Crude oil markets are in the grip of a supply-driven downturn. WTI crude slipped below $68 per barrel on July 13, with Brent trading at $71.55, as OPEC+'s decision to proceed with an additional 250,000 b/d output increase for August collided with mounting evidence of slowing demand growth. The EIA's July Short-Term Energy Outlook revised its Brent forecast down sharply, now expecting an average of $70/barrel in Q4 2026 compared to the $103 average in Q2 2026 — a 32% collapse in six months.
The supply story is straightforward: OPEC+ has been systematically unwinding the production cuts implemented in 2023-2024. The group's August increase brings cumulative additions to approximately 2.5 million b/d since the unwinding began, with a further 500,000 b/d targeted by year-end if market conditions allow. J.P. Morgan Global Research's oil market analysis projects that global oil supply will outpace demand growth in 2026, with the surplus concentrated in the second half of the year.
Demand growth is softening from earlier expectations. The EIA projects global oil demand averaging 105.2 million b/d for 2026, representing growth of 0.9 million b/d over 2025 — roughly half the growth rate of 2024. The deceleration is geographically concentrated: Chinese demand growth has slowed to 250,000 b/d as the property sector drag persists and the transition to new energy vehicles accelerates (BEVs + PHEVs now represent 48% of Chinese new car sales). European demand is flat, and US demand growth of 120,000 b/d is driven entirely by petrochemical feedstock demand rather than gasoline.
The inventory picture is shifting rapidly. Global oil inventories are projected to fall by 2.2 million b/d in Q3 2026 — a sharp revision from the June forecast of 7 million b/d declines and an even steeper contrast with the 5 million b/d drawdown previously expected. The EIA's revision reflects both upward adjustment to supply and downward revision to demand. OECD commercial inventories stand at 2,830 million barrels, slightly below the five-year average but above the level that would trigger significant price support.
Natural gas markets present a divergent picture. US Henry Hub futures have remained relatively stable, averaging $3.19/MMBtu through late June and trading near $3.23 in mid-July. The EIA expects Henry Hub to average $3.67/MMBtu for full-year 2026, down 9 cents from its March forecast. US LNG exports have grown to 17.8 billion cubic feet per day (Bcf/d) so far in July, up from 17.4 Bcf/d in June, as three new liquefaction trains at Plaquemines LNG, Golden Pass, and Corpus Christi Stage 3 continue their ramp toward full capacity.
European gas markets tell a different story. TTF natural gas prices have surged to €49.63/MWh on July 13, up 16.76% over the past month and 39.99% year-over-year. The spike is driven by storage deficit concerns: EU gas storage facilities entered the summer injection season at 54% capacity, compared to the five-year average of 62%. The rapid drawdown over the 2025-2026 winter — the coldest in seven years across Northern and Central Europe — left the region scrambling to refill inventories at a time when Russian pipeline gas flows through Ukraine remain disrupted.
The LNG shipping market is tightening in response to the European storage imbalance. Modern LNG carriers with flexible destination clauses are commanding premium charter rates, with spot day rates for tri-fuel diesel electric (TFDE) vessels reaching $85,000/day — the highest since the 2022 energy crisis. LNG shipping tightens as Europe's storage deficit and winter price risk drive aggressive positioning. The IEA's Q1 2026 Gas Market Report notes that stronger LNG supply growth, driven by new US and Qatar capacity, is expected to provide partial relief, but the timing of new capacity and the pace of European storage refilling remain critical uncertainties.
The energy market is entering a period of regime divergence. For crude oil buyers, the trajectory is decisively downward through Q4 2026: the combination of OPEC+ supply additions, slowing demand growth, and the roll-off of the peak summer driving season points to WTI testing $60-65/barrel by November. The EIA's Q4 Brent forecast of $70/barrel provides a reasonable planning assumption, but the risks are skewed to the downside if OPEC+ maintains its current unwinding schedule. Diesel and jet fuel buyers face a more complex picture: crack spreads remain elevated at $22-25/barrel for ULSD, supported by low distillate inventories globally and the IMO 2020+ premium for low-sulfur marine fuel. Gasoline buyers should expect the seasonal autumn demand decline to compress margins, with RBOB crack spreads potentially falling below $10/barrel by October. For natural gas buyers, the European premium over US pricing is the defining feature. At the current TTF-Henry Hub spread of approximately $13/MMBtu (on an energy-equivalent basis), US LNG exporters are earning extraordinary margins, but European buyers are paying the price. The key procurement hedge for European gas buyers is to maximize storage injection through August while forward prices remain below €50/MWh. For US buyers, the stable Henry Hub outlook at $3.00-3.50/MMBtu supports locking in annual fixed-price contracts, particularly for winter 2026-2027 delivery. The three new LNG trains coming online — representing approximately 3.5 Bcf/d of incremental US liquefaction capacity — will gradually push more gas into the global market but also tighten domestic US supply-demand balance, creating a floor under Henry Hub at $2.75-3.00.