The Duration Trade: Crude and Products, with Emily Kyne

Podcast Briefing: an Edited Q&A

The following Q&A has been adapted from the HC Commodities Podcast and edited for clarity and length.

Oil Returns to Surplus

Paul Chapman: The oil market is back in surplus. How did we get back to that position?

Emily Kyne: It is for October. We are at the time of year when we tend to see refinery maintenance, although the amount of capacity taken offline this fall is lower than the five-year average. Demand has also declined across the Northern Hemisphere.

We’ve seen a significant reduction in supply compared with last year and lower refinery runs because of what’s happening in Russia, the Middle East and discretionary choices being made in China. But despite that, when you look at the high-frequency data, the numbers actually look okay for October. 

How Middle Eastern Crude Keeps Flowing

Paul Chapman: When you’re talking to traders, what is the state of crude flows in the Middle East at the moment?

Emily Kyne: The best way to characterise it is incredible resilience and redundancy on the part of producers in the region. We’ve seen an enormous number of workarounds.

The Saudis have moved a significant amount of crude from the eastern coast to the western coast and the Red Sea. The Emiratis have increased flows outside the Strait of Hormuz to Fujairah, where there are direct loadings and significant ship-to-ship transfer operations.

Saudi Arabian flows are now close to pre-war levels, at around seven million barrels a day. Through the Strait of Hormuz itself, flows are at about 80% of pre-conflict levels, but a lot of that volume has simply been rerouted. Iran is the most affected because much of its volume remains blockaded. 

The Freight Premium Behind Expensive Oil

Paul Chapman: Is oil around $100 because freight rates have made it difficult to get crude to the refinery, or is it pricing in the risk of renewed hostilities?

Emily Kyne: The delivered cost of crude is actually considerably higher than $100 a barrel. At the peak, anything loading in the Strait of Hormuz and being discharged into a VLCC in the Gulf of Oman could cost another $10 to $20 a barrel, and moving it from the Middle East to the Far East could add another $20.

At one point, VLCC freight from the US Gulf Coast to the Far East reached $80 million for a single transit, north of $1 million a day. That translated into more than $40 a barrel in freight.

But there is also clearly a geopolitical risk premium. Since mid-September, the back of the curve has moved substantially higher. The market is waking up to the reality that there may be no easy way out. 

The Limits of the Strategic Petroleum Reserve

Paul Chapman: The SPR releases are becoming depleted. Is it now also becoming economically difficult for buyers to take that crude?

Emily Kyne: Yes. The issue is that US SPR releases are loans, not outright sales, so buyers must repay the barrels. If the spreads aren’t in the money and you can’t lay off that risk further down the curve, you don’t necessarily want to take it.

Freight has compounded the problem. Buyers simply did not want US Gulf Coast crude when it became too expensive to move, and refiners started stepping back from the market. 

China Returns to the Market

Paul Chapman: What about China? Earlier in the year, one reason oil didn’t move higher was that China wasn’t buying. What has changed?

Emily Kyne: China is a bifurcated market. State-owned refiners operate differently from independent refiners, and the independents are extremely margin-sensitive.

Earlier in the year, Middle Eastern crude became very expensive and refined-product export restrictions destroyed refining margins. A lot of independent refiners brought maintenance forward, and refinery runs fell sharply.

Now you have the opposite dynamic. Import quotas work on a “use it or lose it” basis, creating an incentive to buy toward the end of the year. That coincides with seasonally stronger demand across Asia, from Diwali in India through preparations for Lunar New Year in China.

On top of that, Chinese state-owned companies are expected to increase inventories by roughly 400,000 barrels a day from November through April. So you have increased demand arriving at a fairly difficult moment for the global market.

Has the “Dieselpocalypse” Really Gone Away?

Paul Chapman: Has anything directionally changed in the diesel story, or are we still heading towards higher prices for longer?

Emily Kyne: We’ve kicked the can down the road. The market is missing around 1.3 million barrels a day of seaborne diesel supply, roughly one million barrels from the Middle East and another 300,000 to 350,000 from Russia. Europe is particularly exposed because it depends heavily on those marginal seaborne barrels.

Strategic stock releases in Europe have taken some of the froth out of the market, but they are a one-shot measure. Once those barrels have been released, they’re gone. If Russian supply doesn’t materially return, you then move into spring refinery maintenance in Northwest Europe and the United States.

That is why the real concern is the first quarter. We haven’t solved the diesel problem. We’ve pushed it further down the road. 

Europe’s Growing Reliance on US Refining

Paul Chapman: With refinery capacity lost in Europe and elsewhere, how much of the burden is now falling on the US?

Emily Kyne: The US is doing a lot of the heavy lifting. US diesel now represents around 50% of the supply being imported into Europe, which is significant.

The concern is that US refineries are running very hard, and we’ve started to see unplanned outages more frequently. These are huge, complicated machines. They need downtime, catalysts need replacing and units need cleaning.

India and China are adding refining capacity, which should help bridge some of that gap, but right now Europe remains very dependent on US supply. 

What the Options Market Is Telling Traders

Paul Chapman: As we head into these crunch weeks, what is the trading activity telling us?

Emily Kyne: We’ve seen increased open interest in the December contract, which tends to happen as the risk premium rises. Buyers are likely hedging against further escalation in the Strait of Hormuz, and there is significant pin risk around $100.

What’s particularly interesting is the back of the curve. Since mid-September, there has been a noticeable acknowledgement of duration. Calendar 2027 WTI was trading around $75 in mid-September and has moved to roughly $87 to $88, while Brent has moved close to $100.

That matters for producer economics. At these levels, producers can lock in returns and start making capital deployment decisions. 

The Market Starts Pricing the “Duration Trade”

Paul Chapman: Have we effectively settled into a pattern where, short of a much larger escalation, oil oscillates somewhere around this $80 to $100 range?

Emily Kyne: Eighty to $100 works. Above $100 becomes very difficult for the macro economy.

More importantly, Middle Eastern producers appear to have understood earlier than everybody else that this could last a long time. They are investing accordingly, including new pipeline capacity designed to reduce their reliance on the Strait of Hormuz.

At the very least, we are likely to remain in a risk-premium environment for the next year. Even if the conflict were resolved tomorrow, strategic stockpiles would still have to be refilled. More likely, the Strait remains an encumbered waterway.

Supply might look okay today, but this is still a tight market. One thing goes wrong and suddenly the marginal molecule can move dramatically in price. 

Building Around the Strait of Hormuz

Paul Chapman: If everyone is trying to build pipelines away from the Strait of Hormuz, does its importance eventually diminish?

Emily Kyne: Potentially. ADNOC is expanding the Habshan-Fujairah pipeline, which should add roughly 1.5 to 1.8 million barrels a day of capacity towards the end of 2027. The Saudi East-West pipeline could add another three million barrels a day, although that is more likely a 2028 or 2029 story.

Iraq is also looking at ways to increase capacity towards Turkey or the Mediterranean through Syria. Everyone is trying to de-risk their exposure.

The infrastructure itself remains vulnerable, but there is a point at which the game theory around the Strait changes because these workarounds become material. 

Higher Prices Bring New Supply

Paul Chapman: If today’s prices signal new investment, how quickly can additional crude actually come onto the market?

Emily Kyne: Short-cycle production can respond relatively quickly. For a typical shale pad in the US or Canada, you could see production around 20 to 24 weeks after a rig is initially deployed.

We’re already seeing operators in the Permian redeploy from gassier areas towards oilier acreage because the revenue incentive is there.

Offshore projects are different. New production from Brazil, Argentina and Guyana is much more capital intensive and, once those projects are online, they are unlikely to be switched off quickly even if the price signal changes. That creates a lag in both directions and raises the risk of significantly more supply later in the decade.

Venezuela Returns, but Infrastructure Is the Constraint

Paul Chapman: Is Venezuelan production going to go materially higher, or do the infrastructure constraints prevent that?

Emily Kyne: The big issue right now is power. Vessels sometimes wait up to 30 days to load, not because the crude isn’t available, but because the power system isn’t reliable enough.

Exports have recovered to around one million barrels a day, with roughly 600,000 to 700,000 barrels going to the US Gulf Coast. But we don’t expect production to increase materially in the near term.

Chevron has announced a multi-billion-dollar commitment that could add roughly 300,000 barrels a day in the Orinoco Belt, but that is an end-of-the-decade story. Fixing the grid and wider infrastructure will not be a quick process.