Crude oil markets have stabilized in mid-July after a brutal Q2 sell-off that erased $27/bbl from Brent prices. The collapse from April's $107/bbl peak to a June trough of $73/bbl was driven by a confluence of macro headwinds: the Fed's hawkish pivot, slowing global economic growth, and unexpected inventory builds in every major consuming region.
The EIA's Short-Term Energy Outlook, published in early July, projects Brent averaging $74/bbl in Q3 2026, a $27/bbl reduction from last month's outlook. The agency expects ongoing oil inventory accumulation over the coming quarter, with global oil production exceeding consumption by roughly 1.2 million barrels per day. OPEC data shows the cartel's production rose by 280,000 bpd in June to 27.3 million bpd, led by Saudi Arabia and Iraq, as the group slowly unwinds the voluntary cuts implemented in 2024.
WTI's discount to Brent has widened to approximately $4.73/bbl, above the historical average of $3-4/bbl. This reflects growing US production and a shift in global trade flows. US crude production hit 13.4 million bpd in June, just shy of the record 13.5 million bpd set in late 2025. The Permian Basin continues to deliver production growth of 300,000 bpd year-on-year, though the pace of growth is slowing as operators focus on returns over volume.
Natural gas markets are a study in regional divergence. US Henry Hub prices at $2.89/MMBtu remain near multi-month lows, suppressed by record production of 107 Bcf/d and mild summer weather across most of the Lower 48. Storage inventories stand at 3.3 Tcf, 12% above the five-year average. The EIA projects Henry Hub averaging $3.00/MMBtu in Q3.
European natural gas tells a completely different story. TTF prices at €54.92/MWh ($16.35/MMBtu) have risen 31% over the past month, driven by concerns over LNG supply availability and the ongoing phase-out of Russian pipeline gas via Ukraine. LNG spot prices in Northeast Asia (JKM) have exceeded $18/MMBtu, creating a bidding war between European and Asian buyers for flexible cargoes. The spread between US Henry Hub and TTF — roughly $13/MMBtu — means LNG exports from the US Gulf Coast remain extremely profitable, driving utilization at Cheniere's Sabine Pass and Corpus Christi terminals above 95%.
The global oil supply picture is more complex than the headline surplus suggests. While OPEC+ is adding barrels, spare production capacity has fallen to 5.5 million bpd from 6.5 million bpd a year ago. The reduction comes from a combination of natural decline in existing fields and underinvestment in new capacity. Saudi Arabia's spare capacity is estimated at 2.5 million bpd, UAE at 1.4 million bpd, Iraq at 600,000 bpd, and Kuwait at 500,000 bpd. The remaining 500,000 bpd is spread across other OPEC+ members. This cushion is adequate for normal market fluctuations but would be quickly consumed in the event of a major supply disruption.
Refining margins are the hidden story in energy markets. Global refining capacity has contracted by 3.5 million bpd since 2020 as the energy transition narrative discouraged new investment. Three US refineries (LyondellBasell's Houston refinery, Phillips 66's Rodeo facility in California, and one small East Coast plant) closed permanently in 2025-2026. European refineries are running at 87% utilization, the highest in a decade. The result is that the price of refined products (gasoline, diesel, jet fuel) is decoupled from the price of crude oil. Even if crude falls to $70/bbl, diesel prices will remain elevated because there simply aren't enough refineries to meet demand.
The natural gas market is a tale of two hemispheres. US Henry Hub at $2.89/MMBtu reflects a self-sufficient North American market with abundant supply and limited export capacity relative to production. European TTF at $16.35/MMBtu (€54.92/MWh) reflects a continent that has structurally lost its primary gas supply (Russian pipeline gas) and must compete in the global LNG market for marginal cargoes. The six-fold premium of TTF over Henry Hub is not a temporary anomaly — it is the new normal for European energy buyers who have traded cheap Russian pipeline gas for expensive global LNG.
LNG markets are facing their first real stress test of the post-Russian-gas era. Global LNG supply grew only 2% in H1 2026, constrained by maintenance outages at Australia's Gorgon and Wheatstone facilities, feedgas constraints at Angola LNG, and construction delays at projects in Qatar and the US Gulf Coast. Meanwhile, demand growth from Asia (particularly China and India) has been running at 8% annually. The result is an LNG spot market where cargoes in Asia are trading at $18-20/MMBtu while European buyers bid up TTF to secure supply. This transatlantic-Asian bidding war is the defining feature of the 2026 gas market.
US diesel and jet fuel markets face a structural shortage of hydroprocessing capacity. The global shift toward renewable diesel production has converted 15% of conventional hydrotreating capacity to renewable feedstocks, removing it from the pool that produces ULSD diesel. The result is that diesel crack spreads — the premium of diesel over crude — have averaged $28/bbl in 2026, compared to a historical average of $15/bbl. For logistics-intensive procurement teams, rising diesel costs are the single largest energy-related input after electricity. The IIJA is funding 4.2 GW of new hydroprocessing capacity, but this will not come online before 2028.
The energy transition's impact on oil markets is real but overstated in the near term. Global oil demand grew 0.8% in H1 2026 year-on-year to 103.5 million bpd, driven by aviation (jet fuel demand is now 18% above pre-COVID levels), petrochemical feedstock demand in China and India, and diesel demand in emerging markets. EVs are displacing roughly 400,000 bpd of gasoline demand in 2026, but this is offset by growth in other sectors. The IEA's peak oil demand thesis — that global consumption will plateau before 2030 — remains intact, but the plateau is higher and flatter than earlier models predicted.
The US Department of Energy's Strategic Petroleum Reserve (SPR) stands at 590 million barrels, down from 638 million barrels in January 2026 after a drawdown to counter the April oil price spike. The Biden administration has committed to refilling the SPR when prices are below $75/bbl WTI. This creates a demand floor — any sustained decline below $75 would trigger government buying of 3-5 million barrels per month. This is a structural factor that limits the downside in US crude prices.
The shipping and logistics disruption in energy markets cannot be overstated. Red Sea instability redirected 15% of global tanker traffic around the Cape of Good Hope in Q2 2026, adding 10-14 days to voyage times between the Middle East and Europe. This has driven tanker freight rates to $75,000/day for Very Large Crude Carriers (VLCCs), up from $35,000/day in early 2025. Higher freight costs add $1.50-2.00/bbl to the delivered cost of Middle Eastern crude in Europe. This structural cost increase is partially responsible for Brent's premium to WTI.
Coal markets remain relevant to energy procurement despite the energy transition. Newcastle coal futures have stabilized at $145/t, up from $120/t in January, driven by Asian demand growth and supply constraints in Australia and Indonesia. Coal-fired power generation in China and India grew 5% year-on-year in H1 2026 as electricity demand growth outpaced renewable capacity additions. For procurement teams with direct coal exposure, the market is in a structural deficit that will persist until 2028, when the next wave of Australian and Indonesian mine expansions come online.
Coking coal (metallurgical coal for steelmaking) is facing its own supply-demand dynamics separate from thermal coal. Australian premium hard coking coal (PHCC) is trading at $285/t, up 15% year-on-year, reflecting tight supply from Queensland mines affected by heavy rainfall and mine plan disruptions. For steel mills that rely on coal-based blast furnace production, coking coal costs now represent 35-40% of total steelmaking costs. The shift toward electric arc furnace (EAF) steelmaking in the US is partially motivated by the desire to eliminate coking coal exposure.
The energy procurement strategy for 2027 should begin now. Based on the EIA's projections, energy prices will remain below 2022 crisis levels but above the 2015-2020 average for at least the next 12-18 months. The key risk factor is the US election — a change in administration could significantly alter the regulatory landscape for oil and gas leasing, LNG export permitting, and renewable energy tax credits. Buyers should limit fixed-price contracts to 12-month terms and maintain flexibility to adjust as the policy landscape evolves after November.
Energy procurement requires separate strategies by product. (1) Crude oil: Buy 3-month WTI hedges at $75-80/bbl for transportation fuel exposure. The current recovery from June's lows may be fragile — OPEC+ spare capacity at 5.5 million bpd provides a supply cushion. (2) Natural gas: US buyers should not hedge — the $2.89-3.00 range is a buyers' market that will persist until winter. European buyers face a different reality: lock in TTF volumes for Q4-2026 at current levels, as winter supply risk is real. (3) ULSD/diesel: The refining system is running near capacity globally at 84.5% utilization. Diesel crack spreads remain elevated at $28/bbl — consider buying ULSD futures to cap fuel costs for fleets and logistics. (4) LNG: Asian and European buyers should secure cargoes for Jan-Feb 2027 delivery now, as winter premiums will exceed current levels.