The energy complex is experiencing its most significant risk premium since the Russia-Ukraine crisis of 2022, driven by the escalating US-Iran war and the spillover effects on Middle East shipping lanes. Brent crude traded at $100.25/bbl on July 23, up 6.6% on the day, with intraday prints above $101. WTI crude followed at $89-92/bbl, with the Brent-WTI spread widening to $11/bbl as Brent captures the larger seaborne risk premium.
The supply disruption risk is centered on the Strait of Hormuz and the Red Sea. Iran-backed Houthi rebels have escalated attacks on tankers transiting the Bab el-Mandeb strait, forcing shipping companies to reroute around the Cape of Good Hope, adding 10-15 days to voyage times and increasing freight costs by 300%. The threat to the Strait of Hormuz, through which approximately 21 million barrels per day of crude and products transit, represents the single largest concentration risk in global oil markets. Any disruption there could remove 15-20% of global supply.
OPEC+ has maintained a cautious stance on quota adjustments. The group is only slowly unwinding the voluntary cuts implemented in 2023-24, with a 206 kb/d increase scheduled for May 2026 and further small hikes into mid-2026. This leaves approximately 3.24 mb/d of cuts still in place. The cautious approach reflects the group's expectation that demand growth will remain strong and that the geopolitical risk premium is not a reliable basis for production decisions.
US crude oil production continues to set records. The EIA projects US output of 13.7-13.8 million barrels per day in 2026-27, driven by Permian Basin efficiency gains and improved drilling productivity. This non-OPEC supply growth is partially offsetting Middle East outages but cannot replace a full Hormuz disruption. The US is now the world's largest crude producer, a position that provides some insulation but does not decouple US prices from global benchmarks.
European natural gas markets are feeling the heat from the broader energy complex. TTF (Dutch Title Transfer Facility), the European benchmark, traded at €38-42/MWh on July 23, up 2.8% on the day. European gas storage is at 78% of capacity, ahead of the winter filling target, but the premium reflects the risk of LNG supply disruption if Middle East conflict escalates. LNG Asia (JKM) is trading above $14/MMBtu, driven by strong demand from China and India and competition for spot cargoes with Europe.
US natural gas (Henry Hub) trades at $3.10/MMBtu, up 3.3% on the day, supported by strong LNG export demand and summer cooling demand. US LNG export capacity continues to grow, with the Plaquemines and Corpus Christi Stage 3 projects ramping up, adding approximately 5 bcf/d of new export capacity by year-end 2027. This structural export demand is gradually re-pricing Henry Hub away from its historical $2-3 range toward $3-4, as US gas becomes increasingly integrated with global markets.
Coal markets are elevated as well. Newcastle thermal coal trades at $155-165/ton, supported by Asian demand and competition with natural gas for power generation. Coking coal is at $280-320/ton, with supply constrained by Australian mine disruptions and Chinese import demand. ULSD diesel and RBOB gasoline have tracked crude higher, with ULSD at $2.85-3.00/gallon and RBOB at $2.50-2.65/gallon, putting upward pressure on transportation and logistics costs across the supply chain. Methanol, linked to natural gas prices, trades at $340-360/ton in Asia and $380-400/ton in Europe.
Energy buyers face the highest geopolitical risk premium since 2022. Brent above $100/bbl with a widening contango structure signals that the market is pricing in sustained disruption risk. For procurement teams, this is the time to lock in hedges. Brent at $95-100 for Q4 2026 and Q1 2027 offers protection against the scenario where Iran conflict escalates to Strait of Hormuz disruption, which could push prices to $130-150/bbl. Natural gas buyers should accelerate winter coverage: TTF at €38-42/MWh for Q1 2027 is attractive given Russian supply uncertainty and the risk of LNG supply disruption. ULSD buyers face the steepest cost impacts: the diesel market is structurally tight even without geopolitical risk, with global refining capacity constraints and low inventories. Consider extending diesel coverage through Q2 2027. The one mitigating factor is US production growth, which provides a partial hedge but cannot fully offset Middle East disruption risk. The prudent strategy is to increase hedge ratios to 70-80% of expected consumption for the next 12 months, accepting the basis risk in exchange for price certainty.