APA Q1 2024 Earnings Call Transcript

Good morning, John.

No, it's a great question. And as you acknowledge, historically, we have run a higher ratio of workover rigs or drilling rigs. Today, we're going to average 13 to 15 on the drilling rig side this year, and we're going to run right at 20 workover rigs. So it's going to take a little bit more time to kind of chisel away at that, but we're on it. It's coming down a little bit. There's also things we're doing with the drilling rigs to be able to complete some wells, which will also help some of that pressure. So it's just going to take a little bit longer, which is why you'll see a gradual move down on that number.

Yes. Today, the guidance is what's in front of us, right? And it's going to -- obviously, Callon's drilled a lot of wells. We're immediately making changes on the completion side to the extent we can. But there are more wells drilled per section that we would drill. There are more landing zones. And so we're going to have to pump similar-sized fracs in terms of sand loads, I think the big thing will be changing is the fluid volumes will go up, but we're doing things with -- it's kind of a work in progress, right? We start with what Callon has and we modify what we can and what we think is going to be impactful. And then by the time you get to the fourth quarter, you'll start to see how we plan things and what will be full Apache workflow on that.

Just a little color in terms of where the rig count sits and things today. We're running 11 rigs, there's four in the Delaware, there's actually seven in the Midland. We've actually moved one of the Callon rigs to some Apache acreage that was ready and kind of plan like we want to drill it. So we've accelerated some there. So it's going to be in flux as we work through this. But yes, we're anxious to get to fully Apache planned workflow and execution. And it's going to be a kind of a transition over the next two quarters until we get their fourth quarter.

You bet. Thank you.

Well, I mean, that is the big driver. It needs to compete internally on the oil side. And really, we measure that through Waha. So right now, you've had very, very weak Waha. Obviously, we've got Matterhorn coming on, but we're going to need to see much stronger Waha and it's going to need to compete internally with our oil projects.

No. I mean I think big picture, we're committed to the 60%, right? We've shown that it's a minimum of 60%. And we will lean into that when we believe there's weakness, which we've historically done, and we'll continue to do in the future. That gives us the other 40% for debt reduction. We do have some non-core asset sales that we're targeting as we do believe we need to make some progress on the debt side with what we brought on with Callon, but you'll see us aggressively approaching both.

You bet. Thank you.

Yeah. David, this is Steve. So in terms of the capital program and the treatment of DUCs, what we've done is we've added some frac capital in order to come up to the $2.7 billion of capital that we have in the plan for this year now. We basically just combined the final three quarters of Callon's remaining capital program with ours. But then we added some frac capital in the second half of the year, because we did see that both of us were building DUCs.

Now I think it's probably best that we not get into numbers at this point simply because the program is still, I'd say, very much in flux as you go out towards the back half of the year. We're working our way through it. As John said, we are we are changing a lot of the activity. There's hardly any activity that's going on the Callon acreage later this year that we're not changing from the Callon plan. And so you can imagine after four weeks that, that's still a bit in flux.

And so maybe we can share some -- a bit more clarity on things like that with the second quarter earnings call in August. I think that would be better just so we can be through a bit of this, and we can solidify the remaining plan for the year. But just as a general statement, we don't believe that it's good capital efficiency in general to be carrying a lot of DUCs. There are some value to having some DUCs and there's some just basic need because of the logistics of matching up frac schedules with drilling schedules, but we don't believe in the capital efficiency of having a tremendous amount of DUC inventory.

And the only thing I would add is, obviously, we believe the capital productivity will improve on the Callon portion, especially as we go to our modifications and our workflows back half of the year. So combined companies going to improve and we're seeing that productivity on the Apache side right now, and we'll get the Callon assets there towards the back half of the year.

No, we don't have any specific targets in mind. But what we recognize that even after the progress that we made in 2021 and 2022 on debt, for Apache Corp. we knew that we needed to make more progress. And we didn't make as much as we might have wanted to during the intervening time, and we just feel like we need to get on with that and get debt down.

And now that we've added some debt through the Callon acquisition, we're going to just try to focus on that this year. We think it's a good time to be doing that. The market seems to be strong for some of these noncore assets and we'll see if we can get some of those off and get some good prices, and they will be focused on debt reduction. We're optimistic about that. We think that it's a good time to be doing it.

Ultimately, the -- sorry, ultimately, the target is to get debt to a point where we are kind of a solid BBB type of rating on our debt, so that you're not kind of dancing around the edge of investment grade and non-investment grade. And we slid into non-investment grade in 2020 with the massive downturn in oil price and we haven't been able to climb back out of that, even though we're -- we have the metrics of a lot of investment-grade companies. We're still not investment grade with everybody. We've gotten there with two, but not all three.

That's what we're trying to achieve. Yes. I think it's possible, and we're going to certainly give it a try.

Thank you.

Yeah. Betty, what I'll say is, as post the Callon merger, our Permian now makes up roughly 75% of the company. And we've been executing at a high rate on the Apache side. We're anxious to provide those workflows on the Callon side. We have added a little bit of capital, which is going to work down some of the DUCs in the fourth quarter of this year. So I mean, it's early to comment on 2025, but it's going to give us a lot of strong momentum as we exit 2024 with a very strong fourth quarter. So we're very anxious to demonstrate that, and we're very confident in what we can deliver from the Permian.

Sorry, Betty. I was just going to add one thing to that. The one of the reasons why we added the frac capacity in the second half of this year, number one is frac is pretty inexpensive these days. So it's a good time to be doing that. But also just -- with the scale of the operation now that we have in the Permian Basin, as John said, 75% of our company now, with that kind of scale and the amount of activity that we're carrying on we ought to be able to plan activity to where we don't have these big lulls a big rush of completions and turn-in lines and then a big wall of activity, and we ought to be able to plan it maintaining capital efficiency, but plan it in a way that creates a bit smoother profile to production volume.

And that's one of the things that we're trying to achieve as we bring this frac capacity into the back half of this year is to get a little more smoothness to that because we were -- we felt like we may have been setting ourselves up for yet another downturn in first quarter on volume, a little bit of a lull or a flat spot, and we don't need to be doing that, and we can do better than that.

Yes. I mean you've got one factor in Egypt is costs are big picture gas has been declining. So the gross BOEs have been declining because of that, and we've been growing the oil we're in a place today where we're working to rebalance the workover rigs and the drilling rigs and find a good level in there where we can drive that production base. So we'll monitor that over the year and come back later this year with projections in terms of what we'll do next year. And quite frankly, how Egypt continues to compete with what we're doing in the Permian, will play into that as well.

Okay. Yes. So sorry, this is Steve. Yes, on receivables. So as we've always said, we worked very closely with the Egyptian government on things like that. We've received two payments during the first quarter of this year. But despite that receivables, especially with oil price and all receivables increased slightly in the first quarter of 2024 we kind of made good progress through 2023, bringing it down most quarters. It increased slightly in the first quarter of 2024, but it's still below the average of where we were last year. But more importantly, I think you hit on the point, I think Egypt is on a very good path right now. They've floated their currency. They devalued it and floated it. And with that, they had to raise interest rates to control inflation.

But with that, their bonds are up and the ratings outlook is improving. The IMF loan, as you talked about, they increased their loan program from $3 billion to $8 billion. They've gotten a significant amount of investment coming in from other Gulf states mostly around some real estate opportunities. And they've got pledges now from both the World Bank and from the EU to offer support as well. So I think all of the signs for Egypt are pointing up now. That doesn't mean that it's going to be an easy ride. It's not going to be a quick ride, but things are certainly improving.

Liquidity is improving. It's just a big positive step in the right direction, and that's going to help as we go forward. And we have had indications from the Egyptian government that we will get a large payment in the second quarter of this year. So we're will be -- and will actually be in Egypt visiting with them around that same time. So that's where we are on the receivables. It hasn't changed a whole lot in the first quarter, but certainly all of the signs of things going on in Egypt are pointing up and improving.

In terms of gross volume, we haven't declined for two quarters in a row. We've actually -- and if you look back to 2023, gross oil volume was pretty flat for a while and then rose we're declining now from fourth quarter to first quarter. A lot of that is around completion timing. We actually completed 27 new wells in the third quarter last year, 26 in the fourth quarter. And then we completed 17 in the first quarter of this year. So that's not necessarily a surprise that volume -- oil volume might be declining a bit in this quarter.

We'll see where we go going forward. We are continuing to reduce the drilling rig count. So that is going to have an effect on the number of wells that will be available for completion. But we'll see as we go quarter-to-quarter through the year on gross oil volume. And then as we approach year end -- and as John said in the prior question, we've got to work through this issue of the balancing of workover rigs and workover capacity with our drilling capacity because it's not a very efficient use of capital to be drilling new wells when in workover is so much more capital productive than drilling new wells.

Nothing wrong with drilling new wells, but workover is cheap and normally returns quite a bit of production volume to -- on the line. So you got to make sure you have the capacity to stay on top of the workover program. And we've got a lot of ideas on how we can work through that. Ultimately, there is longer term, the possibility you could bring more workover rigs into the country, but there are a lot of other things that we can try to work through before we get to that. So we've got a lot to do in 2024 to get things balanced properly and functioning properly between drilling new wells and working over and working our way through that backlog. And then as we roll into 2025, we'll give a better view to where Egypt is going.

Yeah, I'd just say we're very confident speeds still underway, and we would anticipate an FID by year-end. So it's all moving forward there. And then that's going to dictate timing in terms of drilling we've got till 2026 to start the exploration program. So there's nothing pressing on the 2025 side, but we could be back to drilling in 2025.

You bet. Thank you, Leo.

Yeah, I'll jump in, and I'll let Steve add a little bit more color. But in general, we're changing the program. So you're going to see fewer wells per section, fewer landing zones larger fracs in general. The other thing is when you look at the well count in terms of how they complete their wells, Callon was putting a third of their new wells on ESPs and 30% on gas lift. We've been running outside of Alpine High, about 3% ESP and 60% gas lift. So that's the other place in terms of just how we're equipping the wells, how we're flowing the wells and producing the wells and then obviously, the power then that is needed to drive those sub pumps is another big factor.

I'll also say that they turnkey a lot of their stuff. I mean they turnkeyed a lot of their frac operations and we're going to self source and do a lot of stuff there. So there's a lot of low-hanging fruit on the operations side. So those are some of the big ticket items. And we've already seen a lot of that, which is why you've seen us increase a lot on the operational side.

Yeah. And Neil, I'd just add, if you went back to the Permian slide deck that we published in February, we specifically pointed out three areas where we felt like Callon was significantly kind of off the mark in terms of where we would want to be on LOE per BOE, workover cost per BOE and downtime percent. And they've -- Callon has a history of a much higher well failure rate and including for new wells. They have a higher rate of ESP failures than we do. And many of those are around -- we feel around their equipping choices, and we're already making some changes on a proactive basis in that -- even on some of the wells that they've already drilled and completed and equipped.

There was a lot of inefficiency around compression and the use of their compression fleet, and we're making across a larger set of operations, we can make more economies of scale around compression optimization and even on the rate negotiations for compression costs. As John pointed out, they have a tendency to use a lot of ESPs for which they purchase power. That's very expensive and a big contributor to their LOE per BOE. They use a lot of contract labor, a lot of our supply chain aspects of using APA rates around services and around product using volume discounts that we get across the larger operations and just reducing overall usage.

They had a very high water handling and disposal costs, which we believe we can do much better at. They had a high rate of rental, rentals of ESPs, rental of compressions where we think we can do better at that as well. On the capital side, we'll use more technology to drill to use -- to decrease average drilling days on wells. We'll get better rig rates. We'll do a better job of rig moves because we're not moving rigs across the basin between the Delaware and the Midland Basin. We will use spudder rigs generally for a lot of the wells that we drill. They did not have a practice of doing that normally. Frac rates will get better at proppant costs, again, more supply chain type of stuff.

And then on facilities, we -- they typically have built facilities spec. We typically try to modularize that. We will typically go to multiphase flowing through a single line. They like to use test separators and meter three products in three different lines. So we think there's just -- and there's just a whole bunch more of stuff that we're going to be looking at and doing to reduce LOE per BOE and downtime and the workover costs.

Thanks Neil.

Good morning, Paul.

I'll jump in. The -- there's one dry hole in Suriname, which was related to Bonboni up in the north. It was one that we held and weighted because we didn't know how the North would factor in on the future exploration side. And so that's why we took that one now. And then we went ahead in Alaska and rolled off the two wells that we failed to reach TD on simply because the decision was made that it would be easier to go back and redrill those prospects with new branded wells. And so that's what the dry hole expenses were for.

Well, it's very preliminary, Paul. But we're excited about both. I mean these are not shallow wells in the book and play to high-quality oils. We were also very pleased with the early data, but we need to get the rock data back into the lab and analyze that and go through all that before we really share anything. I think one of the big read-throughs on King Street though, it was the smallest and the most risky of the three prospects, even though it's the one we got down all the way, but there is a very positive read through in the Upper Zone at King Street for the big target in Vudu [Phonetic], so it's very exciting.

And if anything, it has us feeling even better about the program and the acreage going forward. I mean we've moved 70 to 90 miles east of working hydrocarbon system. Truly wildcat area, and now we've proven petroleum system. We've proven oil, and there's also very high-quality sand there. So a lot to get pretty excited about going forward in Alaska.

I'll just say, it's highly likely that we redrill both prospects -- but it's -- we've got to work through the partners, and we don't have to make decisions yet on the 2025 drilling program. So we're -- it's something we'll be working through with the partners over the next several weeks. But at this point, it's something that could be done in 2025. It doesn't have to be done in 2025, but we'll be working through the partners with that. Okay. Thank you.

You bet.

Yes. Thank you. In closing, our Permian is performing extremely well, and we have just bolstered it with the addition of Callon and is now approximately 75% of the company. We will be integrating Callon over the next couple of quarters. And by the fourth quarter, you should start to get a good picture of what we can do with the Callon assets. We have pulled from some frac capital into the second half of the year which should really give us strong momentum as we head into 2025.

On the cost synergy side, we have increased our expectation by 50%, and we'll capture most of these by year end and we believe there is even more to do beyond that. And lastly, we'd like to make more progress on debt reduction by the end of the year, while also meeting our 60% shareholder return commitment. Thank you very much for joining us today.