WTI crude at $72.24/bbl on July 10, up 0.23% on the day, as the market digests a 4.4% recovery earlier in the week on US-Iran tensions. Brent crude at $76.27/bbl, flat on the day. Both benchmarks are down roughly 16-18% month-over-month but still up 5-8% year-over-year. The energy complex is being pulled in three directions: geopolitics (Hormuz), macro (demand concerns), and supply (US production records, OPEC dynamics).
The Strait of Hormuz is the dominant short-term factor. US strikes on Iran this week — and Trump's declaration that "the ceasefire is over" — disrupted vessel traffic through the strait, with shipping slowing sharply on both the Iran-approved routes and the US-backed Omani corridor. WTI surged 4.4% on the news before giving back half the gain as traders assessed the probability of a sustained disruption. The situation is unresolved: US and Iran are in talks but the rhetoric is escalatory.
Beyond Hormuz, the macro picture is bearish. The EIA's July Short-Term Energy Outlook projects global oil demand will fall 1.2 million barrels per day in 2026 — the first annual demand decline since 2020 outside of a pandemic. The driver is slowing economic growth in China (GDP tracking below 4.5%) and Europe. Meanwhile, non-OPEC supply is growing by 1.5 mb/d, led by US production at a record 13.93 million b/d.
US crude oil production hit an all-time high of just under 13.9 million b/d in April, according to EIA data. The Permian Basin continues to deliver, with completion efficiency gains offsetting declining well productivity. The EIA forecasts US production averaging 13.8 mb/d in 2026 and 14.0 mb/d in 2027. That additional supply is displacing OPEC barrels in global markets.
OPEC faces a strategic dilemma. The alliance is producing below its theoretical capacity, with several members exceeding their quotas. Saudi Arabia needs $85-90/bbl to balance its budget. But with non-OPEC supply growing and demand declining, OPEC's market share is shrinking. The August OPEC meeting will be critical: if the group cuts further, prices support; if they maintain or increase output, the surplus widens.
Henry Hub natural gas at $3.01/MMBtu, down 0.21% on the day. The market is balanced heading into summer cooling season. EIA reported working gas in storage at 2,922 Bcf as of June 26 — a 6% surplus year-over-year and 5% above the 5-year average. Storage injections are running at 87 Bcf/week, in line with seasonal norms. LNG exports continue at record levels (13.2 Bcf/d) as global Asian and European demand supports the market at $3.00.
TTF natural gas in Europe is under pressure from a wave of new LNG supply. Approximately 90+ bcm/yr of new LNG capacity is expected to come online between 2025-2027, and the first cargoes from these projects are already arriving. European storage is 78% full ahead of schedule. TTF has fallen to the equivalent of $6-7/MMBtu, down sharply from crisis-era levels.
Refined products tell a mixed story. Diesel cracks are strong at 70-75% of crude value as refining capacity tightens globally — several European refineries closed permanently during the pandemic and have not reopened. Gasoline at $2.99/gal, down 3.59% month-over-month. RBOB gasoline prices are softening as summer driving demand peaks. ULSD (heating oil/diesel) at $3.53/gal, flat month-over-month with the crack spread supported by low distillate inventories.
Bull case: Hormuz closes partially for 2+ weeks, OPEC cuts further at August meeting, and Chinese stimulus boosts demand. WTI back to $85.
Bear case: US-Iran ceasefire holds, US supply hits 14 mb/d, global demand contracts more than expected. WTI tests $65.
Base case: WTI trades $68-78 through Q3, with Hormuz risk keeping a $5-7 premium in the price. Natural gas at $2.80-3.40.
The energy market in July 2026 presents a complex risk environment for procurement teams. The dominant factor is not the macro demand picture or the supply surplus — it is the Strait of Hormuz. Any procurement strategy that assumes uninterrupted Hormuz transit is taking uncompensated risk. The base case should include a 5-10% probability of a 2-4 week disruption that would spike WTI to $85-90 and diesel to $4.50+/gal. Buyers should: (1) lock in Q4 diesel coverage now as the crack spread support from limited refining capacity will persist regardless of crude prices; (2) for WTI-related procurement (plastics, chemicals, transport fuel), layer in collar options that protect against a $90 spike without sacrificing downside to $65; (3) increase permitted inventory levels for middle distillates by 15-20% through September; (4) monitor Henry Hub storage data weekly — if injections run below 80 Bcf for two consecutive weeks, natural gas buyers should accelerate winter hedge coverage.