The transparency of locational spreads between the various US Gulf coast terminals that make up Argus AGS has proven quite popular, as it helps to highlight each connection’s unique market fundamentals.
In this episode of The Crude Report, Argus Associate Editor Amanda Hilow and Argus Americas Crude Editor Gus Vasquez explain Argus AGS’ newest methodology changes and what factors have contributed to the downward trend between locational spreads.
Transcript
Amanda Hilow: Hello, and welcome to The Crude Report, Argus' podcast on global crude oil markets. I'm Amanda Hilow, and I'm joined by Gus Vasquez, who's the editor of the Argus Americas Crude report. The main topic today will be [Argus] AGS, which is our Midland-quality WTI index at the Gulf coast, and we'll discuss some recent and upcoming changes to the methodology and what those changes mean for the future of AGS as a benchmark. So welcome, Gus. Do you want to take us away?
Gus Vasquez: Sure. Thanks, Amanda. So, first of all, let's just talk a little bit about what AGS is. The first thing I think we need to say is that it stands for American GulfCoast Select. Not everybody necessarily knows that off the top of their heads, but that's what it stands for. And this is essentially a daily volume-weighted average that captures trades or transactions for Midland-quality WTI across different locations along the Gulf coast. So currently, we have 11 locations that we use to come up with the AGS price every day – some are waterborne, some are pipeline. Because it's all WTI, the quality is going to be the same, so that's not an issue. But, of course, when you have different locations, you are going to have different dynamics and certain locational spreads, as they're called in the industry, that are going to vary from time to time. So how do you combine all of that into a single price? And the answer to that question is – you have to normalize. And in the case of AGS, what we do is we normalize to one single location which is the Enterprise ECHO Terminal in Houston.
Amanda: So, Gus, why do we normalize to ECHO and not any of the other locations?
Gus: That is a good question and one that we've actually been asked quite a bit in our meetings. The reason we chose Echo was because, first of all, there's quite a lot of transaction there. There's more volume that's expected to be coming into ECHO terminal. We're talking about WTI quality crude, right? So more barrels of that coming into that location. And at the time that we launched AGS last year, this was the lowest value location out of all the different locations that we were looking at. That is important because what it means is that it's the one location that you can set every other locational spread and it's going to be the same. So they're all going to be positive or they're all going to be a premium. So every other terminal was ECHO plus some kind of spread. That just simplifies the process rather than having, say, if you had MEH as your normalizing factor, then you would have to have some locations that were above MEH but some locations were valued below MEH, and then so some of your spreads would be positive, some would be negative, and it starts to get really confusing really quickly. So having a terminal that was the lowest value, that, by far, is the easiest way to calculate some of these spreads. And then as I said, there's volume that trades there, and more volume was being expected to come into that terminal, so it just made a lot of sense.
Amanda: And you mentioned that we now have 11 pricing locations that we include. That's definitely an increase compared to when we first launched. Could you go over what we've added?
Gus: Sure. When we initially launched this price, we realized from the beginning that it was going to be pretty complex already. We're talking waterborne and pipeline, multiple locations, all combined and normalized to a single price. It was all very different from what we traditionally do.
Traditionally, our prices are for a single grade at a single location price against WTI Cushing and everything is very straightforward. This was very complex, so we knew that we wanted more locations, but we didn't want to launch with all the locations already in there because it was just going to be too much to introduce all at once. So we kept it somewhat smaller and then we have been expanding ever since. So the latest expansion that we had was to include deals done for WTI at Moore Road and Valero Junction, and those became part of AGS starting on the 26th of March. And since we did that, we had the first transaction done at Valero Junction, and that deal was for 20,000 b/d, so quite a sizable deal. You can see how adding these locations starts to help boost the liquidity that goes into the assessment.
We are also looking ahead to making more changes. So one upcoming methodology change that we have is to look at the frequency with which we publish the locational adjustment factors. And we had been updating those every three months based on the previous three months of data. So we would take the data from three months, average it all out, and that would say, "Okay, the spread between MEH and ECHO is now this." We would publish that and we would leave it alone for three months. What we found is that those locational spreads are actually very useful to people in the industry, and so they wanted them more often, and we can, of course, provide that. So what we're going to do is we're going to update those on a monthly basis now but still using the previous three months of data. So you essentially have a three-month rolling average of the spreads being updated by Argus every month now.
Amanda: That means that the new spreads are expected to take effect on the 26th of April rather than the 26th of May as they would have under the previous schedule. And what we're seeing so far is that the downward trend that began last year in locational spreads for WTI at the Gulf Coast is continuing through 2021 so far. When we first launched AGS on the 26th of June in 2020, we had our locational spreads set to reflect logistical costs and the difference of logistical costs at each location. For example, MEH was set at a $0.25/bl premium to ECHO, and we had the Enterprise Houston Ship Channel, we had Texas City and Seabrook, all of those waterborne locations set at premiums of $0.45/bl in order to reflect typical loading costs.
Now, keep in mind, those can vary depending on terminal and counterparty, but more or less, they reflected what it costs in order to transport and load crude at each of those locations. But that doesn't always happen, you know. That's not always the case. What we're seeing is that these spreads are narrowing over time in order to reflect fundamentals instead rather than just loading costs. So, for example, if you look at the FOB versus the pipeline market for WTI FOB Houston, which would include the Enterprise Houston Ship Channel, Texas City, and Seabrook, we're seeing those locations fall to right around parity to the ECHO Terminal rather than the $0.45/bl premium for logistical costs, right? So it fell from $0.45/bl, in October it fell to $0.25/bl, then it fell down to $0.20/bl. Now it's at $0.08 and we're expecting it to be around $0.01/bl premium or around parity with this next adjustment review.
Gus: Okay. But wouldn't you expect that to be a larger premium given that, you know, there's a cost to get those barrels out there?
Amanda: Yes and no. That's a common misconception in FOB markets. Typically, what we hear is that, okay, well, you'll want to get your pipeline costs at MEH and then add loading costs and that'll be your FOB price. That's not right. The FOB market is intended to reflect the meeting point of both domestic fundamentals and international markets. And in international markets, there is this major disruption to global oil demand. A lot of that is in the form of lockdowns meant to stanch the spread of the Covid-19 pandemic. So fuel demand is...honestly, it's in the toilet, Gus. We're also seeing a resumption of Libyan crude exports after months-long force majeure. We're also seeing sanctions ease on Iranian crude oil exports. So a lot of these WTI exports are being displaced. There's a bottleneck building at the Gulf coast. So, in order for sellers to actually place these cargoes in the international market, they're going to have to eat those loading costs on their own and they're going to have to trade it at parity to what it's selling to in the US market.
Gus: So, essentially, what you're saying is that the domestic market is more profitable than the export market, or in other words, the arb to export is not that good, so you're better off selling domestically.
Amanda: Exactly. But we're also seeing lower demand in the pipeline market too. In the past, we would see a lot of speculative trade occurring at MEH. Market participants would buy volume at the Magellan East Houston Terminal and then ship it to other locations in the Gulf coast physical pipeline market and profit off of the spread between those locations. But now we're seeing MEH and ECHO, our two primary locations in AGS, both turning towards parity.
We're seeing MEH at an average $0.06/bl premium to ECHO deliveries compared to our most recent spread of $0.09/bl. This is continuing, a trend that we've seen for several months now, of the two moving towards parity, and there's a lot of different reasons for this. There's the higher connectivity out of the ECHO terminal with the recent commencement of services on Midland ECHO III. We're also seeing MEH beginning to accept third-party pipeline deliveries rather than just from Longhorn and Bridgetex, and we're seeing Enterprise and Magellan, previously each other's main competitors, now beginning to collaborate on a wider scale. They both recently announced plans to launch a joint futures contract that would accept WTI deliveries at each of their terminals rather than just ECHO or just Magellan.
So, a point I really want to drive in, though, is that, like I mentioned, the speculative trade is falling. Instead with all of these connectivity options, we're seeing domestic demand trend towards purely refinery supply. So rather than buying at ECHO or rather than buying at MEH and then shipping to the refineries, they'll buy it as close to the refineries as they can as we see at Valero Junction, for example. And we expect this trend to continue near term due to a poor Midland to Houston arbitrage on your key pipelines.
So while the arbitrage between Midland and Houston is low, we'll see that demand remains prominent for refinery supply rather than speculative trading. For example, if you were to buy crude in Midland and then ship it to Magellan East Houston, your costs at the end of that route is going to be around $1.86/bl. However, we're seeing the difference between WTI trading in Midland and WTI trading in Houston around $0.56/bl, so that's less than a third of your pipeline tariff. So, as a result, we're seeing the Magellan East Houston terminal become less of a trade hub and more of a location for storage, you know. So right now, since there's not as much speculative trade occurring. The May trade month volumes so far this month has only been 217,000 b/d at Magellan East Houston. That's a 33% drop compared to the same time frame of the April trade month. We're seeing similar drops at ECHO with volume falling 68% on the month to just 8,000 b/d so far this trade month.
Gus: Right. But then as we see those volumes fall, we do see volumes kind of increase at other locations, right? And this is why AGS is so interesting because now another potential expansion that we're looking into is to include the pipeline deals that are done at Corpus Christi and at Nederland. Both locations we already have FOB transactions that can go into AGS. These would be pipeline deals at those locations that will then also go into AGS. And if we were to do that, and that's something that's currently in discussion with the industry, but if we were to do that, or if we had done that already, we would have seen that for what we have so far for the May trade month. At Nederland, it would have added a volume greater than 50,000 b/d.
Amanda: That's a fantastic point, and that keeps rising too. AGS has to capture how markets trade and how markets develop, and what we're seeing at Nederland is that WTI volumes are increasing. I have it written down right here. In the March trade month, we saw WTI at Nederland total 25,000 b/d. In April, it totaled 40,000 b/d. Now it's up to 50,000 b/d. I think that is potentially being driven by the fact that there are fewer Bakken deliveries now at Nederland via the Dakota Access Pipeline. And that's largely because a huge portion of the market is waiting to see how the ongoing court case for DAPL develops and they're withholding some Bakken deliveries on that pipeline, and ultimately, that leaves more room at Nederland to bring in light sweets from Texas instead.
Gus: Right. And then capturing that volume, if we were to expand the AGS methodology to include those locations, would obviously increase the liquidity that we have in AGS, and that would make it a more reflective price of what's happening in the market, which is, like you said, you have this change in where the crude is coming from because of some pipeline issues, and so you know, liquidity that we were capturing somewhere else has now potentially moved to Nederland, for example, and then now we need to consider capturing that location and those volumes this time around.
I'm sure we could keep talking about AGS for hours and hours, but all good things must come to an end, so I think we'll leave our discussion there. If you do have any questions about AGS or you have any feedback on the potential methodology changes that we touched on, please do let us know at houstoncrude@argusmedia.com, and if you're in need of more in-depth daily coverage of US crude oil markets, do consider subscribing to Argus Americas Crude, which is our main report. It covers all the pricing for the Americas. You can find more information on that service at www.argusmedia.com.
I would like to end by saying thank you so much for tuning in today, and we look forward to you joining us on the next episode of The Crude Report.
