-up revenue soared 48% over the same period to $284 million. At the end of June, the company\u2019s fleet consisted of 140 rigs, up from 137 at the end March. ","headline":"ADNOC Drilling says Jordan extends contract until end-2024","updatedDate":"2024-08-05T10:10:49.000"},{"Unnamed: 0":497,"body":null,"headline":"Saudi Aramco cuts all US-bound Sep OSPs by 75 cents\/b","updatedDate":"2024-08-05T01:49:25.000"},{"Unnamed: 0":498,"body":null,"headline":"Saudi Aramco cuts all Europe, Med-bound Sep OSPs by $2.75\/b","updatedDate":"2024-08-05T01:49:23.000"},{"Unnamed: 0":499,"body":null,"headline":"Saudi Aramco maintains or raises Asia-bound Sep crude OSPs by 10-20 cents\/b","updatedDate":"2024-08-05T01:49:23.000"},{"Unnamed: 0":500,"body":" Production at Libya's Sharara oil field, the country's biggest, was partially suspended on Aug. 4 after protestors entered the operations room, sources told S&P Global Commodity Insights. Estimates of production lost ranged from 28,000-70,000 b\/d, although it couldn't be determined what current production was. Sharara has a maximum capacity of 320,000 b\/d with recent production at 250,000 b\/d. A source at Libya's National Oil Corp said that the disruptors were taking steps to reduce output to zero. The partial closure has been sanctioned by the Libyan National Army, one source said. The LNA is under the command of eastern warlord Khalifa Haftar, whose troops carried out regular blockades in recent years, reducing Libya's output to just 650,000 b\/d in the summer of 2022. The blockades largely stopped after the appointment of Farhat Bengdara as chairman of NOC. The latest disruption follows a shutdown at the field in January which lasted for two weeks. Libya then imposed a force majeure at the project after protestors from the Southwestern Ubari region closed the field to protest rising fuel prices, poor economic opportunity and unemployment. Sharara is a joint venture between Libya\u2019s NOC, France\u2019s TotalEnergies, Spain\u2019s Repsol, Austria\u2019s OMV and Norway\u2019s Equinor. The companies did not immediately respond to requests for comment. Output challenges Libya controls Africa\u2019s biggest oil reserves, estimated at 48 billion barrels and has ambitious plans to increase production in the mid-term. In early 2024, NOC Chairman Farhat Bengdara noted plans to increase production to 2 million b\/d within the next five years. He said at the time that 45 greenfield and brownfield projects would contribute to the increase. It is planning a bid round at the end of 2024, but political unrest and difficulties attracting project financing threaten its production plans. Relative political stability has kept Libya\u2019s crude output at around 1.15 million b\/d since February 2024. It produced 1.16 million b\/d in June, up from 1.15 million b\/d in May, according to the Platts OPEC+ production survey by Commodity Insights. This is well below the 1.6 million b\/d it was producing before the toppling of Moammar Qadhafi in 2011. Libyan crude is typically light, low in sulfur and yields a good amount of middle distillates and gasoline, making it popular in the Mediterranean and Northwest Europe. ","headline":"Libya's Sharara oil field partially shut due to protests","updatedDate":"2024-08-04T12:06:34.000"},{"Unnamed: 0":501,"body":" Crude oil futures settled sharply lower Aug. 2, retreating to two-month lows on demand growth concerns stoked by a weaker-than-expected US report. NYMEX September WTI settled down $2.79 at $73.52\/b, and ICE October Brent declined $2.71 to $76.81\/b. US employers added 114,00 workers to payrolls in July, Labor Department data showed Aug. 2, down 36% from the month prior and well under market expectations. The weak jobs print pushed the unemployment rate up to 4.3%, the highest since October 2021. \"Today's employment situation report cast a pall on the US economy, and its implications reverberated throughout all markets,\" said NinjaTrader analyst Tom Schneider, adding that oil prices were falling \"on worries that an economic slowdown will crush crude oil demand.\" The weaker-than-expected jobs report comes on the heels of Aug. 1 data showing continued contraction in the US manufacturing sector last month. The Institute for Supply Management's July manufacturing purchasing managers' index fell for a fourth straight month to 46.8% in July, down 1.7 percentage points from 48.5% in June. \"A stag-flationary reading from the ISM on manufacturing caused a massive retreat in stocks that drug down petroleum [Aug. 1],\" Price Futures Group analyst Phil Flynn said. \"Lower expansion, less jobs and higher prices paid freaked out stocks putting more importance on today's monthly unemployment report.\" NYMEX September RBOB fell 8.04 cents to $2.3176\/gal, and September ULSD dipped 8.79 cents to $2.3185\/gal. Markets remained in wait-and-see mode regarding potential escalation of Middle East tensions. \"The market will continue to follow developments in the Middle East and, in particular, on what form Iranian retaliation might take and whether that poses a risk of escalation,\" Callum Macpherson, head of commodities at Investec, said in a note Aug. 2. Both Iran and Hezbollah have indicated they are primed to retaliate against Israel, which recently claimed responsibility for the assassination of a slew of high-ranking militant leaders in the Middle East. \"The more Iran gets directly involved, the more risks of oil supply disruption grows,\" Ewa Manthey, commodities strategist, and Warren Patterson, head of commodities strategy at ING said in a note. ","headline":" Crude hits two-month lows as weak US jobs data stokes demand concerns","updatedDate":"2024-08-02T19:51:03.000"},{"Unnamed: 0":502,"body":" Production decline at Azerbaijan's flagship ACG oil complex slowed to 9% year on year, data published by BP on Aug. 2 showed, reflecting the April startup of the new Azeri Central East platform. In a statement, BP said production for the first half of 2024 had averaged 336,000 b\/d, a 10% drop year on year. However, in the second quarter, production was down 9% year-on-year at 333,000 b\/d, compared with a 12% year-on-year drop in Q1 2024. The $6 billion ACE project came on stream in April, becoming the seventh production center at the Azeri Chirag Gunashli complex and the first to be added since 2014. So far, ACE is producing from just one well, with output averaging 8,000 b\/d, however, this is set to rise to 24,000 b\/d by year-end with the addition of two more wells, BP reiterated. The Azeri Light crude stream, loaded at Ceyhan on Turkey's Mediterranean Coast, is sought-after for production of jet fuel and middle distillates such as diesel. Prices for the grade have fluctuated this year amid disruptions to exports out of the Mediterranean to Asia stemming from attacks on shipping in the Red Sea. However, Azeri Light loaded at Ceyhan was assessed by Platts at a $2.04\/b premium to Dated Brent on Aug. 1. BP confirmed no cargos of Azeri Light had been sent from the Sangachal terminal on the Caspian coast to Georgia's Black Sea coast via the alternative Baku-Supsa pipeline route. Azeri Light flows continue to be supplemented with condensate from the BP-operated Shah Deniz gas field, with condensate volumes steady at around 99,000 b\/d in the first half of 2024. The Baku-Tbilisi-Ceyhan pipeline shipped 4% less oil in the first half of the year compared with a year earlier, at 604,000 b\/d; volumes were also supplemented with oil shipped across the Caspian to Baku from Kazakhstan and Turkmenistan, as well as from Azeri fields operated by state Socar, BP said. ","headline":"Azerbaijan ACG oil production decline slows after new platform startup: BP","updatedDate":"2024-08-02T15:47:23.000"},{"Unnamed: 0":503,"body":" ExxonMobil pushed back its time frame for the startup of the Golden Pass LNG export terminal to late 2025 on Aug. 2, a delay of about six months after the lead contractor building the Texas facility declared bankruptcy. \u201cRight now, our estimate is we're going see about a six-month slippage,\u201d ExxonMobil's CEO Darren Woods told investors during a second-quarter earnings call. \u201cWe now are looking at probably the back end of 2025 for first LNG.\u201d The oil and gas giant provided the revised timeline for Golden Pass about a week after a federal bankruptcy court approved a settlement between the joint venture partners building the project and lead contractor Zachry Group on July 24, allowing the remaining contractors to ramp up construction. Zachry filed for Chapter 11 bankruptcy in May, blaming its work on the project for the company\u2019s financial stress. It cited cost overruns stemming from unexpected obstacles, including soil conditions at the site, the pandemic and supply chain constraints. The setbacks at Golden Pass have contributed to a tighter global supply picture than expected for 2025. Before the new timeline, ExxonMobil\u2019s most recent estimate for bringing Golden Pass online was first-half 2025, a delay from a previous target of late 2024. The project will have a peak capacity of about 18.1 million mt\/year. Qatar Energy owns 70% of Golden Pass, while ExxonMobil owns 30%. The energy giants agreed in 2022 to independently market their own shares of LNG production from Golden Pass after reaching a final investment decision on the project in 2019. During the earnings call, Woods said that the venture building Golden Pass is in the process of restaffing and getting back to work, with a focus on bringing the project online as close to the original schedule as possible. \u201cThe teams are just getting back up and running, and they have a clear mandate to try to bring that in as effectively as they can,\u201d Woods said. \u201cMy expectation is they will do better than we currently think, but we've got work to do.\u201d ","headline":"ExxonMobil delays timeline for Golden Pass LNG startup to late 2025","updatedDate":"2024-08-02T15:14:43.000"},{"Unnamed: 0":504,"body":" Global energy trader Vitol has agreed to acquire Hong Kong-based Noble Resources Trading, both companies said Aug. 2, in a move that is expected to grow Vitol's coal trading business. The deal is expected to close before the end of this year for $0.63 per share, said Vitol. Noble Resources added that the purchase price was $208.9 million on a debt-free basis. Noble Resources was formerly a wholly-owned subsidiary of the Noble Group, formerly a major trading firm listed in Singapore. In 2015, questions over its accounting practices had plunged the firm into crisis and triggered a fire sale of its business units, resulting in it being delisted from the Singapore Exchange in 2022. Noble Resources had been under new ownership and management since December 2018, and the company reiterated that it is a separate business from the Noble Group. ","headline":"Energy trader Vitol expands coal business with Noble Resources acquisition","updatedDate":"2024-08-02T08:55:02.000"}] \ No newline at end of file