Energy complex volatile: WTI below $70 as Iran conflict reshapes global oil and gas flows

The energy complex enters July 2026 deeply divided. Crude oil trades in the high $60s to low $70s as demand destruction from the Iran conflict collides with supply disruption from the Strait of Hormuz closure. Natural gas markets are bifurcated between a subdued US Henry Hub ($3.25/mmbtu) and elevated European TTF ($44.25/MWh) and Asian LNG ($12.80/mmbtu). Coal and methanol have corrected from war-driven spikes but remain structurally elevated relative to pre-conflict baselines.

Crude oil: WTI at $68.78/bbl and Brent at $72.13/bbl reflect a tug-of-war between conflicting forces. The IEA's June Oil Market Report projects world oil demand declining by 1.1 mb/d year-on-year in 2026 — the first annual demand contraction since 2020 — driven by the economic impact of the Iran conflict. The EIA's June STEO similarly projects a 1.1 mb/d decline. OPEC's June MOMR maintains a more optimistic view of demand growth at 1.0 mb/d, though this has been revised down multiple times from the pre-war forecast of 1.4 mb/d.

Supply is contracting faster than demand. Global oil supply is projected to decline by 3.9 mb/d on average in 2026, per the IEA, due to Gulf outages from the Strait of Hormuz disruption. OPEC+ spare capacity has been slashed to an estimated 320 kb/d in March, the lowest on record according to IEA data. OECD petroleum inventories are projected to fall to just under 2.3 billion barrels by end-2026 — the lowest since 2003 — with days of supply down to approximately 50 days, also a record low in the EIA series.

The EIA's June STEO assumes flows through the Strait of Hormuz begin to gradually resume in H2 2026, bringing Gulf supply back and allowing Brent to average $105/bbl in June-July before falling to an average of $79/bbl in 2027. For the full year, EIA forecasts Brent averaging $95/bbl and WTI $85.68/bbl — well above current spot levels, implying futures/backwardation embed expectations of tighter balances or risk premia later in 2026 relative to current spot.

Natural gas: The US-European price divergence is extreme. Henry Hub at $3.245/mmbtu reflects ample US supply from the Permian and Marcellus, robust storage, and mild summer demand. The EIA projects Henry Hub averaging $3.50/mmbtu for 2026. European TTF at $44.25/MWh ($14.71/mmbtu equivalent) and Asian JKM at $12.80/mmbtu ($16.29/mmbtu equivalent) trade at 4-5x US levels. EU gas storage at approximately 49% full is about 10 percentage points below last year, contributing to TTF support. LNG flows are being redirected: the JKM-TTF spread has averaged more than $2/mmbtu since late March 2026, keeping Atlantic basin cargoes pointed east. EU LNG imports fell 18% year-on-year in June 2026 amid sustained wartime strains.

Coal markets are structurally elevated. Newcastle thermal coal at $138.50/t has corrected 12.7% over the past month from war-driven highs above $160 but remains 17% higher year-on-year. An Indonesia export controls scare in June caused a temporary spike. China continues its 'all-of-the-above' energy strategy, expanding both coal-fired power (78% of new global coal capacity in 2025) and renewables. Coking coal at $241/t is particularly tight, up 35% year-on-year, driven by constrained Australian and Canadian output and strong Indian steel demand. Chinese mine closures (155 mines shut after a major accident) pushed China toward Australian imports, supporting prices.

Methanol at $96/t reflects partial normalization after the March 2026 price spike. The war blocked ~18% of global methanol capacity from normal trade routes. Southeast Asia spot prices jumped 72% to $555/t in March. Since then, pricing has partially normalized but remains elevated in import-dependent regions. The Americas remain structurally long supply, function as a swing exporter to cover Middle East shortfalls, with US Gulf barge prices hitting four-year highs in March.

Refined products show the impact of crude compression. ULSD diesel at $3.257/gal and RBOB gasoline at $2.774/gal reflect wide crack spreads driven by middle-distillate tightness. The EIA forecasts diesel and jet fuel wholesale prices rising more than 60% in 2026 and 40% in 2027 compared to pre-conflict baselines. The ULSD-Brent crack spread structurally exceeds RBOB-Brent, reflecting limited middle-distillate supply globally.

The demand outlook divergence between agencies underscores the uncertainty. IEA and EIA project demand contraction; OPEC still sees growth. The difference matters for 2027 planning: if the IEA is right, the market may return to surplus quickly as Gulf supply normalizes. If OPEC is right, the demand recovery combined with depleted inventories creates a significant price spike risk.

Bull case (crude): Brent returns to $95-105 as inventory draws intensify and spare capacity stays near zero, with any demand recovery creating a sharp price response. Base case: WTI $65-85, Brent $70-95, with gradual normalization of Hormuz flows in H2 2026 driving late-year softening. Bear case: WTI sub-$60 if the Iran conflict resolves quickly and OPEC+ floods the market with restored supply.

The Strait of Hormuz closure remains the single most disruptive factor in global energy markets. Approximately 20% of the world's oil and 25% of LNG transits this chokepoint. The effective blockage since early 2026 has forced massive rerouting of energy flows, with Middle East exporters unable to ship normal volumes to Asian and European buyers. The EIA's base case assumes incremental resumption of flows beginning in Q3 2026, but this timeline is highly uncertain — any delay in negotiations or renewed hostilities would keep markets in a state of acute shortage through year-end.

US crude production has plateaued near 13.5 mb/d, below the 13.7 mb/d record set in late 2025. The Permian Basin, which accounts for roughly 45% of US oil output, is seeing declining well productivity as operators exhaust the best drilling locations. Average well productivity in the Permian has declined by approximately 15% from 2023 levels, requiring more drilling to maintain flat production. The EIA's STEO projects US crude output averaging 13.7 mb/d in 2026, but this depends on drilling activity remaining elevated at current levels.

Global oil demand composition is shifting toward non-OECD markets. While OECD demand is expected to decline modestly in 2026 (down 0.2-0.3 mb/d per IEA estimates), non-OECD demand continues to grow, led by India, China, and other Asian economies. India's oil demand grew 5-6% in 2025 and is projected to continue at a 4-5% pace in 2026, fueled by rising vehicle ownership, expanding petrochemical capacity, and growing aviation demand. This structural shift toward Asia has important implications for crude quality preferences and trade flows.

The natural gas market's regional divergence is creating competitive advantages for US manufacturing. The Henry Hub price at $3.245/mmbtu is approximately 4.5x cheaper than TTF on an energy-equivalent basis. This cost advantage has driven a reshoring of energy-intensive manufacturing to the US, including chemicals, fertilizers, steel (EAF), and data centers. The IEA notes that the US is experiencing an 'industrial renaissance' driven by cheap gas, with chemical and industrial investment announcements exceeding $200 billion since 2023.

Renewable energy growth continues to reshape the power generation mix, with implications for coal and gas demand. Global renewable capacity additions are projected at over 700 GW in 2026, with solar PV accounting for more than 60% of new capacity. However, intermittent generation requires gas-fired power for grid balancing, creating a complementary rather than competitive relationship between renewables and gas. Coal demand remains surprisingly resilient in Asia, where China and India continue to build coal-fired capacity to meet growing electricity demand from manufacturing, air conditioning, and EV charging.

The US Strategic Petroleum Reserve (SPR) situation is an important factor for crude oil market stability. The SPR was drawn down to approximately 375 million barrels after the historic 2022 releases, well below the peak of 727 million barrels in 2010. The Biden administration initiated a slow refill program in 2023-2024, but the pace of refilling has been inconsistent. At current WTI prices around $68/bbl, the SPR refill could accelerate, adding incremental demand that tightens the physical crude market. The Department of Energy has indicated that it is monitoring domestic crude prices to find favorable refill opportunities, with target prices reportedly in the $67-72/bbl range.

The OPEC+ production dynamics continue to evolve in the context of the Iran conflict. The UAE's departure from OPEC in early 2026 was a historic shock to the organization, reducing OPEC's effective coordination capacity. The remaining OPEC+ members face a difficult balancing act: maintaining price support through output restraint while accommodating the return of Iranian supply if the conflict resolves. Saudi Arabia has indicated it prefers to manage supply in coordination with Russia, but the internal cohesion of the group has been tested by the UAE exit and the pressure of lost revenue from Iran's disrupted exports.

European energy security has been fundamentally reshaped by the Iran conflict. EU dependence on Middle East gas and oil has been exposed as a vulnerability, accelerating the energy transition and diversification of supply sources. European LNG import terminal buildout continued through 2025-2026, with new regasification capacity coming online in Germany, Italy, and the Netherlands. However, these terminals are competing for limited global LNG supply, keeping TTF prices structurally elevated. The EU's REPowerEU plan targets of eliminating Russian gas imports have been complicated by the need to replace Middle East volumes as well, creating a more acute supply challenge than initially anticipated.

Asian energy demand growth is the defining long-term theme in global energy markets. India is projected to be the largest source of oil demand growth through 2030, with its crude consumption expected to reach 7-8 mb/d by the end of the decade. China's oil demand growth has moderated as its economy rebalances toward services and EV adoption accelerates, but its crude demand remains above 16 mb/d — making it the world's largest importer by a wide margin. Chinese natural gas demand continues to grow at 5-8% annually as the country shifts from coal for winter heating and industrial processes, driving demand for both pipeline gas from Russia and Central Asia and LNG from global markets.

The interplay between energy prices and inflation is a critical macro factor for all commodity markets, not just energy. Higher energy prices increase production costs across virtually all industrial sectors, from mining and manufacturing to transportation and logistics. The World Bank projects an overall energy price surge of 24% in 2026. This has implications for central bank policy — persistent energy-driven inflation could keep interest rates higher for longer, impacting the economic growth outlook and, by extension, industrial commodity demand. Procurement teams should incorporate energy price scenarios into their broader commodity cost forecasting, as energy costs represent 5-15% of input costs for most manufactured products.