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MABUX ARA LNG Bunker Index
Port LNG$/mton MGO LS$/mton Date
ARA
1 449.00
+93.00
1 405.00
+20.00
Sep 7
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Port	LNG$/mton	MGO LS$/mton	Date
ARA	1 449.00	+93.00	1 405.00	+20.00	Sep 7

MABUX Global Bunker Index

380HSFO$/mton		VLS FO$/mton		MGO LS$/mton		Date
681.78	+8.99	838.68	+8.73	1 481.05	+17.34	Sep 11

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MABUX Market Differential Index (MDI)

Correlation between market bunker prices (MBP) and MABUX Digital Bunker Price Benchmark (DBP)

All Indexes in $/mton	380HSFO			VLS FO			MGO LS			Date
All Indexes in $/mton	MBP Index	DBP Index	MDI	MBP Index	DBP Index	MDI	MBP Index	DBP Index	MDI	Date
Rotterdam	600	740	-140	700	841	-141	1 405	1 628	-223	Sep 11
Singapore	680	783	-103	860	965	-105	1 285	1 621	-336	Sep 11
Fujairah	678	730	-52	915	905	+10	1 502	1 684	-182	Sep 11
Houston	542	734	-192	765	880	-115	1 420	1 600	-180	Sep 11

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Latest News
- 2026-09-11
  Oil prices set to end week above $100 for first time in nearly 4 months
  Oil prices rose on Friday and both major benchmarks are on track to end the week above $100 a barrel for the first time since mid-May, as increasing attacks along key shipping routes in the Middle East fuel fears of a prolonged disruption to supplies. Brent... Read more Oil prices rose on Friday and both major benchmarks are on track to end the week above $100 a barrel for the first time since mid-May, as increasing attacks along key shipping routes in the Middle East fuel fears of a prolonged disruption to supplies.
  
  Brent crude futures rose 81 cents, or 0.8%, to $108.44 a barrel by 0345 GMT. U.S. West Texas Intermediate crude rose 69 cents, or 0.7%, to $103.17 a barrel. Both benchmarks rose more than 6% on Thursday.
  
  On a weekly basis, the benchmarks were trading nearly 13% higher — the steepest gain since the week ended July 17.
  
  Iran-aligned Houthis seized control of Yemen’s port of Mocha on Thursday, posing a further threat to Red Sea traffic, while Gulf traffic remains restricted through the Strait of Hormuz as tanker attacks in the region have intensified in recent days.
  
  Attacks from Yemen on Saudi energy facilities marked an escalation beyond Iran and the Strait of Hormuz and raised fears of prolonged disruptions in the broader region, analysts say.
  
  "While meaningful volumes are still moving through the Strait of Hormuz, flows remain well below pre‑war levels, underscoring how fragile the situation has become," ING analysts said in a note.
  
  U.S. DIESEL PRICES SURPASS $6 A GALLON
  
  Oil supply disruptions due to the U.S.-Iran war, along with Ukrainian attacks on Russia’s refineries, pushed the U.S. national average diesel price past $6 a gallon for the first time ever on Thursday, according to price tracker GasBuddy.
  
  Still, U.S. President Donald Trump has not shown any signs of easing attacks on Iran. He warned the U.S. may hit Iran’s Pickaxe Mountain near its heavily damaged Natanz uranium enrichment facility, but said he thought the war would end immediately after the November midterm elections.
  
  Iran said it had attacked 10 ships near the Strait of Hormuz on Wednesday, after the U.S. hit five Iranian oil tankers. Iran’s Islamic Revolutionary Guard Corps said it would escalate its response to any further attacks.
  
  "With events spiralling and Iran showing it is willing to stretch this conflict as wide and as long as it can, it is becoming increasingly likely that WTI crude will retest the $119.48 high from early March," IG analyst Tony Sycamore said.
  
  Analysts said the rally’s durability will hinge on China, the world’s largest crude importer. If China continues to buy, it could amplify the impact of supply disruptions and drive prices higher.
  
  OPEC lowered its forecast for world oil demand growth in 2026 to 380,000 barrels per day, a copy of its monthly report showed, marking the fifth straight downward revision. OPEC oil output fell by 640,000 bpd in August, a Reuters survey found.
  
  "The next leg in oil will depend less on headlines and more on whether physical flows improve or deteriorate further," said Phillip Nova analyst Priyanka Sachdeva.
  
  "The question now is whether the market can stabilise below $120, or whether another wave of supply disruption pushes crude into a completely new price regime." Source: Reuters/Investing.com
- 2026-09-11
  U.S. Crude Inventories Fall As Brent Prices Soar
  Crude oil inventories in the United States saw a decrease of 400,000 barrels during the week ending September 4, according to new data from the U.S. Energy Information Administration (EIA) released on Thursday. The decrease brings commercial stockpiles... Read more Crude oil inventories in the United States saw a decrease of 400,000 barrels during the week ending September 4, according to new data from the U.S. Energy Information Administration (EIA) released on Thursday. The decrease brings commercial stockpiles to 424.1 million barrels, according to government data, which are now on par with the five-year average for this time of year.
  
  The EIA’s data release follows API’s figures that were released a day earlier, which reported that crude oil inventories had fallen by 300,000 barrels in the period.
  
  Crude futures were trading up at 11:50 a.m. in New York; Brent futures were trading at $106 per barrel—up $4.79 (+4.73%) on the day but up roughly $12 per barrel from this same time last week. WTI was also trading up on the day, by $4.45 per barrel (+4.63%) on Thursday morning at $100.50, up about $11 per barrel since this time last week.
  
  For total motor gasoline, the EIA reported that inventories increased by 1.3 million barrels, after falling by 1.2 million barrels in the week prior. The most recent figures showed that average daily gasoline production fell to 9.3 million barrels. For middle distillates, inventories increased by 2.1 million barrels with production increasing to an average of 5.3 million barrels daily. Distillate inventories are now 13% below the five-year average.
  
  Total products supplied—a proxy for U.S. oil demand—averaged 20.1 million barrels per day over the last four weeks, down 3.7% compared to the same period last year. Gasoline demand averaged 8.8 million barrels per day over the last four weeks, with the distillate four-week average supplied averaging 3.7 million barrels—down 2.6% year over year. Source: Oilprice.com
- 2026-09-11
  MABUX: Global bunker market set to extend upward trend on Sep. 11 amid escalating Middle East tanker attacks.
  The MABUX World Bunker Index — a composite benchmark reflecting daily prices for 380 HSFO, VLSFO, and MGO – continued its upward trajectory on Sep. 10 for the fourth consecutive session: 380 HSFO: USD/MT: 672.79 (+12.48) VLSFO: USD/MT: 829.95 (+5.97) MGO:... Read more The MABUX World Bunker Index — a composite benchmark reflecting daily prices for 380 HSFO, VLSFO, and MGO – continued its upward trajectory on Sep. 10 for the fourth consecutive session:
  
  380 HSFO: USD/MT: 672.79 (+12.48)
  VLSFO: USD/MT: 829.95 (+5.97)
  MGO: USD/MT: 1 463.71 (+8.54)
  
  As of Sep. 10, the MABUX Market Differential Index (MDI), which measures the spread between Market Bunker Prices (MBP) and the MABUX Digital Bunker Benchmark (DBP), registered the following trends across the four major global bunkering hubs—Rotterdam, Singapore, Fujairah, and Houston:
  
  • HSFO segment: All four ports remained underpriced. MDI discounts widened by $15 in Rotterdam, $9 in Singapore, $10 in Fujairah, and $24 in Houston. Houston’s MDI discount remained above the $100 mark, while Rotterdam also exceeded this threshold.
  
  • VLSFO segment: Fujairah remained the only overpriced port, although its premium narrowed by $10. The other three ports stayed underpriced, with MDI discounts widening by $33 in Rotterdam, $26 in Singapore, and $20 in Houston. Rotterdam’s MDI discount moved above the $100 threshold.
  
  • MGO LS segment: All four ports remained in the underpriced zone. MDI discounts widened by $33 in Rotterdam, $30 in Singapore, $23 in Fujairah, and $31 in Houston. MDI discounts remained well above the $100 mark across all four hubs.
  
  The global bunker market is expected to maintain its upward momentum on Sep. 11, supported by escalating geopolitical and supply-risk concerns following tanker attacks in the Middle East. The incidents are likely to reinforce the regional risk premium and provide additional upside support to bunker fuel prices:
  380 HSFO: plus 5-15 USD/MT, VLSFO: plus 5-20 USD/MT, MGO LS: plus 3–25 USD/MT.
  Source: MABUX
- 2026-09-11
  Permian Gas Has Been Worth Less Than Nothing for 118 Days This Year
  Outside Pecos, Texas, Chevron is getting ready to build a power plant to solve a problem the Permian Basin has been stuck with for years, which is that it produces far more natural gas than anyone nearby is willing to pay for. Chevron's subsidiary,... Read more Outside Pecos, Texas, Chevron is getting ready to build a power plant to solve a problem the Permian Basin has been stuck with for years, which is that it produces far more natural gas than anyone nearby is willing to pay for.
  
  Chevron's subsidiary, Energy Forge One, signed a 20-year agreement with Microsoft in June to build a gas-fired plant beside a data center campus, ramping up to roughly 2.67 gigawatts. The final investment decision is due by the end of this year, with power flowing in 2028.
  
  One deal in one county doesn't make a trend, but it does show how three separate energy problems in West Texas, all of them years in the making, are starting to find the same customer.
  
  Most of the talk out of Midland this year has been about restraint, with fewer rigs, tighter budgets and what one trade publication called a transition to slower, more disciplined growth. That describes the oil side well enough, but it misses what's happening with gas.
  
  WTI averaged $65 a barrel in 2025 and roughly $84 through July of this year, well above the $63 to $69 breakeven that Midland and Delaware basin operators reported to the Dallas Fed, so producers kept drilling.
  
  The catch is that every barrel now brings up more gas than it did a few years ago, a rising gas-to-oil ratio that tends to come with age in almost any oil field.
  
  The EIA expects Permian gas production to average 29.2 Bcf/d this year, up 6% and a record for the region.
  
  There isn't enough pipeline to move all of it…
  
  Waha, the pricing hub for Permian gas, traded negative on 118 of the first 131 trading days this year and is on pace to beat 2024's record for negative days.
  
  Negative means producers pay someone to take the gas off their hands, which they do because the alternative is shutting in the oil well that's actually making them money. So the Permian's trouble isn't production; it's that one of its two products spends much of the year worth less than nothing.
  
  Nobody in the midstream business is acting as if this ends soon, either. Enterprise Products Partners is expanding its Bahia NGL pipeline out of the Midland and Delaware basins, with ExxonMobil taking a 40% stake and contracts running into 2027.
  
  Data Centers Don't Wait for Pipelines
  
  East Daley Analytics figures LNG terminals and data centers together will pull more than 20 Bcf/d of new demand, and that the pipelines now being built toward the Gulf Coast won't sit empty waiting for it.
  
  Their read is that producers may end up drilling gassier acreage on purpose, just to keep both products moving through infrastructure that was designed mostly around crude.
  
  A behind-the-meter data center changes that without anyone laying new pipe...
  
  The plant going up at Pecos sits next to the wellhead, buys gas that would otherwise be competing for space in an oversubscribed gathering system, and burns it on site to make electricity the data center uses directly, never touching the public grid.
  
  RBC Capital Markets counts about 38 gigawatts of announced behind-the-meter gas capacity in Texas, more than any other state.
  
  One project alone, a build called GW Ranch, is targeting 7.5 gigawatts of on-site generation in West Texas by 2031, which is roughly what a mid-sized American city draws.
  
  One claim about these projects deserves more skepticism than it tends to get, which is that they're soaking up gas that would otherwise be flared. Nobody has demonstrated that for Project Kilby.
  
  An environmental compliance firm working in the sector made the point in a client note this summer, arguing that sitting near a stranded well doesn't prove a data center's fuel is displacing flared volumes, and that most developers haven't produced the project-level evidence to back it up.
  
  Flaring in the Permian has been falling anyway, with intensity down nearly 10% between 2023 and 2024, largely because pipelines like Matterhorn Express finally gave the gas somewhere to go.
  
  The simple fact is that the Permian makes more gas than the market can absorb even after the pipelines get built, and data centers are the first buyers in years with enough money and enough impatience to put a power plant where the gas already is.
  
  Wind Already Paid for the Wires
  
  Nolan County, with Sweetwater at its center, has been called the wind turbine capital of Texas since the mid-2000s, when hundreds of turbines went up on the plateaus between Abilene and Big Spring.
  
  Moving that power east required new transmission, which the state paid for through a roughly $7 billion program called CREZ. Those lines added about 18,000 megawatts of capacity, they've been paid down for years, and they're still carrying electricity today.
  
  That's a large part of why data center developers keep landing along this stretch of I-20, because the wires went in the ground long before anyone was planning gigawatt campuses.
  
  I wrote about what that's done to land values and ranch economics in the corridor in West Texas Cowboys Are Cashing In on the AI Land Rush.
  
  The piece of it that matters here is that wind already solved the region's east-west transmission problem, and everyone building now is spending capital somebody else committed two decades ago.
  
  Solar Is Still Waiting on Its Transmission Line
  
  A new high-voltage line called the Permian Reliability Project is working through siting now, and it's expected to do for far West Texas solar roughly what CREZ did for wind around Abilene, turning land that has plenty of sun and no way to sell the power into land a developer can actually finance.
  
  Where the next round of renewable buildout lands may look different from the last one, because turbines need open ground and distance from flight paths.
  
  One large project near Abilene switched from wind to solar after developers ran into airspace conflicts with Dyess Air Force Base. Panels have fewer of those constraints, and once the Permian Reliability Project's lines are up, solar sits much closer to the data center campuses now scouting land in the basin itself rather than in the Abilene corridor to the northeast.
  
  Crypto Miners Ran a Small Version of This First
  
  Putting data centers next to stranded gas isn't new in West Texas, it just hasn't been done at this size before.
  
  Miners have spent years hauling shipping containers full of rigs and small generators out to remote well sites and buying gas straight from producers who had no other way to sell it.
  
  ConocoPhillips ran an early version in the Bakken, ExxonMobil piloted its own, and the model spread across the Permian from there.
  
  Mining works for this because it doesn't care where the power comes from or whether the connection is reliable, so it can take energy nobody else wants, right where it's produced, without waiting on a pipeline permit.
  
  Ryan Dusek, a commodity risk advisor at the consultancy Opportune, has called it one of the few genuinely symbiotic arrangements in energy, since producers get rid of gas they can't move and miners get power at wholesale with no exposure to grid outages.
  
  Pecos runs on that same trade at a completely different scale.
  
  A container of mining rigs might burn a few million cubic feet of gas in a year, while a 2.67-gigawatt power plant is another business entirely, which is why what miners were doing out here a few years ago now looks like a rehearsal for something much bigger.
  
  Abbott's Pause Doesn't Touch Any of This
  
  Governor Greg Abbott ordered a pause on new data center approvals on Aug. 3, telling ERCOT and the Public Utility Commission of Texas to audit every project sitting in the grid's interconnection queue, which had grown to roughly 474 gigawatts of requests against a record peak demand of about 85 gigawatts.
  
  The audit covers around 300 large projects in ERCOT's Batch Zero process and looks at water use, ownership, public subsidies and a good deal else.
  
  None of it applies to projects that skip the grid connection.
  
  A developer building its own generation on site, the way Chevron and Microsoft are doing at Pecos, can keep going while the queue sits frozen.
  
  That fits what the directive was written for, since Abbott's stated concern is grid reliability for Texans who depend on the grid, and a data center making its own power was never drawing from it.
  
  The politics will keep moving through this fall's elections, and there's no firm end date on the audit, but the incentives point one direction regardless, because the more scrutiny grid-connected projects face in Texas, the better behind-the-meter starts to look. That's the model pulling gas demand, and eventually renewable demand, straight into the Permian and the corridors around it.
  
  Data centers didn't create any of these three problems…
  
  The stranded gas, the underused wind transmission and the solar line that still hasn't been built were all sitting in West Texas waiting on a buyer with enough capital and enough urgency to work around the infrastructure gaps instead of waiting for someone else to close them.
  
  Whether that buyer stays at the size currently advertised is a fair question, and ERCOT's own officials expect much of the interconnection queue to disappear once financial-commitment rules flush out the speculative filings.
  
  What's already signed is harder to argue with. Kilby is a 20-year contract with a final investment decision due before the year is out. Source: Oilprice.com
- 2026-09-11
  OPEC Sees Oil Demand Growth Explode Sixfold in 2027
  OPEC now expects global oil demand growth to jump from just 380,000 barrels per day this year to 2.36 million bpd in 2027—a more than sixfold increase in the space of a year. The cartel trimmed its 2026 demand-growth forecast in its September Monthly... Read more OPEC now expects global oil demand growth to jump from just 380,000 barrels per day this year to 2.36 million bpd in 2027—a more than sixfold increase in the space of a year.
  
  The cartel trimmed its 2026 demand-growth forecast in its September Monthly Oil Market Report, putting total consumption this year at 105.84 million bpd. For 2027, OPEC raised its forecast, with global demand expected to reach 108.19 million bpd.
  
  The swing is especially stark in China. OPEC expects Chinese oil demand to grow by only 10,000 bpd this year, leaving consumption essentially flat at 16.90 million bpd. In 2027, OPEC expects China to add 380,000 bpd, taking demand to 17.28 million bpd.
  
  India shows an even sharper change. Demand growth there is pegged at just 60,000 bpd in 2026. OPEC sees another 400,000 bpd arriving next year, lifting Indian consumption to 6.11 million bpd.
  
  OECD demand is expected to shrink by 110,000 bpd this year. OPEC has penciled in 430,000 bpd of growth for 2027, including increases in the Americas, Europe and Asia Pacific.
  
  Non-OECD countries account for most of next year’s increase. Their combined demand growth accelerates from 490,000 bpd in 2026 to 1.92 million bpd in 2027. China, India and the rest of Asia alone account for nearly 1.2 million bpd of that increase.
  
  OPEC’s own barrels would face a much bigger call under that forecast. Demand for crude from countries participating in the Declaration of Cooperation is expected to rise from 42.2 million bpd in 2026 to 43.9 million bpd next year. OPEC puts that increase at about 1.6 million bpd.
  
  OPEC has lowered its 2026 oil demand growth forecast repeatedly this year.
  
  OPEC is heading into 2027 with a demand forecast that looks nothing like 2026: roughly 2 million additional barrels per day of annual growth, led overwhelmingly by countries outside the OECD. Source: Oilprice.com
- 2026-09-11
  EIA Raises 2027 U.S. Oil Output Forecast
  The U.S. Energy Information Administration has raised its forecast for U.S. crude oil production in 2027 to 14.3 million barrels per day, up from 14.2 million bpd in August and 14.0 million bpd in July. For 2026, EIA is still calling for 13.8 million... Read more The U.S. Energy Information Administration has raised its forecast for U.S. crude oil production in 2027 to 14.3 million barrels per day, up from 14.2 million bpd in August and 14.0 million bpd in July.
  
  For 2026, EIA is still calling for 13.8 million bpd, unchanged from its July and August forecasts. That would top the 13.7 million bpd record set in 2025.
  
  U.S. production averaged 13.7 million bpd during the first half of this year, up 300,000 bpd, or 2%, from the same period last year. Most of that increase came from the Permian and the U.S. part of the Gulf of Mexico.
  
  The EIA expects Permian production to average 6.8 million bpd this year, 3% above 2025. WTI averaged $84 per barrel through August, up from $65 last year. Producers responding to the Dallas Fed’s March survey put average breakeven prices at $69 per barrel in the Midland Basin and $63 in the Delaware Basin.
  
  The Gulf added another 200,000 bpd in the first half, a 10% increase year over year. Four projects that started production over the past year—Shenandoah, Ballymore, Whale and Salamanca—have produced a combined average of about 191,000 bpd since coming online.
  
  Shenandoah leads the group at 70,000 bpd, followed by Ballymore at 58,000 bpd, Whale at 38,000 bpd and Salamanca at 25,000 bpd. EIA expects four additional, smaller Gulf projects to start by the end of 2026.
  
  EIA expects Brent to average $91 per barrel in 2026 and $74 in 2027. Its U.S. crude production forecast rises another 500,000 bpd over the same period. Source: Oilprice.com
- 2026-09-11
  Senegal to Offer 109 Oil and Gas Blocks to Investors
  Senegal will offer to local and foreign investors as many as 109 oil and gas blocks, Energy and Petroleum Minister, El Hadji Abdourahmane Diouf, has said. Only four out of the West African country’s 113 oil and gas blocks are currently contracted,... Read more Senegal will offer to local and foreign investors as many as 109 oil and gas blocks, Energy and Petroleum Minister, El Hadji Abdourahmane Diouf, has said.
  
  Only four out of the West African country’s 113 oil and gas blocks are currently contracted, the official told a local TV channel.
  
  “The remaining 109 will be put on the market,” the minister said, as carried by Reuters.
  
  “The president’s plan is to create local leaders in the energy, oil and gas sectors,” Diouf added.
  
  Several oil and gas discoveries offshore Senegal in the past decade have kickstarted the petroleum industry in the African country, which saw its first oil project launched in 2024, while LNG exports were launched a year later from a gas project offshore Senegal and Mauritania.
  
  The start-up of Senegal’s first ever oil project in 2024 pushed economic growth to a record high.
  
  Australia-based Woodside Energy achieved first oil at the Sangomar oil project in June 2024.
  
  The Sangomar Field Development Phase 1 is a deepwater project including a stand-alone floating production storage and offloading (FPSO) facility with a nameplate capacity of 100,000 barrels per day (bpd) and subsea infrastructure that is designed to allow subsequent development phases, Woodside says.
  
  “First oil from the Sangomar field marks a new era not only for our country's industry and economy, but most importantly for our people,” Thierno Ly, general manager of Senegal’s national oil company Petrosen said at the time.
  
  A year later, BP, as the operator, safely loaded the first LNG cargo for export from Phase 1 of its Greater Tortue Ahmeyim project offshore Mauritania and Senegal.
  
  Phase 1 at Greater Tortue Ahmeyim (GTA) is set to produce around 2.3 million tons of LNG per year and the project is expected to produce LNG for more than 20 years, BP says. Source: Oilprice.com
- 2026-09-11
  IEA: Global Coal Demand Set to Hit Record High as Iran War Chokes LNG Supply
  Soaring LNG prices due to the Strait of Hormuz blockage are prompting economies to shift to alternative energy sources, pushing coal demand to a another record high this year, the International Energy Agency (IEA) said in a new report on Thursday. The... Read more Soaring LNG prices due to the Strait of Hormuz blockage are prompting economies to shift to alternative energy sources, pushing coal demand to a another record high this year, the International Energy Agency (IEA) said in a new report on Thursday.
  
  The surge in LNG prices have pushed markets including China, India, Japan, South Korea, and even Europe, to rely more on coal-fired capacity for electricity generation, the IEA said in its new Coal Mid-Year Update 2026.
  
  The Middle East is not a major exporter of coal, so global coal shipments weren’t disrupted when the Iran war began more than six months ago. But the LNG shipments out of the Strait of Hormuz slumped materially, pushing LNG and gas prices higher and prompting utilities to run coal-fired units harder.
  
  As a result of the major energy supply dislocation, global coal demand – which before the war was expected to slightly drop this year – is now projected to rise by 1.2% in 2026, the IEA said. This increase would bring global coal consumption to a record 8.94 billion tons this year.
  
  The change in coal demand forecasts for this year “mainly reflects the crisis in the Middle East and an unusually strong El Niño weather pattern,” the IEA said.
  
  “Although shipping disruptions in the Strait of Hormuz do not directly affect coal markets, tighter natural gas supply has pushed up prices, prompting some electricity systems to switch from gas to coal.”
  
  Coal demand in the two biggest coal consumers, China and India, is expected to rise this year. Chinese demand is set for a 1% increase to 5 billion tons, while India will see a 4.2% rise to 1.353 billion tons, reversing last year’s temporary slight drop, according to the IEA.
  
  If the Strait of Hormuz remains largely closed to LNG shipments well into next year, global coal demand could further rise to new record highs, the agency added. Source: Oilprice.com
- 2026-09-11
  HSBC Raises 2026 Brent Forecast to $90 as Hormuz Crisis Drags On
  HSBC has hiked its Brent Crude forecast for 2026 to $90 per barrel from $80 as the Strait of Hormuz crisis is tightening markets while no clear path to de-escalation is in sight. The oil markets are unlikely to rebalance until the middle of 2027, HSBC... Read more HSBC has hiked its Brent Crude forecast for 2026 to $90 per barrel from $80 as the Strait of Hormuz crisis is tightening markets while no clear path to de-escalation is in sight.
  
  The oil markets are unlikely to rebalance until the middle of 2027, HSBC analyst Kim Fustier wrote in a note, as cited by The Wall Street Journal.
  
  The bank’s base-case scenario for the coming weeks and months is a fragile form of understanding between the United States and Iran which would be susceptible to breakdowns and uncertainties, including in terms of shipping security and insurance.
  
  HSBC’s Fustier forecasts that oil flows through the Strait of Hormuz will rise to about 8 million barrels per (bpd) by the end of 2026, up from 6 million bpd now.
  
  This estimate is below some other analyst projections and current flows tracking that suggest about 10 million bpd of crude and petroleum products move through Hormuz at present.
  
  Still, even if the 10 million bpd estimate is correct, this is half the pre-war levels of about 19-20 million bpd of oil that transited the chokepoint every day.
  
  HSBC expects Hormuz oil flows to gradually move up to 9.5 million bpd by the middle of 2027, Fustier said, noting that this would lead to continued tightness in the oil markets for nearly another year.
  
  Hence, HSBC’s higher Brent Crude forecast of $90 per barrel for 2026.
  
  Early on Thursday, Brent Crude prices hovered at $101 per barrel, having breached the $100 mark on Wednesday for the first time since July, as the U.S.-Iran tanker war escalated.
  
  In HSBC’s ‘stalemate’ scenario, with diplomacy failed and flows constrained as-is, Brent could jump to $120 per barrel.
  
  This is not the bank’s base-case scenario, but it is close to Goldman Sachs’ warning from earlier this week that oil prices could surge to as much as $120 per barrel if attacks on shipping in the Middle East intensify. Source: Oilprice.com
- 2026-09-11
  TotalEnergies to Bring New Angola Discovery Online in Just Three Months
  TotalEnergies has made a new discovery offshore Angola and has bought operated interest in two new exploration blocks close to operating hubs as the international majors are returning to exploration in Angola’s waters to take advantage of existing infrastructure. TotalEnergies... Read more TotalEnergies has made a new discovery offshore Angola and has bought operated interest in two new exploration blocks close to operating hubs as the international majors are returning to exploration in Angola’s waters to take advantage of existing infrastructure.
  
  TotalEnergies on Thursday said that the Acacia-5 discovery in Block 17 would see first oil achieved just three months after the discovery was made in June 2026. This would be done through a fast-track development using the available capacity on the nearby Pazflor FPSO. Acacia-5 is expected to increase oil production in Block 17 by 6,000 barrels per day (bpd).
  
  Acacia-5 is the second exploration success so far this year in TotalEnergies' Angolan portfolio, following the recent Block 0 discovery in the Lower Congo Basin, where TotalEnergies holds a 10% interest alongside the operator, Chevron.
  
  Last month, Chevron announced a new oil and gas condensate in a Block 0 exploration well that could be tied directly into the company’s existing production infrastructure in the country.
  
  TotalEnergies has also signed agreements with the concessionaire Agência Nacional de Petróleo, Gás e Biocombustíveis (ANPG), to enter with a 40% operated interest in exploration Blocks 17/25 and 32/21, located in the heart of the prolific Lower Congo Basin, the French supermajor said today.
  
  “Exploration is a key pillar of our ambition in Angola, supported by the incentives introduced to encourage investment,” said Patrick Pouyanné, Chairman and CEO of TotalEnergies.
  
  “Together with our partners, we aim to explore further and unlock new resources, sustaining a strong exploration effort to identify new opportunities across Angola's offshore basins.”
  
  TotalEnergies is one of several supermajors ramping up exploration efforts offshore Angola.
  
  Earlier this week, ExxonMobil announced a discovery on Block 15.
  
  The majors’ return to exploration in Angola is good news for the African producer, which quit OPEC in early 2024 and aims to reverse years of declining oil production. Source: Oilprice.com

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