Crude markets look remarkably strong for a time when refinery works and poor margins should sap demand. Some of the strength is due to temporary factors such as weather, Turkish straits delays and Chinese teapots deciding to maximise import quotas early. But supplies are coming in lower than expected—particularly from OPEC—which is helping to offset lower demand. Once the straits delays clear up and turnarounds are in full swing (March–May barrels), the physical market is likely to soften, but the weakness is unlikely to be as acute if the supply losses continue.
The outage at the 0.3 mb/d Sharara field seems set to be prolonged, forcing us to reduce our Q1 19 Libyan output estimates by 0.3 mb/d to 0.8 mb/d. Saudi production is also lower, set for 10.1 mb/d in February, with Q1 19 estimates lowered by 0.1 mb/d. Finally, while the market remains fixated on how the overthrow of the Maduro regime can unleash millions of barrels of oil from Venezuela, the near-term prospects are grim. With storage full and diluent supplies cut off, production is already shutting in. We estimate lost DCO output of at least 0.24 mb/d for February.
As such, we have lowered our Q1 19 OPEC output estimates from 31.0 mb/d to 30.5 mb/d. Even adjusting for higher refinery works (which have risen by 1 mb/d vs a month ago), this reduces our Q1 19 crude builds to 0.2 mb/d. This figure will rise if run cuts are material, but diesel will tighten.
The conundrum remains, however. How can one explain US crude production rising by 0.35 mb/d (with 0.26 mb/d of that in crudes above 40 API) m/m in November 2018 and yet USGC refiners cutting planned runs due to the tightness in sour crude and even importing some West African crudes? Clearly, there is a quality mismatch that is making US shale growth slightly less relevant.
|Atlantic Basin differentials, $ per barrel||OPEC production, y/y change, mb/d|
|Source: Argus Media Group, Energy Aspects||Source: Energy Aspects|