Listen: LatAm shuffles the heavy sour oil deck in the Americas

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Jeff Mower:

Hello and welcome to the Platts Oil Markets podcast by S&P Global Commodity Insights, where today, we'll be talking about a decline in Latin American heavy sour crude supply and expected reshuffling of heavy sour barrels following this year's Canadian Trans Mountain crude pipeline expansion and next year's Olmeca refinery start-up in Mexico.

I'm Jeff Mower, director of Americas oil news, and I'm joined today by S&P Global Commodity Insights analysts Stephanie Rivera and Nick Blanco and associate editorial director for Americas crude price assessments, Beth Brown. Welcome, everyone.

So Latin American crude production is on the rise, with countries like Brazil, Guyana, and Argentina leading the way. However, Latin American heavy sour crude output is expected to decline, with Commodity Insights showing a drop of roughly 240,000 barrels a day between January 2024 and December 2025 to around 2.9 million barrels a day.

This tightening will impact refiners geared up to run heavier sour barrels, such as in the US Midwest and the Gulf Coast, especially once Canada's Trans Mountain crude pipeline expansion comes online and Mexico's Olmeca refinery starts up.

So, Nick, let's start with you. Could you give us just an overview here? What's going on with Latin American crude? Why are we seeing this drop in heavy sour supply?

Nick Blanco:

Yeah, absolutely. So if we look back five to 10 years at Latin American crude production, we see a very different picture. Back then, Latin America was known as a producer of mostly sour grades, and we had both Venezuela and Mexico each producing well over 2 million barrels a day. And even Colombia was sometimes producing over a million barrels a day.

Because of how close Latin America is to the US Gulf Coast, as you mentioned, many of the Gulf Coast refineries were actually configured to consume these Latin sours, and it was common to see over 2 million barrels a day of Latin sours alone being exported to PADD 3 on a monthly basis. But since then, production for the Latin region has characteristically changed, and now the region is more associated with medium-light sweet than it is with sour grades.

So what's going on here? Well, we can talk about sour grades in a moment, but I think it's useful to get some context about sweet crude production. In Brazil, we had the engineering breakthrough of pre-salt drilling, which has led to a production increase of well over a million barrels a day within a decade, right? And that's even with significant mature field declines.

In Guyana, a country that has essentially no history of producing crude five years ago, and it's producing over 600,000 barrels a day today. Lastly, on the sweet crude side, we have begun to see the fruits of Argentina's unconventional Vaca Muerta in recent years, which could sharply increase soon, but there is a lot of political investment issues in the country.

Jeff Mower:

Now, how about Mexico and Venezuela? I mean, Venezuela, we've had sanctions lifted recently, although temporarily, and there were some expectation that we might see some increased supply out of that country, but Mexico is a little tough. Pemex, especially, has been struggling to keep output steady there.

Nick Blanco:

That's right. Yeah, on the Venezuela side, I'm sure much of the audience has heard this, essentially, Venezuela's energy industry began to decay after years of mismanagement and underinvestment, and at the same time, the country essentially collapsed economically and in an infrastructure sense.

So PDVSA basically endured a brain drain, if you will, and it had no expertise when it needed the most. Those factors alone were enough to cause production to drop about a million barrels a day within two years, and that was leading up to 2019. But then PDVSA was sanctioned by the US, which then blocked it from exporting crude and also from foreign investment into the country, excluding Chevron. But that really brought down production, I think, as low as almost 200,000 barrels a day, which was a historic low.

Since that time, production has somewhat recovered, and as you mentioned, the recovery of some allowances from the US Treasury has allowed some production and maybe some investments, but we are maintaining a very reserved outlook. With the Biden administration, we're not really sure what's going to happen politically. I'm not a geopolitical expert, but on one side, Biden wants to keep energy prices low, but on the other side, Maduro is essentially flaunting the agreement that brought the reduced sanctions in place.

Jeff Mower:

Yeah, from a few stories written, it looks like sanctions will likely be reimposed in April, considering Maduro's recent actions. He's preventing its key competitor politically from running this year in the presidential elections and kicked out some human rights organization, I believe, last week. How about on the Mexico front? They're having an election this year as well.

Nick Blanco:

Yeah, exactly. But I really see Mexico as having two main issues. On one hand, you had the decline of Cantarell and KMZ, Cantarell complex, historic complex that used to produce over 2 million barrels a day at its peak, and now it's down around 150,000 barrels a day. And then KMZ, which is maybe a little bit more important today, has been declining for around three to four years.

Now, on the other hand, you have issues with investment in the country. The current president, President Andres Obrador, has effectively blocked further foreign investment into upstream projects, even as foreign-operated production finally started to grow, even reaching, I think, almost 200,000 barrels a day.

But more importantly, Pemex has decided to focus its investing into what it calls priority projects, which are really shallow-water and onshore projects. Now, these projects did lead to a temporary increase in production, but there was always significant uncertainty in the success of some of these projects. And we are now seeing that the volumes from those projects are unable to overcome declines from the KMZ.

It's also important to note that these fields tend to produce Olmeca and Isthmus, so Mexico's crude production has actually started to shift to lighter grades, kind of mirroring the larger trend in Latin America, interestingly.

Jeff Mower:

Now, what about elsewhere in Latin America, Stephanie? How about, say, Ecuador and Colombia?

Stephanie Rivera:

So, as you mentioned, Jeff, at the beginning of the podcast, we forecast heavy sour crude from Latin America to decline. And I would say that both Ecuador and Colombia are prime examples of this decline.

Both these Andean countries have a similar experience in that they haven't been able to get their production levels back to pre-Covid levels. And so we foresee that their trajectory is going to be on a gradual downward trend.

And most of these factors that are leading to this decline can be similar for both countries. So, for both countries, they have not been able to offset the decline in mature fields, adding new projects. Also, infrastructural issues. So, for example, Ecuador, their SOTE or OCP pipeline have had multiple pipeline ruptures due to landslides. And then, for Colombia, they have had third-party pipeline attacks on their Cano Limon-Covenas pipeline, along with the addition of illicit valves that have interrupted their crude flow. Furthermore, they've had social unrest. Both countries have dealt with social unrest, whether it be blockades or protests, that have led to a reduction of foreign investment in their energy sector.

So if we look at Ecuador specifically, Ecuador produces two heavy sour crudes, and their heavier sour is Napo and then their Oriente. And so, prior to Covid, production was near 550,000 barrels per day. But since then, production has not been able to reach 500,000 barrels per day on a yearly basis. So looking more specifically to their December 2023 production difference from December 2022, we see that production has decreased by 1.2%.

And so this has led both former and current presidents to really take a step back and evaluate their projections and their targets. So, in 2023, former president Guillermo Lasso, he was forced to reduce his yearly production target by 8% to 480,000 barrels per day due to the factors that I had mentioned, whether it be political issues, social unrest, infrastructural issues.

And now, we see in Ecuador uncertainty continuing to loom over their crude production. And that was caused by the August 2023 referendum in which over 50% of Ecuadorian voters voted in favor of stopping crude production at its Block 43 complex, which is made up of the ITT or Ishpingo, Tambococha, and Tiputini fields. And so this has caused Petroecuador to take the steps to stop production in 250 wells, which accounts for 12% of crude production in Ecuador or approximately 57,000 barrels per day.

And so I guess a question mark that exists with this referendum vote is that Ecuador is currently undergoing violence due to narco-terrorism and gang violence. So the current president, Daniel Noboa, is looking to delay this shutdown or this decommission for a year in order to finance the war against narco-terrorism.

Jeff Mower:

Yeah, that's a really interesting angle. And also, I mean, there has been some activity there, I guess. I mean, Ecuador's energy minister announced that contracts will be signed the first half of this year for the Intracampos II bid round. But yeah, that's all a little down the road, right? That's pretty far upstream.

So, before we go any further, I want to let our listeners know that there is still time to register for two big events happening in mid-March, CERAWeek and the World Petrochemical Conference. They're both taking place in Houston from March 18th to March 22nd. For those who want to hear more about Americas oil, for instance, some great CERAWeek sessions for you would be Global Competitiveness of Latin American Upstream, and North American Oil and Gas: Continuing Growth.

WPC will feature thought leadership and expert insight across the chemical value chain, including carbon, olefins, polymers, and emerging technologies, just to name a few. We'll include the links to register for CERAWeek and WPC in our show notes, so click on that to learn more.

So let's turn now to the expected shift in flows, especially from the two upcoming events, the Trans Mountain crude pipeline expansion and the Olmeca refinery. So, Beth, you're hearing just in recent days that West Coast crude traders are already taking a kind of wait-and-see attitude ahead of the start-up of Trans Mountain. Could you explain why that is? And why is Trans Mountain... Exactly what is it, and why is that so important to traders on the West Coast?

Beth Brown:

Yeah, Trans Mountain pipeline expansion has been many years in the waiting, and it does appear that it will be happening later in Q2 of this year, after some anticipation, some pushback dates. But the Trans Mountain pipeline expansion is the twin pipeline for the Trans Mountain system taking those heavy crude barrels produced in Western Canada, the Alberta region, taking them to the West Coast of Canada to be exported out of the Westridge Terminal in the Vancouver area.

And that pipeline will bring an additional nearly Aframax size, 590,000 barrels per day of crude out to the water. And that's a massive deal because from there, the barrels can either flow down to the US West Coast, they could potentially flow to Asia. And I think that the actual home of where those barrels will end up is the big question mark that everyone in both Western Canada, the US West Coast, and Latin America is all trying to figure out because the US West Coast right now is really diversified grounds for imports from the Atlantic Basin, from South America, and from Asia, so this pipeline coming online has the ability to affect imports from all over the world into the US West Coast.

In recent days, we've even started to see some of how people are trying to figure out what that's going to look like. So we saw just last week a trade in the Platts Market on Close process for Liza crude out of Guyana. That trade happened at Dated Brent minus 1.60, which was a little bit lower than the previous levels. And when we talked to people about why the prices were falling, we're already starting to hear people say it's because of some of this uncertainty around West Coast buying for crude out of Guyana.

The West Coast takes crude from Guyana, from Brazil, from Ecuador, as well as from different places in Asia. And so, yeah, we're already starting to see that even though the Trans Mountain pipeline expansion isn't expected to come online for another few months, people are already still trying to figure out what this is going to mean and if this is going to disrupt the historical buying habits.

Jeff Mower:

So once, I remember, we had spoken before, and you said that Oriente would be the first grade out of the West Coast when Canadian barrels come in, but do you think, mean, I would imagine companies are going to be competitive. They're going to want to keep market share.

So one question I have is, when I hear Canadian producers talk about how when TMX comes online, these sort of deep Canadian crude price discounts are going to go away or they're going to narrow. They're going to narrow because you're going to have this outlet. But it made me wonder, well, what about these other producers? Are they going to lower their prices and force the Canadians to drop their prices to hold onto that market share?

Beth Brown:

Yeah, I think Oriente is definitely the crude grade that gets called out first as being the first that can get priced out of the West Coast market. The West Coast takes around 100,000 barrels per day of Oriente coming up from Ecuador. But yeah, this is definitely going to be a ground that people are going to want to be competitive. They're going to want to keep their market share for it.

That being said, you can already start to see that the price of heavy Canadian crude in Alberta is starting to price in what they expect will be an increase in prices starting around the time of the Trans Mountain pipeline expansion. So, right now, Western Canadian Select is trading at a discount of maybe around minus $18, and by the end of Q2, beginning of Q3, those discounts are as narrow as minus $12, minus $13, so nearly a $5 per barrel increase that people are already pricing in to what they expect that to be.

And that's probably being driven, as much as anything, by the fact that for the first time, Canadian market is facing a situation where they have more egress than there is production. They've been in this pipe-constrained world for so long that bringing on an additional 600,000 barrels a day of capacity to move their barrels is going to be a massive boon to them. And from there, they can decide, do you want to ship barrels west to be potentially exported to the West Coast or to Asia? Do you want to continue to send your barrels to PADD 2 refiners? Do you want to continue to send it down to the Gulf Coast?

Those are going to be big question marks, and I think ones that people are still working out. There's still genuine questions around whether it's actually more economical for someone to ship all the way down to the Gulf Coast and be able to load it onto a VLCC quite easily and then ship it to Asia. Does that actually make more sense than exporting it via the Trans Mountain pipeline, loading it onto an Aframax, and exporting to Asia from there? Because right now, the largest size cargo that you can load out of Westridge is an Aframax.

So logistics is going to be a really big part of how the flows of these Canadian pipelines are going to work. But regardless, you can just see that the prices are going to get stronger in Western Canada along the curve already just because of the ability to make those decisions and have the egress in the market.

Jeff Mower:

Yeah, sure. And now, what about the Pemex's Olmeca refinery? I don't know who wants to jump in here. What's the latest expectation on when that refinery is supposed to start up, and what do you think the impact will be there, especially on the heavy sour supplies?

Nick Blanco:

Yeah, regarding the Olmeca refinery, the current expectation is the start-up is around 2025. This is always a date that's been delaying. It's been delayed about three years at this point.

The refinery is expected to have a nameplate capacity of around 300,000 barrels a day, and importantly, it's going to consume 100% Maya crude. So the problem is, currently, Pemex exports around 500 to 700,000 barrels a day of Maya globally, depending on the month, most of which ends up at the US Gulf Coast. This will be a huge dent into Maya availability at the US Gulf Coast, right?

And actually, not many people are talking about this. There's the addition of the coker at the Tula refinery, an already existing refinery, and that's going to flip the diet of the Tula refinery from about 30% Maya to 70% and also increasing capacity. So, suddenly, the US Gulf Coast will lose more sour barrels on top of what it could possibly lose, given the different possibilities with TMX and on top of the OPEC+ cuts. So we're just really seeing limited volumes of sour. The only upside I can maybe see on sour supply from Latin America is Venezuela, and that's tenuous at best as other sours really decline in the region.

Jeff Mower:

Well, thanks very much, Beth, Stephanie, and Nick for joining me in this conversation. And, of course, thank you for listening. This Oil Markets episode was produced by Jennifer Pedrick in Houston.