Crude is cheaper,
distillates remain expensive.

Over three months the market stopped asking whether crude would run short and began asking how quickly supply would return and whether 2027 would bring too much of it. The physical markets for LNG, diesel and jet fuel stayed tight throughout. Shipping constraints, low stocks and a reconfiguration of refinery yields have left the price of a barrel explaining ever less of the cost of finished fuels.

Europe now watches cargo availability as closely as the level of the benchmark. The United States, Nigeria, Canada and the Atlantic projects have taken over part of the marginal producer's role, but longer voyages raise the call on vessels, financing and insurance. A logistics premium is forming that Brent alone does not show.

The Brent path itself was not smooth. From an average of about 104 USD/b in May the market slid to 76 USD/b in early July, rebounded by more than 25 USD within a month and closed July near 97 USD/b, holding August in an 88–97 USD/b range. Crude is cheaper than in May, even though July closed with a range of close to 40 USD/b. The balance of the period and its path through it are two different stories.

In biofuels the direction remains upward, but uneven. HVO benefits from new emission-reduction obligations, SAF from aviation mandates, and biomethane from the rising volatility of imported diesel. The common constraint is bankable feedstock supply and long-term contracts.

Each of these markets has its own critical point. In LNG it is the availability of liquefaction and vessels, in diesel the heavier fractions and hydrocracking capacity, in jet fuel stocks and the flying season. In HVO and SAF renewable feedstocks and regulatory compliance decide.

The June IEA scenario assumed average demand of 103.3 mn b/d and supply of 102.4 mn b/d in 2026. In 2027 the return of supply would be far faster than the recovery in demand, creating a theoretical surplus of about 5 mn b/d. It is precisely that prospect that began to weigh on deferred contracts, even while the physical market stayed tight.

Saudi Arabia, Russia, Iraq, Kuwait, Kazakhstan, Algeria and Oman agreed on 2 August to increase output by 188 kb/d from September. It was the sixth consecutive monthly increase and the formal completion of the unwinding of the voluntary cuts of 1.65 mn b/d announced in April 2023. Some 2 mn b/d of separate group cuts from 2022 remain in force, running to the end of 2026.

The number itself matters less than the scope for delivering it physically – in preceding months higher targets did not always translate into larger exports, owing to disruption to infrastructure and shipping. Delegates signalled a pause in increases in Q4.

Argus material from May, June and July shows three successive phases of the same shock. First the market responded by releasing stocks and by Chinese buying being curtailed. Then came hope of a gradual resumption of shipping. In July risk rose again, and attention shifted from the crude price itself to the safety of crews, insurance and the real throughput of the route.

According to the IEA, loadings from Qatar and the UAE fell in the March–June period by 35 bcm y/y. Output outside the Gulf rose by about 27 bcm, chiefly on new projects and better availability of feedgas for the plants. The global LNG market therefore contracted by about 8 bcm rather than the full 35 bcm.

That is good news for the security of the system, but not enough for Asian importers heavily dependent on Qatar. Argus and Bloomberg described increased spot buying, greater reliance on the US and Canada and a rising cost for the economies of South Asia.

The IEA noted that the JKM premium over TTF averaged about 2.1 USD/MMBtu from March to June. That directed flexible cargoes from the Atlantic basin to Asia. In early August S&P Global assessed September JKM at 21.25 USD/MMBtu, and DES Northwest Europe at 19.255 USD/MMBtu.

Europe entered August with storage 57.1% full, against 68.9% a year earlier (GIE/AGSI data – the lowest for this point in the year since measurement began in 2011; by 26 August the level had recovered to about 63%). The higher summer price did not encourage rapid injection. At the same time weaker industrial demand and higher renewable generation limited the pressure.

Argus described in July a turn by European refineries towards road fuels. Diesel priced above jet fuel, gasoline benefited from seasonal demand and exports, and naphtha from blending. Hydrocracking and FCC returned to positive premiums over Brent after a weak start to June.

What decides is not the sheer size of processing capacity but crude quality, hydrogen availability, plant configuration and the economics of alternative products. One additional tonne of diesel means less jet fuel, or a smaller supply of components for another market.

S&P Global Energy noted that Russian export restrictions and attacks on refining infrastructure have tightened the diesel balance. Europe does not import Russian products directly, but it competes with Turkey, Africa and Latin America for replacement barrels from the US, India and the Middle East.

The 15% m/m fall in Russian product exports in June supported demand for longer clean tanker voyages. In July exports slid to 1.18 mn b/d – the lowest since this series began in 2016. The same volume of trade now absorbs more vessel days and more working capital.

Towards the end of June European jet fuel cheapened markedly against the April peak, but ARA stocks stayed low. In July the stress returned along with competition for middle distillates.

Refineries move part of their yield between jet fuel and gasoil. When diesel offers the higher margin, jet fuel output falls despite rising air traffic. With low stocks, any disruption to supply then hits the market immediately.

IATA lowered its forecast of industry net profit to USD 23bn, with the fuel bill rising to USD 350bn. About one third of consumption is hedged, but many airlines hedge crude rather than the full jet crack. The rise in the product margin therefore remains partly unprotected.

In June global passenger demand fell by 1.7% y/y, although cargo grew. That is the first signal that high prices, longer routes and network disruption are beginning to limit volume. For the fuel market, however, the geography of flying will matter more than global RPK alone.

A high diesel price can improve the relative competitiveness of HVO and biomethane, but it also lifts the cost of the benchmark against which premiums are settled. SAF has a different dynamic: demand is increasingly regulatory, while availability is constrained by investment, certification and long-term offtake contracts.

Low water on the Rhine constrained German physical purchases over the summer, and some participants opted for certificates. At the same time the entry of the German implementation of RED III, plant turnarounds and smaller US exports pointed to a renewed tightening of the balance later in the year.

S&P Global pointed to the need for offtake agreements of 10–15 years. Without them a project has a demand mandate but no stable cash flow. Asia-Pacific may become an important supplier to Europe on the strength of its feedstock advantage, yet whether a delivery qualifies is decided by emissions methodology, certification and the ability to assign the environmental attribute.

In July the IMF forecast growth in the world economy of 3.0% in 2026 and 3.4% in 2027. Energy-importing economies bear the greater cost of the shock, while exporters and states benefiting from the investment boom in technology are more resilient.

The divergence of −2.2% for crude against +19.1% for European gas in the same month shows why a general energy price index is not sufficient to assess the costs of a particular buyer or sector.

An assessment of Brent, TTF or ICE gasoil describes the price of the commodity at a reference point. An industrial buyer pays for something else: for a tonne placed at its terminal, on the agreed date, with deferred payment and a complete set of documents. Between the one and the other lie freight, working capital financing, transhipment and insurance – items that rose faster than the benchmarks themselves this quarter.

The DGDCI is built from Danske Gas's own transaction data. It is neither a market assessment nor a price for contractual settlement. It shows how the cost of performing the same commercial service changes from quarter to quarter.

The benchmark alone is not enough to price a delivery. Only setting the assessment against the actual cost of freight, product availability, the cost of blending and certificates gives the full cost of delivery to the customer – and it is on that we base our pricing per cargo.

The upside risk is logistical and inventory-driven: the next incident could find the market with a smaller buffer than in the spring. The downside risk is a simultaneous rapid return of supply and weaker demand in China, Europe and aviation.

Scenario switching points: regular LNG transits through Hormuz, EU storage rising above the seasonal path, the closing of the USGC–Europe arbitrage, a recovery in Russian product exports and a fall in the European diesel crack below 35 USD/b.

The statements below carry a numerical threshold and a date of resolution. The next issue will open with their settlement, whatever the outcome.