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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 discussing what we're hearing so far from oil producer and refiner earnings calls.

I am Jeff Mower, director of America's Oil News, and I'm joined today by senior upstream editor, Starr Spencer, senior refinery editor, Janet Mcgurty and midstream editor, Binish Azhar.

We are in the middle of fourth quarter earnings season and are already hearing some compelling commentary coming from oil executives. We figured why wait until the end of the season to fill in our listeners. Oil producers and service companies are warning about a slowdown in US production growth, while US refiners are reporting a heavy maintenance season in the first quarter, which should help to tighten refined products inventories.

Let's start with the producers and service companies as well. Starr, we've had quite a large increase in US production over the last year, over the last couple of years, came in about, what, a million barrels a day in 2023. What are producers saying so far for production growth in 2024?

Starr Spencer:

Well, let me start with the US Energy Information Administration forecast. According to them, it shouldn't grow much in 2024, maybe as little as 300,000 barrels of oil a day. And as you said, it compares with about a million barrels a day of growth in 2023 and also a million in 2022.

But if you look back a year, 2023 wasn't supposed to be a very growthy year either. At the start of 2023, the EIA was forecasting output to increase by about a half a million barrels a day, specifically about 550,000 barrels a day specifically. And as a matter of fact, at this time last year, the EIA didn't even see the US getting to 13 million barrels a day until the end of 2024. But we hit that milestone in August of 2023. If you want to go back further, 2022 was supposed to grow only about 600,000 barrels a day too. So when you consider that somehow oil production managed to top all the predictions, and the EIA is conservative anyway, I guess the only answer is we'll wait and see.

Jeff Mower:

Were oil companies saying the same thing this time last year, were they being pretty cautious about production growth?

Starr Spencer:

They were, analysts certainly were, yes.

Jeff Mower:

I do think it's interesting, I was reading recent analytics report, S&P Global Commodity Insights analytics report, that showed that nine private companies out of over 11,000, 11,000 companies, it's amazing, accounted for more than all of the oil output growth between 2019 and 2023. And they cited these companies like Mewbourne and Kaiser-Francis and Endeavor. And I just thought that was interesting that these aren't companies that you're going to hear from. And I think maybe that's where the surprise production is coming from. People were expecting, oh, 400,000, 500,000 barrels a day, and then we get this big surge because there are these private companies that they're not reporting on earnings.

I'm curious to see, are there analysts forecasting even higher production growth this year? That same analytics group see something like 15 million barrels a day in US production by 2030. But they have this aggressive case, they said, "Well, we could see a million barrels a day growth over the next 10 years." And that's their aggressive case, even though that would sort of exhaust premium drilling inventories by 2034.

So in the call so far, are we seeing, I'm curious, in the second half of the year, some of these companies, Halliburton, Chevron, Exxon, they're seeing higher DUCs, drilled but uncompleted wells, that they may tap into in the second half of the year. So what was the thinking there?

Starr Spencer:

Yes, right. DUCs are drilled but uncompleted wells, and they're either wells that E&P companies either haven't gotten around to completing or they're deliberately not completing them to save them for a time when they're needed to boost production.

Jeff Miller, who is the CEO of Halliburton, he said that during the company's recent quarterly conference that production is a function of service intensity. That is more stand used in hydraulic fracking as well as more chemicals and other materials and equipment. Miller said, and this is important, that we saw peak levels of service intensity in the first half of 2023. So that actual output came online in the second half of the year. And that is going to happen with some companies this year also. Chevron in particular indicated that they're going to spend the first half drilling DUCs and then they're going to hire another frack crew, a hydraulic fracking crew, to complete those wells in the second half.

And Exxon didn't really give a timeline for when it was going to add DUCs, but it also says it's going to drill DUCs, but in a very careful and calibrated way. Darren Woods, who's the CEO of Exxon, said that the DUCs can offer any constraints that crop up and keep output levels constant. But he also said they need to optimize DUC levels because they just don't want to leave capital in the ground, drilling the wells and then not bothering to complete them.

So these companies, majors especially, have their 2024 plans pretty much set in stone at this point, including their production levels. So both Chevron and Exxon, who have had their calls already, they're both headed toward a million barrels of oil equivalent of production, Chevron in 2025 and ExxonMobil in 2027. So they already have a pretty good idea where the production is going to be. These companies are deliberate, they don't just kind of randomly do things. I think that their production levels are set and they pretty much know what they're going to be doing.

Jeff Mower:

And we're also hearing continued talk of improved efficiencies, we're seeing rigs drop, I mean, you report on rigs every week, and these rig counts keep dropping. But we're producing quite a bit of oil just because of the increased efficiencies. What are companies saying as far as some examples maybe of the efficiencies we're hearing about?

Starr Spencer:

Companies have been getting efficient all along, but they continue to push the envelope. They've been drilling longer laterals, and laterals are the horizontal part of the well, for years, going back 15 years or more. But only recently has the long part of the laterals reached impressive levels.

Exxon, for instance, has been a leader in long laterals. The typical well of say five to 10 years ago, say 10 years ago, was 10,000 feet. And that was an improvement from even earlier levels of 5,000 to 7,000 to 8,000 feet. But Exxon has drilled one of the first three-mile laterals in 2017 in the Bakken shale. And the company continues to push toward the four-mile level, so they're later in long laterals.

Companies have been using simul-frac, that is a technique where they complete two wells at one time. And now Ovintiv, which is the former Encana, said it's experimenting with trimul-frac, which is completing three wells at once. So that's another fairly recent efficiency measure. And all of it gets more oil and gas out of the ground faster.

Jeff Mower:

How about Core Labs, you covered a company, Core Labs, the other day, what was notable about that earnings call?

Starr Spencer:

Yes, Core Labs the other day, and today I covered a company just earlier before the call called ChampionX, and these are both companies that either, well, Core Labs evaluates reservoir rock and also helps companies enhance production. And ChampionX provides drilling and also production enhancing chemicals and services.

And so ChampionX said, they said its exposure to North American operations would be maybe not good because North America isn't really ... it's kind of flattish in activity expected for this year. But at least they will be seeing a little bit more activity. Core Labs also said that even though onshore drilling and completion activity in 2024 is expected to be flat versus 2023, the market penetration for its proprietary reservoir and production diagnostic service technologies should outperform activity.

Jeff Mower:

They have some demand for evaluating the tier two and tier three properties, right? Yeah, why is that relevant?

Starr Spencer:

Up until this point, companies have drilled tier one acreage, which is the creme de la creme of drilling of rocks. Now we're kind of running out of that. And so tier two and tier three are going to be what a lot of production comes from in the future, the near term anyway. So that's what these companies are banking on, these service companies that cater to this kind of activity are banking on so that they'll get a hand in helping them do that.

Jeff Mower:

Now, Binish, you covered a couple of service companies as well. What were they? I think Liberty Energy and RPC, what was notable about those as far as the efficiencies go?

Binish Azhar:

Definitely for these oil services companies, Liberty Energy, for example, which specializes in fracking technology and implementing new digital solutions to kind of increase these efficiencies, that seem to be a big focus between Liberty Energy and RPC. Actually, one of the new technologies that they're employing is natural gas powered fracking fleets, which drove an increase in their operational efficiencies in the last quarter.

In fact, for 2024, CEO Christopher Wright expects that 90% of their fleet will be primarily powered by natural gas. The benefits of this newer technology is that these fleets are becoming more efficient by reducing how long engines spend idling and lowering emissions, as well as just minimizing overall fuel consumption because they're dual fuel powered.

RPC, for example, has a new tier four dynamic gas building fleet. This employs both diesel as well as natural gas powered systems and it's kind of making up a big portion of their portfolio going forward. So we definitely see this focus on efficiencies from these oil service operators, especially as we have record production in North America. So I know this trend will continue.

Jeff Mower:

All right. So before we continue, I want to take a moment to tell you our listener about Platts Connect, the ultimate resource for those interested in the oil and refined products markets we've been discussing. With a subscription you'll have access to daily prices, news, analysis, market updates and more. And if you're specifically interested in our discussion on oil company earnings, be sure to check out the link we've included in the show notes.

So Janet, let's shift to refiners. We've had all this production coming on stream, especially the Permian, which is leading the production growth. What does that mean for refiners, especially in the US? And also what are refiners saying as far as their maintenance programs for this year, for 2024?

Janet Mcgurty:

Well, what we're seeing is, I thought what Binish just said about the fracking, the dual fuel, just makes me think, well, what's that going to do to diesel demand, right? Because diesel is the fuel that is used to run the rig. So that's kind of an interesting trend that I'm going to keep my eye on for sure.

So with refining, we have a very heavy first quarter maintenance season in the US. And Covid really wreaked havoc on refining turnarounds, which are planned year in advance. Currently there's many what we call five-year turnarounds going on. And that means that that's mandated by the government. Every five years you have to do a certain amount of work. And this year it happens to be on coking units. And the coking units are the units that make diesel and heating oil and distillate. And they're also the ones that run the heavy crude.

So we have all this Permian crude, which is light sweet crude coming on, it's kind of a mismatch with US Gulf Coast refiners because they can only run a certain amount to be efficient. Now they'll be running a lot now because they're not looking for heavies because they're taking their cokers offline for work. And we have a lot of big ones down in the US Gulf Coast, cokers, Valero took the legacy coker off at its Port Arthur plant, Marathon, Galveston Bay, Garyville, those are three good-sized refineries. There's also some in the Midwest too that are going down. We have Chevron Pascagoula, they're taking their coker down in March. That's a five-year turnaround for them.

So refiners think that what's going to happen that we're going to see the differential between the light sweet crude like the Permians, and the heavier crudes, which would be like Maya crude, some of the South American crudes, it's widening. So in December, let's say Maya had a $6 discount to light Louisiana sweet, which is a US Gulf Coast, Gulf of Mexico, offshore crude. It's kind of like a benchmark here. But now it's $10 because no one wants Maya.

So if you put that among the backdrop of what's going on geopolitically, refiners in the US, one of them said during their earnings, and I think it might've been Valero, they're not really concerned about not being able to get crude from the Middle East because they haven't been running it for a while, which is true. So they run Maya and the South American crudes and Western Canadian Select.

Jeff Mower:

Oh yeah. And we have seen Canadian production growing and expected to grow this year, right?

Janet Mcgurty:

Yeah, yeah. And so that's important. Well, first of all, the Midwest in the US is, they run so much. So when we saw BP Whiting go down the other day when they had a power outage and the whole plant shut down, everyone looks at the WCS price to see because they run more of it than anyone. We're seeing a lot of it. And we expect to see more to California when TMX comes online.

Jeff Mower:

That's the Trans Mountain expansion in Canada. Yeah.

Janet Mcgurty:

Expansion. Right. But there's problems there. We've already seen stuff coming down. And that's mostly for California. But because of the way of the geology, you can't get VLCCs in there, which are the huge crude tankers which travel across the world.

Jeff Mower:

Yeah, have the refiners talked about Venezuela crude much? I mean, we've had sanctions lifted and a bit more Venezuelan crude has been exported, although there are some problems getting it out recently.

Janet Mcgurty:

Yeah, yeah. Venezuela has been, so Venezuela has kind of been the reason why, not that they're not concerned about OPEC and their production cuts and their production plant, but the Venezuelan barrels coming in, there's a good amount. Valero runs a lot of it at Port Arthur. Chevron who has part, still produces in Venezuela, always has, at their Petropiar joint venture down there. They've shifted from going to China and now they're in the Gulf Coast, which again addresses the higher tanker rate issue, which has been also a result of the Red Sea issues. No one really thinks anything's going to happen there just because it's crude oil that's heavy and it is an election year and, well, yes, the president does not set the price of gasoline, he does have impact on the supply.

Jeff Mower:

Now I see what you mean. Yeah, it's an election year in a bunch of places, yeah, so Biden definitely wants to keep gasoline prices low. So I guess the thinking there is, well, let's keep those sanctions lifted on that Venezuelan oil sector. Even though they're having an election, a lot of that ... At what point does the Biden administration slap sanctions back on because the Maduro regime is gaming the system there to limit the competition?

Janet Mcgurty:

Well, here's the other thing I just like to say. So with the Permian, so the Gulf Coast cannot run a lot of it, so we export a huge amount. So we exported, I looked over the last four weeks, over four million barrels per day, that's compared to 500,000 barrels more than we exported this time last year.

But the problem is that other refiners in the US, which could easily run the light sweet crude cannot do that. And I'm talking about the US Atlantic Coast refiners. And the reason they can't is because it has to come by Jones Act tanker. There is no pipelines. So the only way they can get it is waterborne. And a Jones Act tanker is more expensive. But also there is a severe limit on how many there are.

Now we saw recently that Monroe Energy, which is Delta's refinery in Trainer, Pennsylvania, they chartered a ship for six months, a Jones Act tanker, to bring light sweet crude to Trainer, Pennsylvania refinery. And the ship that they got was moved from carrying ANS, Alaska North Slope, to California and the Northwest, Pacific Northwest refineries, to bringing it to the US East Coast. Now with TMX coming online, when it does, that might open up more of these tankers, there's four or five of them that do that, that do that run.

Jeff Mower:

The availability of those tankers?

Janet Mcgurty:

Yes.

Jeff Mower:

Oh, interesting. Yeah.

Janet Mcgurty:

I mean, that's what I've been thinking of. Because now, I asked people who are in the know and run Jones Act tanker, they're kind of like, "Monroe's a one-off." So the US Gulf Coast can't run as much Permian crude as even is produced today, so it has to be exported. So that's I think going to be the interesting thing to watch.

Jeff Mower:

Yeah. And I was seeing that, there were US exports of TI into Europe dropped a bit recently. It had an impact on North Sea differentials, propped up differentials a bit over there. But I think that had more to do, and I did see a slight drop month on month in US crude exports, but I think it had more to do with production issues from cold weather. That's what I've heard at least.

But I'm wondering, are we hearing anything on capacity constraints? And this is a question for Binish. Every once in a while we'll hear, and this happens all the time, production rises and the pipeline capacity is falling short, so you're unable to get enough barrels out and it causes a glide in prices to fall in that region. So Binish, are you hearing anything on that front as far as pipeline capacity out of the Permian?

Binish Azhar:

So just according to their third quarter earnings report of Corpus Christi's, they saw a 4.4% increase in their crude oil shipments out of that port as of Q3 at 242 barrels compared to Q2 2023. And if I compare that with Houston loadings, we can see that in January, according to our commodities at sea platform data, crude loadings in January for Houston were around 364,000 barrels per day, while Corpus Christi has been pretty consistent around 500,000 barrels per day. That's coming off of two million seen consistently in December of last year, 2.5 seen in November of last year. So Corpus Christi is definitely running close to capacity. So we may see some of those constraints down the line this year at least.

Jeff Mower:

All right. Sure thing. Well, thanks so much Binish, Janet and Starr for joining me in this conversation. And of course thank you for listening. This Oil Markets episode was produced by Felix Fernandez in London.