Crude oil (Brent) price on Apr 10, 2026 at 5pm EDT?

IEA and EIA forecast differing OPEC+ spare capacity for Q1 2026. The International Energy Agency (IEA) projects OPEC+ 'effective spare production capacity' to average 3.5 million barrels per day (mb/d) for the first quarter of 2026 ^{[^]}. This projection reflects minor adjustments from earlier IEA reports, which forecast 3.6 mb/d in February 2026 ^{[^]} and 3.7 mb/d in January 2026 ^{[^]}. In contrast, the U.S. Energy Information Administration (EIA) forecasts 'OPEC crude oil effective spare production capacity' at 3.8 mb/d for Q1 2026 ^{[^]}, noting that the IEA's figure applies to 'OPEC+' while the EIA's figure specifies 'OPEC crude oil'.

Q1 2026 forecasts exceed the recent 5-year historical average. To provide context, the 5-year historical average (2019-2023) for OPEC's effective spare capacity during the first quarter is approximately 3.0 mb/d ^{[^]}. This historical average, derived from IEA data, indicates that both the IEA's forecast of 3.5 mb/d for OPEC+ and the EIA's forecast of 3.8 mb/d for OPEC crude oil for Q1 2026 represent an increase in effective spare production capacity compared to the recent historical average for that quarter ^{[^]}.

Determining 'Managed Money' net positions for 2026 ICE Brent futures is not possible. CFTC Commitment of Traders (COT) reports typically aggregate data across all contract months for a given commodity or focus on specific nearby contract months, rather than providing data for a cumulative '2026 delivery' category ^{[^]}. The most granular CFTC report available that specifies a date is a petroleum futures short report from January 13, 2026 ^{[^]}. This report details short positions held by various participant categories for crude oil and other petroleum products. However, without a corresponding long report for the same date, the precise 'Managed Money' net position (longs minus shorts) cannot be calculated from the provided sources ^{[^]}.

Post-earnings shifts in 'Managed Money' positioning cannot be quantified from available data. The quarterly earnings calls for several major oil supermajors for Q4 2025 took place in late January and early February 2026. For instance, ExxonMobil's 4Q 2025 earnings call was scheduled for January 30, 2026 ^{[^]}, and Shell plc published its 4Q 2025 press release around February 5, 2026 ^{[^]}. Reports also indicated that major oil companies were preparing for earnings results during this period ^{[^]}. To assess how institutional positioning, specifically for 'Managed Money,' might have changed following these earnings calls, CFTC data from after these dates would be essential. However, the provided sources do not include any CFTC Commitment of Traders reports dated later than January 13, 2026 ^{[^]}, making it impossible to quantify any subsequent shifts in 'Managed Money' positioning for ICE Brent futures based solely on the information at hand.

The Brent crude oil futures market currently exhibits mild backwardation. This structure indicates that the front-month contract trades at a premium compared to longer-dated contracts, including December 2025, reflecting a perception of current supply tightness or robust demand relative to future expectations. Deutsche Bank suggests that this futures curve signal points to a "temporary price spike," implying the current backwardation may be a short-term phenomenon ^{[^]}.

Physical inventory levels in March 2026 show significant regional shifts. In the Amsterdam-Rotterdam-Antwerp (ARA) region, fuel and gasoil stocks decreased, with fuel oil inventories specifically declining by a notable 19% ^{[^]}. Conversely, Singapore's fuel oil inventories saw an increase of 4% during the same period. Specific current inventory levels or trends for crude oil at Cushing, Oklahoma, were not provided in the available research ^{[^]}.

The observed backwardation generally correlates with tightening physical market conditions. The decrease in ARA fuel and gasoil stocks aligns with regional supply tightness, which could support this backwardation ^{[^]}. However, the increase in Singapore's fuel oil inventories presents a more mixed picture for global product markets, indicating varying regional supply dynamics. This combination of mild backwardation and declining ARA stocks generally points to near-term supply concerns, even with rising fuel oil storage in Singapore ^{[^]}.

The U.S. Strategic Petroleum Reserve consistently purchases 3 million barrels monthly. Beginning in January 2023, the U.S. Strategic Petroleum Reserve (SPR) has maintained a crude oil purchase rate of 3 million barrels per month. This sustained pace is consistent with the Department of Energy's contracts for refilling the reserve and is expected to continue through December 2025 ^{[^]}.

SPR additions will exceed one day of global demand. At the observed rate, a total of 117 million barrels of crude oil is projected to be added to the SPR between January 2023 and March 2026, encompassing 39 months of purchases ^{[^]}. This accumulated volume represents approximately 112.1% of the forecast global crude oil demand, which is estimated at 104.4 million barrels per day in 2026 ^{[^]}.

US Permian Basin oil output growth is projected to moderate in 2025. For full-year 2025, oil output growth in the US Permian Basin is anticipated to slow to approximately 400,000 barrels per day (bpd), a decrease from around 500,000 bpd in 2024 ^{[^]}. This occurs as non-OPEC+ countries are expected to be the primary contributors to petroleum liquids supply growth in both 2025 and 2026 ^{[^]}. Overall U.S. crude oil production is forecasted by the U.S. Energy Information Administration (EIA) to remain near its record 2025 levels, indicating sustained output from key domestic basins ^{[^]}.

Non-OPEC+ countries drive supply growth, with Guyana playing a key role. Offshore Guyana is identified as a crucial region contributing to petroleum liquids supply growth from non-OPEC+ countries in 2025 and 2026, alongside the United States, Canada, and Brazil ^{[^]}. Top non-OPEC E&P companies are demonstrating capital discipline, with global exploration and production (E&P) capital expenditure (capex) expected to remain steady in 2025 ^{[^]}. For example, ConocoPhillips plans a $12.9 billion capex for 2025, aiming for a year-over-year production increase, even after trimming its capex by $500 million while sticking to its production target ^{[^]}. Similarly, EOG Resources has set a $6.5 billion capex plan for 2025, with the objective of maintaining production at its Q4 levels ^{[^]}.

Inflation management for oilfield services costs is not explicitly detailed. The provided sources do not explicitly detail how the projected growth rates or capex guidance from non-OPEC E&P companies account for potential inflation in oilfield services costs. While some companies like ConocoPhillips adjust their capex plans, trimming budgets while maintaining production targets ^{[^]}, the direct reasons cited for these adjustments in the available information do not explicitly link them to managing or forecasting oilfield services cost inflation. The general trend of "capital discipline" ^{[^]} and "steady global capex" ^{[^]} suggests operators are managing within budgetary constraints, but specific mechanisms for addressing inflation in service costs are not outlined.

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