The Crude Report: State of the benchmarks

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Argus Crude editor Michael Carolan returns to the podcast to talk with James Gooder about the current state of crude benchmarking in a time of upheaval.

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James Gooder: Hello, and welcome to another edition of "The Crude Report." This is a regular podcast from Argus Media about goings-on in the crude markets. And this time we are going to have a look at the state of the benchmarks. Of course, this is a subject close to our hearts at Argus. We produce prices and benchmarks in different regions. And a lot of these prices, these key crude prices, are under scrutiny.

I'm joined today by Michael Carolan, who's the editor of the Argus Crude Report. So let's get into it. We've got crude prices not at, but close to record highs, and products prices are surging around the world. There's some very wide crack spreads and refining margins. So there's a lot of focus right now on how oil is priced, as well as the outright levels that it is priced at. And Brent, of course, the most widely used price benchmark of all, is embarking on fundamental change over the next few months. So in this edition of "The Crude Report," Michael and I are going to have a look at how Brent is being rebuilt, while also casting an eye over the state of some of the other crude price benchmarks in Asia and the Americas.

But let's start with Brent. There are three interdependent pillars of the Brent Complex, and complex, of course, is the word. We've got the ICE Brent futures contract, where most of the liquidity is. A lot of the price discovery happens on the futures contract. And then there's the forward contract, through which those positions can turn into physically deliverable cargos. And then lastly, the Dated Brent, or what we call North Sea Dated physical benchmark that reflects the prices of physical crude cargos in the North Sea.

Now, the market has been wrangling for a couple of years over whether to add the U.S. WTI, that's West Texas Intermediate crude, to the North Sea Dated basket. There's five crudes in that basket already, but they're all in the North Sea. And there seems to have emerged a consensus that this is a good idea, but there're still are very stark differences of opinion on how to integrate it particularly...and we're getting straight into the technicalities here I guess, but particularly, when it comes to the forward contract, which is often known also as the cash contract. But maybe, Michael, you can explain why the forward contract is such an important part of the Brent Complex.

Michael Carolan: Well, I will try. And like you said, complex is definitely the keyword here. The forward contract is basically what links the futures to the physical in the Brent Complex. Like you said, there are three pillars of the complex:

  • Dated Brent, which is used as a benchmark by many, but actually has very few participants involved in the trade underpinning it
  • The forward or cash market, which has even fewer participants, but involves the transfer of physical cargos of crude
  • And ICE Brent, now that is where the mass participation is, but it's not where you would go to buy physical Brent Crude

ICE Brent's only link to the physical market is through the cash contract. ICE Brent's expiry price is set using the assessment of the cash market, and the exchange futures for physical contract links ICE Brent to the cash market, not to Dated.

Of course, the forward market also forms the lion's share of price discovery when it comes to Dated Brent and North Sea Dated. Dated Brent represents the price of Brent, Forties, Oseberg, Ekofisk, and Troll in the coming month. But the starting point for getting to that price is the forward cash price. So while the intricacies of how this market operates is really of interest to only a few companies, and individuals, and price reporting agencies in Europe, the fact that it operates smoothly is essential to how the global crude is priced.

James: Right. So it's really...what we're talking about here is the kind of cement or the link that holds this whole Brent Complex together. And as I was saying before, if you were to add crude from outside the region into this complex, it would really kind of shake things up. And so, having explained how it fits together, what are the different views currently being aired about how this benchmark should be updated and kept current?

Michael: Well, there are a number of different options, and all of them has to be said are fiendishly complicated. What the market is trying to do is to fit in a crude from a different region, with different trading patterns, and different logistics into a FOB North Sea contract. So various adjustments need to be made for timing of delivery, and freight compensation, whatever method is decided upon.

But there appear to be two schools of thought at the moment. One, our competitors Platts suggested in February included WTI cargos deliverable into the cash contract on a FOB basis. So with a buyer effectively collecting its cargo at the U.S. Gulf Coast with various freight compensations then coming into play.

Then Shell came up with its own proposals. To be accurate, these aren't proposals. Shell amended its own SUKO 90 contract. And that is the contract which has governed North Sea trade for 30 years. In its amendments, it stipulated that WTI would be deliverable on a delivered Rotterdam basis only, thereby avoiding any risk of U.S. regulators or tax authorities getting involved.

Now since then Vitol, another big player in the market, has been circulating its own proposals, which stipulate WTI on a FOB basis. Many expect that to result in a more tradeable contract. But we've also heard talk that BP favors such a FOB contract, although they have yet to say anything publicly.

Now, the difference between these ideas is perhaps less interesting, that the fact that there are differences. Shell has amended this contract many times over the years, adding Forties, Oseberg, Ekofisk, and Troll to the contract, introducing quality premiums, etc. Now, these changes always generated a few complaints in the market, but generally, the market came round to the changes and they were accepted. But this split looks a bit more serious. We could end up with two or more contracts with differing terms and conditions. And it's hard to see how a forward market could operate when nobody can agree on such a fundamental aspect.

And time is running out. WTI will be part of Dated Brent from next summer. So any changes to the forward contract really need to be in place by February at the latest.

James: Yeah. That gives a sense of the urgency, but why is this happening now? Why are these things being shaken up in such a way that's generated so much heat, if not much light?

Michael: Well, we and others have been saying for some time that the Brent Complex needs an injection of market liquidity. The existing grades, the North Sea grades, Brent, Forties, Oseberg, Ekofisk, and Troll, volumes of those are all declining and have been for years. It's a mature region, and it's only going to get worse. The arrival of U.S. crude in significant volume since 2016 has provided an option. So the liquidity is there, it just doesn't quite match what we're used to in Europe.

Now, of course, the disappearance of Russian crude this year from the spot market has added to that momentum. We basically have very little visible spot trade going on now that isn't WTI. So adding those volumes could be a bit of a game-changer for the North Sea market.

James: That's interesting. I mean, we certainly heard from some market players that there used to be two liquid and transparent crude markets available to the European buyer. One was U.S. exports and the other was Russian exports. And now given that Russia is being carved out certainly of the European market, if not the wider markets, then one of those sources of liquidity is gone. So it does seem as if U.S. crude may ride to the rescue.

Michael: Right. And you said at the beginning, Brent is obviously used far beyond the Atlantic basin. But what do you expect the impact of these changes will be in Asia for instance?

James: Well, that's a good question. As you say, Brent is not just a European benchmark. It's used all around the world. I mean, most Middle East Gulf crude suppliers continue to use medium-sour Oman and Dubai grades as benchmarks when they're pricing their crude exports to Asia-Pacific. And of course, that remains, in volume terms, the biggest crude kind of route of all from the Middle East to the Far East. Anyone importing crude into Asia from further afield has to ensure that their crudes are competitive against crudes that are priced in that way against Oman and Dubai.

Dubai, of course, in some ways is an extension of Brent. The greatest liquidity underpinning that benchmark, as we see it, is really provided by the Brent to Dubai exchange of futures for swaps market, by which people trade the difference between Brent and Dubai. And that reflects, of course, the geographic spread, as well as the quality difference between those light-sweet and medium-sour grades.

That's currently a very wide spread. I think it's over $10, so that really hampers sales East from places like the North Sea and West Africa. But as I've said, Brent is kind of woven through that trade. And then Brent itself, either the futures price, which is used in China, for example, or Dated Brent. Platts Dated Brent is used for exports from Australia, Malaysia, Vietnam, Indonesia. Places like that. It's really kind of the lingua franca in Asia of crude pricing.

Now, of course, a lot of the changes that we're talking about today may erode some of the confidence in this structure, but it certainly looks like it's well built-in for now. But in Asia, it's not the only game in town. There was, just over a year ago, the launch of a new futures contract for Abu Dhabi's flagship Murban Crude on the ICE Futures Abu Dhabi exchange, IFAD as it's known, and that's given the market something to think about and potentially a new pricing basis, especially for light crude cargos flowing into Asia-Pacific. So things like U.S. WTI in particular, which of course, can go to any destination.

The IFAD Murban contracts officially prices all of Abu Dhabi's state-owned ADNOCs term crude exports. And many refiners in Asia-Pacific we hear are also looking at this IFAD Murban price when they're buying WTI or even things like CPC Blend from Kazakhstan via the Med into that Asian region. So just to get a gauge of the demand for and the value of light crude in Asia-Pacific. So it's certainly being looked at.

Michael: Would you say it's well placed to make the move towards becoming a formal benchmark?

James: Potentially. But we do know that these things take a long time. I mean, it took more than 10 years for the DME, that's the Dubai Mercantile Exchange's Oman Futures contract, to gain enough market confidence and momentum to be adopted by Aramco and others as part of their benchmarking. And it will take a while for anyone other than the Abu Dhabi exporters to build Murban into contracts I think. But it is certainly among the alternatives, probably the most likely to grow in usage over the coming years. I mean, it's early days. It takes some time as they say.

Michael: Okay. So if that's Asia, what's happening in the U.S.? I mean, we're all aware of WTI, and that's the heart of the benchmark complex there. But is that still just a domestic reference price for the U.S. market? When exports are sold out of the U.S Gulf Coast, they tend to be priced against Brent futures, right?

James: That's true. But those relationships may change when WTI is injected into the Brent Complex. Whichever way of the two options you've mentioned, whether it's FOB, U.S. Gulf, or delivered Europe. But one way or another, WTI will effectively be setting Brent. At least according to our analysis, it's most of the time the most competitive light-sweet crude in Europe and therefore, under the current method where the most competitive grade sets the benchmark, WTI effectively would be the benchmark in Europe. So what would it mean for WTI to be priced against Brent? There is a risk of circularity there, which is what a lot of the current dispute that you described is partly about. Now, WTI is clearly following, or arguably even leading the global trend higher. The volume of trade on WTI futures is still greater in fact than that on Brent futures, so there's definitely the liquidity there.

So while Brent may be more widely used globally, its only real rival on the global stage is in a strong position to be used more. And as for regional benchmarking trends in the U.S., away from WTI, the main thing over there is that Mars, which is, of course, a medium sour crude produced in the U.S. Gulf of Mexico, which is in some ways a secondary benchmark for medium sour crude over there. It's being pressured at the moment by the release of volumes from the strategic petroleum reserve, so far managing to flow at around the million barrels a day that was originally promised. There was some skepticism that U.S. Gulf infrastructure couldn't handle that much additional volume for an extended period. And while that may have not completely disappeared, that skepticism, there's certainly less doubt around the issue. And this would seem to be making people a bit bearish on medium sour prices, all that extra crude flowing into that region into that market is widening the spreads between WTI itself and the secondary benchmark of Mars.

Mars is a important regional secondary market. It's a bit like Urals used to be in Europe before all of this Russia-Ukraine disruption came in. So it's also, of course, the majority share of the Argus Sour Crude Index, which is a benchmark used by the Saudis and others when they're selling medium sour and heavier crude into the United States. So there's a bit of a knock-on effect in terms of widening those regional benchmark spreads. Interestingly though, the Saudi official selling prices, the formulas that they set against the Argus Sour Crude Index, have been unchanged for the last couple of months. So that may indicate that outright prices are just so high now that they're not really troubling themselves with making big adjustments on the diffs. In other words, it's a sense that the benchmark itself is pricing in all of the market sensitivity that they need it to do.

And then heavier still, we have Western Canadian Select which pipes all the way down across the United States from Canada, of course, and into the U.S. Gulf Coast, which is another kind of secondary benchmark for the heavy sour crudes, challenging things like Maya from Mexico as a regional measure of crude of that quality. And that's coming under pressure as well for similar reasons to Mars. So there's plenty of volume available but the arb to export is not great at the moment, for reasons that we've said in terms of the Brent Dubai spread and so on.

Essentially, we have quite a comprehensive benchmarking system at the U.S. Gulf Coast, which is in ruder health really than the one in Europe. In Europe, we have Brent, of course, though Brent is going to change in some unpredictable ways, and Urals, which is a very important regional market, is now not really representing market value at all.

Michael: Okay. So for all that complexity, and there's obviously a suite of benchmarks on a domestic basis in the U.S. On a global basis is it fair to say that it's still really a two-horse race, with the leader Brent being challenged by WTI?

James: Yeah, I think that's probably fair to say. Without stretching the metaphor though, these two horses are becoming one in some ways. I mean, the picture is changing because of what you described at the outset of our chat today with Brent likely to be transformed by the inclusion of WTI. So the future of benchmarking now seems to be not really a choice of grade, should it be Brent or WTI, but a choice of location, will it be WTI delivered into Europe setting Brent, or will it be WTI at the Gulf Coast where it can be exported to anywhere? And certainly, when you look at the liquidity, most of the liquidity seems to be in the pipeline markets at the U.S. Gulf Coast.

Anyway, I don't know if we've answered all of these very complex questions, but that's a quick overview of how things stand in crude benchmarking at the moment. Do feel free to get in touch with Michael or me or anyone else at Argus to get more detail on all of this. And of course, the best place to read about it is the daily Argus Crude Report, our flagship publication for the global crude market. And I'm sure you can find a link to more information about that in the homepage of this podcast on our website. So thanks very much for listening everybody. Thanks very much, Michael, for joining us as well.

Michael: Thank you, James.

James: It's always a pleasure and we'll leave it there. But thanks again, and do please tune in again for another edition of "The Crude Report."

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