Crude steady. Products tight. Gas enters winter.

Brent ended October at 120.15 USD/b, 4.6% above its level on 1 October, but prices moved abruptly: by 2 October the price had already risen to 135.51 USD/b. The monthly average was 123.93 USD/b. WTI remained considerably cheaper, and the average Brent–WTI price spread reached 21.86 USD/b.

The products market was tighter than the crude market. US distillate stocks fell to 99.259 mn barrels, below 100 mn for the first time since 2003. ULSD reached its highest average in the week of 19–23 October, when Brent was already below its average for the first half of the month.

The gas market sent two opposite signals. Between 1 and 30 October the Henry Hub spot price fell by 19.3%, to 2.42 USD/MMBtu. Meanwhile, ACER’s assessment of the European LNG price rose by 39.4%, to 97.170 EUR/MWh, and at the end of the month JKM and TTF converged at about 34 USD/MMBtu.

LPG kept its own momentum. The Mont Belvieu propane price rose by 41.4%, and between 2 and 30 October propane and propylene stocks shrank by 3.738 mn barrels. Such a strong divergence from crude justifies separate monitoring of VLGC freight, exports and petrochemical demand.

In October, the value of a cargo was decided not only by the price of the commodity, but also by the route and the cost of time.

The greatest divergence occurred between European LNG and propane on the one hand and US gas on the other. Brent and ULSD were more stable from the start to the end of the month, but along the way they passed through distinctly different weekly phases.

Brent 125.17 USD/b; propane 0.914 USD/gal; EU LNG 70.23 EUR/MWh

The G7 announced 100 mn barrels of coordinated releases over four months, with a significant share of diesel at the start of the programme. On 2 October Brent reached 135.51 USD/b. On 4 October OPEC+ did not increase the required production level for November.

Brent +1.8%; ULSD +4.2%; propane +4.7%; EU LNG +5.0% against the short week

The EIA published its STEO on 6 October, and on 7 October the IEA called for faster implementation of earlier releases. Hurricane Isaias curtailed output in the Gulf of Mexico; according to BSEE, 62.89% of offshore crude output was shut in on 8 October.

In October, the margin depended on the availability of specific fractions and on logistics, not only on the price of the feedstock.

Brent −1.4%; WTI +3.2%; ULSD +2.4%; propane +11.5%; EU LNG +9.1%

On 14 October the IEA assessed that gasoil would remain in deficit in Q4, and that a rebuild of stocks beyond seasonality was unlikely before the second half of 2027. On 16 October the EPA published a proposal to reallocate additional small refinery exemptions (SRE).

Brent −3.6%; WTI +7.2%; ULSD +3.5%; jet +2.7%; EU LNG +5.3%

S&P Global described JKM rising to about 30 USD/MMBtu on winter purchases by buyers in North-East Asia. ULSD NYH reached its highest weekly average of the month, 5.2008 USD/gal. US distillate stocks fell to 102.824 mn barrels.

Brent +0.1%; ULSD −8.5%; jet −3.4%; propane +3.6%; Henry Hub −12.4%; EU LNG +9.3%

ACER raised its EU LNG assessment to an average of 92.54 EUR/MWh. According to JOGMEC, on 30 October JKM stood just above 34 USD/MMBtu and TTF at 34.0 USD/MMBtu. US distillate stocks fell to 99.259 mn barrels, and propane ended the month at 1.285 USD/gal.

In its October STEO the EIA estimated world production in 2026 at 101.1 mn b/d and consumption at 102.4 mn b/d. The forecast stock draw was 0.7 mn b/d in Q4. In the middle of the month, however, the IEA indicated that September supply had risen by 2.5 mn b/d to 102.3 mn b/d, mainly thanks to Gulf producers.

On 4 October OPEC+ maintained the required production level for seven participants for November. On 12 October the group again emphasised its stabilisation mechanisms. The statements limited expectations of sudden additional volume, but did not halt the gradual improvement in physical flows.

On 8 October S&P Global assessed the WTI MEH arbitrage to Rotterdam at 19.99 USD/b. The same crude had a negative netback to Singapore and North-East Asia: −17.01 and −19.77 USD/b respectively. Europe was therefore the natural direction for the marginal US barrel, provided that freight, quality and delivery date remained covered.

The IEA reported that global diesel exports in September were 700 kb/d lower y/y, and that the loss from Russia and the Middle East totalled 1.3 mn b/d. In Q4 gasoil supply is expected to remain below demand, despite the anticipated increase in refinery runs by the end of the year.

Product deliveries from the Middle East recovered more slowly than crude flows. The IEA estimated September shipments of refined products at 1.9 mn b/d, against 4.7 mn b/d before the war. This limited the scope for quickly passing an improvement in crude supply through to the diesel market.

India gained in value as a flexible supplier. S&P Global reported that September middle-distillate exports reached almost 740 kb/d, and that early-October loadings remained high. Europe and the Mediterranean basin attracted a larger share of cargoes, but the cost of clean tanker freight remained a significant barrier.

The Mont Belvieu spot price rose from 0.909 USD/gal on 1 October to 1.285 USD/gal on 30 October. The weekly average rose in each successive week. At the same time, propane and propylene stocks shrank from 107.846 mn barrels on 2 October to 104.108 mn barrels on 30 October.

The EIA reported that US propane exports averaged 2.0 mn b/d in the first half of 2026, 11% more y/y, and reached a record 2.1 mn b/d in April. Terminal expansion is set to add about 300 kb/d of capacity, but it also increases the market’s dependence on terminals, slots and the VLGC fleet.

The IEA estimated September LPG shipments from the Middle East at 670 kb/d, against 1.5 mn b/d before the war. Lower LPG availability from the Gulf and record US export supply supported global demand for Mont Belvieu propane.

ACER’s LNG assessment rose from 69.692 EUR/MWh on 1 October to 97.170 EUR/MWh on 30 October. ACER indicated that EU hub prices approached 90 EUR/MWh in the middle of the month, and that the conflict in the Middle East had raised the estimated gas import bill by EUR 18–33 billion.

JOGMEC reported that JKM rose from just above 25 USD/MMBtu at the end of September to well above 31 USD/MMBtu on 23 October, and then to just above 34 USD/MMBtu on 30 October. TTF ended the month at 34.0 USD/MMBtu. With such convergence, a flexible cargo had no obvious destination premium.

Henry Hub remained considerably cheaper, but it is not the price of delivered LNG. An export netback must take account of the liquefaction fee, fuel use, freight, boil-off, regasification and contract restrictions. The Freeport LNG outage and the risk to Norwegian deliveries were a reminder that cheap feed gas is not enough without a working supply chain.

EU storage ended October at about 74.6%, against about 71.6% at the end of September. The increase of about 3 percentage points improved the buffer, but did not halt the rise in prices. ACER emphasised the unfavourable winter–summer spread and competition with Asia for spot LNG.

In the US, working gas rose from 3,415 Bcf on 25 September to 3,724 Bcf on 23 October. The latest report showed stocks 38 Bcf, or 1.0%, above the five-year average, but 147 Bcf below the level a year earlier.

The contrast explains the fall in Henry Hub alongside the rise in European LNG. The US had rising stocks and strong production, while Europe paid for transport, liquefaction and rivalry for the cargo. Regional storage is a buffer, but it is not interchangeable without export infrastructure.

The average USGC jet fuel price rose through the first four weeks of the month, reaching 4.6226 USD/gal in the week of 19–23 October. In the final week it fell by 3.4%, to 4.4636 USD/gal, but stayed above its level at the start of the month.

Jet fuel stocks in PADD 3 rose from 13.407 mn barrels on 2 October to 14.875 mn barrels on 30 October. Net production fluctuated between 1.016 and 1.077 mn b/d. The improvement in the local buffer helped the final correction, but the global distillate shortage continued to sustain price risk.

On 1 October Platts launched SAF assessments for the US Gulf Coast and a Brazilian import parity assessment. This increases contract transparency, but does not remove differences in feedstock qualification, emissions intensity, environmental credits and certification costs.

For Q4 the EIA forecast 0.27 mn b/d of renewable diesel, 0.11 mn b/d of biodiesel and 0.05 mn b/d of other biofuels, including SAF, renewable heating oil and renewable naphtha. Full-year renewable diesel production is expected to reach 0.23 mn b/d, about 21% more than in 2025.

On 16 October the EPA proposed two options for reallocating about 770 million additional RINs arising from larger-than-assumed small refinery exemptions for 2025: a split between 2026 and 2027, or moving the whole amount to 2027. The agency did not change the previously set physical volumes of 24.02 and 24.46 billion RINs.

For international trade, the key issue remains the loss or retention of the value of support schemes. The EIA indicated that in the second half of 2025 the US exported about 50 kb/d of renewable diesel and other biofuels, mainly to Canada and Europe. Such a flow does not, however, mean that every cargo will meet the requirements of RED, RFS, LCFS or a national SAF mandate.

Crude and runs. North America and the Middle East had the greatest capacity to deliver an additional barrel, although the recovery of flows from the Gulf remained fragile. Europe and Asia were structural importers of crude; actual availability was decided by freight and by how well the grade matched the refinery configuration.

Refined products. The deficit was widest in diesel and jet fuel. Products and LPG from the Middle East recovered much more slowly than crude. Asia’s export buffer was concentrated in India, South Korea and Singapore, while Europe, Latin America and Africa remained dependent on imports.

Gas, LPG and low-carbon fuels. The US remained the key source of flexible LNG and LPG, but terminals, the fleet and the Panama Canal limited the pace of growth in shipments. Biofuel supply was concentrated in North and Latin America; in Europe, physical availability did not equate to qualification under RED or a national mandate.

Crude, petrol and naphtha. Asia remained the largest marginal buyer of crude, but expensive freight limited its ability to reach for Atlantic barrels. Demand for naphtha was weak, which the IEA linked to negative cracks; petrol was more regional and, after the summer season, gave no uniform global signal.

Diesel, jet fuel and VLSFO. Europe, Latin America and Africa competed for a limited pool of diesel. Aviation demand sustained purchases of jet fuel in North America, Europe, the Middle East and Asia. Singapore needed Western VLSFO components, but the level of freight decided whether the East–West spread translated into a cargo.

Gas, LPG and biofuels. Europe and Asia increased LNG purchases ahead of winter, and JKM and TTF converged at the end of the month. South Asia took up part of the growth in US propane exports. The strongest regulatory demand for biofuels and SAF remained in the US and Europe, while Latin America combined national mandates with a feedstock base.

Crude. On 8 October the published WTI MEH netback from the US Gulf Coast (USGC) to Rotterdam was +19.99 USD/b. The same crude to Singapore and North-East Asia gave −17.01 and −19.77 USD/b respectively. USGC → Europe therefore receives status N, and USGC → Asia-Pacific status Z.

Petrol and naphtha. The Atlantic → Latin America/Africa and Middle East → Asia corridors are structural, but public sources did not give a comparable October netback for all relationships. A status of W or M is therefore a signal to calculate, not a declaration of an open margin.

Diesel. Flows from Asia to Europe and from the US to Latin America were physically confirmed, but backwardation, MR rates, sanctions and voyage time limited the margin. The directions from USGC, the Middle East and Asia to Europe remain natural conditional routes.

Jet fuel. The geography of supply was narrower than for diesel. Asia and the Middle East could supply Europe, but long voyage times and competition from diesel for middle fractions raised the profitability threshold. The matrix therefore does not mark any direction as confirmed by a positive netback.

VLSFO. Western cargoes from North-West Europe (NWE), the Mediterranean basin and Brazil supplied Singapore. The East–West spread reached up to 152 USD/t, but high freight limited arrivals in the first half of the month. The physical flow was visible, but the margin remained dependent on the day of loading and the blending component.

LNG. US → Europe, Middle East → Asia and Africa → Europe are confirmed corridors. At the end of the month JKM was close to TTF, so the value of the Atlantic → Asia route came mainly from the freedom of choice, not from a lasting destination premium.

LPG – US → ARA/NWE. S&P Global indicated that in September Europe took 12 mn barrels of propane from the US, and that average Houston–NWE VLGC freight was 31.27 c/gal, against 30.71 c/gal in August. The corridor is therefore physically confirmed. An open arbitrage, however, requires CIF ARA to cover Mont Belvieu, the FOB USGC premium, the terminal, VLGC freight, losses and financing.

LPG – other directions. US → Asia is also a confirmed flow; Middle East → Asia remained conditional because of limited supply. Latin America and Africa were potential destinations from USGC, but public sources did not make it possible to confirm a positive October netback.

Biofuels and SAF. US → Europe has a confirmed flow, but the value of RINs, LCFS, RED, carbon footprint, certification and duties can completely change the result. The remaining relationships are therefore marked W or M, even where physical trade in feedstock or fuel exists.

October’s commercial value lay in the ability to change source, route and destination.