Permian Resources Corporation (PR) Earnings Call Transcript & Summary

Good afternoon, and thank you for joining us at JPMorgan's 2021 Energy Conference. I'm Zach Parham from the E&P equity research team here at JPMorgan. With us this afternoon, we have Sean Smith, the CEO of Centennial Resource Development. Sean has been the CEO since April of 2020. Prior to this role, Sean was the COO, and prior to that, the VP of Geosciences. Prior to Centennial, Sean served in numerous roles at QEP, Resolute Energy and Kerr-McGee. With that, I'll turn it over to Sean for an intro, and then we'll jump into the Q&A.

Great. Yes. Thanks, Zach. I appreciate that. By listing off all those companies, it makes me feel older than maybe I should be. But thanks for the introduction. And for those who don't know [indiscernible] quick overview of who Centennial is and maybe a little bit of background before we jump into Q&A. But we are a Permian Basin pure play. In fact, a Delaware Basin pure play, a subbasin of the Permian. We've got about 82,000 net acres located between Lea County, New Mexico and Reeves County, Texas. It's really in a good shape. It's been a few years since we've started cobbling this together, and it's now very much a cored-up position in those 2 areas, both the Northern and Southern Delaware. And that allows us to grow a lot longer laterals. We've been increasing our lateral length year-over-year-over-year for the past several years. This year, we think we're going to average around 8,800 feet on average, of which greater than 95% is operated and very large contingency of HBP, 90-plus percent HBP. So position is very well held together for both long laterals and operated point of view. Producing around 30,000 barrels of oil per day right now. We're definitely an oil-weighted company. One of the major bragging points I would say about our position now is that we've got 15-plus years of inventory at much lower commodity prices than where we stand today. So feel very good about what we would consider as premium inventory and a long runway there to develop that pretty high rate return. So feel good about our position. From a cost perspective, a lot of folks have talked about bringing down costs over the past year. We've done so as well, meaningfully across the board. Whether it's on the OpEx side or on the CapEx side, we've seen tremendous improvement there, not just from a deflationary environment, which is what we used to be in, but also from a structural point of view. And then we've just taken costs out of the business through efficiencies, again, both on the operating and the D&C side of things. From the commodity prices, that really helped, obviously, but bottom line is by taking a lot of those costs out of the business ourselves, we've been able to generate meaningful free cash flow to the tune of the past couple of quarters, substantially above, I guess, what we were planning on years before. This year, we're thinking somewhere north, well north, I would say, now of $100 million free cash flow, and that's going to allow us to really meaningfully delever the business in a very short amount of time. Early in the year, I had mentioned on previous earnings call that targeting kind of sub 2.5x net debt-to-EBITDA was a goal. I'd say as we look forward now to the business, I think we'll plan to end the year closer to 2x with a pretty short line of sight on being sub 1.5x to the following year. So a massive deleveraging of the business, and that's really a credit to both the operations team as well as, of course, commodity prices make us all look smarter than we are. So that's the basis of the company. I feel very good about how we're positioned both as a stand-alone, but also looking for opportunities to bolt on as well. So that's how we're thinking about the business in the short term. So with that, Zach, I'll turn it back over to you.

Great. Thanks for that, Sean. I guess we've got a 7 handle on oil prices now. You all have been holding production flat this year. How are you thinking about the 2022 program at this point and that balance between production growth and free cash flow generation?

Right. That's a good question. I think as I mentioned kind of in the opening statement, free cash flow generation and delevering is our primary focus. So we currently have 2 rigs running. And what we have said is that's essentially a maintenance program. So targeting kind of a flat production from Q4 volumes of last year to average that of this year. And I'd say that it's a maintenance program. 2 rigs is what we plan on running for the year. The fact that we continue to get better operationally, both from a cadence perspective and also from a cost perspective, are really allowing us to probably have single-digit growth even just by maintaining a 2-rig program. So feel good about that, that we're going to generate substantial free cash flow, delever the business and have what we'll call very low amount of growth. But it's really just a spreadsheet math at that point. Keeping 2 rigs busy allows us to have that.

Got it. Is there an oil price out there where you would consider adding a third rig? Or does it make more sense to just get that low level of growth with higher free cash flow generation?

I think right now, for sure, I think we're generating the most value by returning that cash flow to our balance sheet. I think that's what is generating value for the shareholders. So right now, there are no plans for adding that third rig. Is there a point in time? There probably is at some point down the road. What personally I'm waiting for is for the OPEC+ barrels to kind of get back on the market to stabilize the commodity price at a fully saturated oil supply-demand ratio. Once that occurs, and it looks like there is a need for additional barrels and therefore, a reward from the market by putting more barrels in the market, we might look at doing so. And as you mentioned, we're running 2 rigs. So adding a single rig would be a 50% improvement on the rig count. And so it would add meaningful growth to the company if we decide to do that down the road. But for right now, everything is focused on kind of a maintenance mode and generating free cash flow and paying down [indiscernible].

Got it. So you continue to get more efficient in your drilling and your completing of wells. As we go through the rest of the year, if you continue to get more efficient, how do you look at what happens kind of late in the year? If you've exhausted your budget because you're doing things faster, do you keep that program running and maybe raise the budget a little bit? Do you take a frac holiday? Just how are you thinking about that as you go into the back half of the year?

Yes. It's a good question because I think that is an issue for a company like ours that continues to get better at what they're doing. From an efficiency point of view, our costs continue to go down. Taking aside the inflationary side of things, our costs are coming down. But by the fact that our cycle time is also going down, we're likely going to drill more wells than what we had initially planned, which probably pushes us towards the higher side of our guidance range but still within it. Should we be on the high side of that, as you mentioned, we have the option of taking a frac holiday, to use your terms, and build up a few DUCs if we decided that was the most prudent thing to do. But I think right now, we're going to fall within our range, and I'm pleased with the progress that we've made both on the cost side as well as on the cadence side.

Got it. So I think you're targeting now $750 to $850 per lateral foot on D&C cost. Can you just talk about -- and those costs are significantly lower than where they were at if you look back 2 or 3 years. Can you talk about what's allowed you to drive those costs lower? And then on the opposite side of that, now with oil above 70 and some activity coming back, are you seeing any initial signs of cost inflation? And how do you see that trending through the back half of the year and into '22?

Yes. Good question. Yes, our costs have come down tremendously, as you pointed out. In fact, in our last earnings report, we published a slide that really showed our costs coming down significantly year-over-year, while at the same time, our lateral lengths went up materially. So drilling things for less money and a shorter time is really the most important there for a longer lateral length. So improvement on both sides of that equation, which has been great, which has really led to that overall dollar per foot reduction year-over-year, I think that those things are structural in nature, meaning that they are going to remain regardless of an inflation or a deflationary environment. Some of that -- what caused that was your question. In Texas, we kind of had a redesign on wellbores and the fact that we're drilling everything with 1 less string of casing. So that enabled us to drill a little bit faster and save a few dollars. And then also just really paying attention to all the small, little, minute details. And the guys in the field now, instead of measuring things on kind of half day or a full day increments, now it's down to hours and even minutes, in some cases, how they can reduce downtime, and they're doing an outstanding job. We've got walking rigs now. Both of our rigs are walking rigs, and so that helps reduce cycle time as well. So all of those things, again, are structural or sticky in nature in that those stick around, and we think that we can continue to even potentially put prices down on a peripheral basis lower. Now on the flip side of that is the inflationary question. And I would say, across the board, we are having those discussions with various vendors. I think that it is -- we felt it in certain areas. We've done a fairly good job of getting ahead of that by signing certain contracts that kind of get through at least the near-term inflationary pressures. But it's coming. If these prices hold where they are today, I do expect inflation to continue to increase. And ultimately, I think that's a healthy thing for the business. I think the service providers need to make a margin to bring good talent to the field, and we want those talented folks to work for us, right? So it will all balance out, and I'm okay with some inflation, honestly. I think it makes sense for everybody to have a healthy E&P sector. So I do think it occurs much more in the back half of the year than in the front half of the year. A few things hit early on, steel prices and things like that. But again, we had some inventory. And so it didn't hit us a whole lot. I do think we'll see in the back half of the year. We did plan for that. We had put 10% inflation into our budget. I think that's probably the right number, and it's more back half-weighted. I think it's really going to be interesting to think about next year, and as we disclose next year's budget, how the service industry has reacted to stronger prices and what that kind of inflation looks like. But again, ultimately, I think it's healthy for the entire sector to have some higher costs in the service business.

Got it. Maybe shifting gears a little bit to the balance sheet. You talked about getting closer to 2 turns of leverage later this year and closer to sub 1.5 turns in '22. Do you have a leverage target? What do you think is the optimal level of leverage or gross debt to run at Centennial?

Yes, I'm pretty pleased with the fact that it wasn't a few months ago that we talked about being pleased at -- end the year at 2.5x. And now we're talking at 2x or depending on commodity prices, even lower. So very excited about how that's repositioned the company. There was a point in time where 2x levered was the standard, and that's what you were always shooting for as an upstream E&P company. Times have changed quite a bit, and now it seems like 1x is kind of where we're -- and that's honestly a safe place where we want to end up to. So kind of 1x is a long-term target for us, long term being not that far away, kind of in the 24-month time frame. It feels like that's about where we can meet depending on strip prices and whatnot. Ultimately, that's the goal. I think as we start to look ahead and get closer to that 1.5x, the next obvious question is shareholder returns. I think that's when companies like us, that's certainly when we will start having serious discussions about what that shareholder return is. Is it dividend? Is it -- what kind of dividend? Is it fixed? Is it variable? Is it a onetime special? Are you doing share buybacks? And so all of those things come into focus once you kind of get below that 1.5x multiple, and I think that's when we'll start discussing it seriously with our Board and look to do something in the not-too-distant future beyond.

Got it. You answered my next question already. So I guess and also thinking about the balance sheet, you all have got, I think, around just under $300 million drawn on the facility. As of the end of 1Q, we've seen a number of high-yield issuances by some of the SMID cap E&Ps recently that have come in at rather attractive rates. Do you think about -- how do you think about that balance on the credit facility? Do you think that's something you'll just pay down over time with free cash flow? Do you think about terming it out? Just how are you thinking about that?

Yes. I think with the amount of free cash flow that we're generating now and then next year as some of the tougher hedges roll off, I think we'll be generating substantially more. So I don't think there's a need to term up [ bad debt ]. I think we've got a very clear line of sight on being able to fully repay the revolver before it's due. That being said, it is a mid-2023 note. And so maybe there's a time where we work on that a bit as that date gets closer. But ultimately, and I think that we're not going to turn that out, we'll just likely pay off with free cash flow.

Got it. Shifting gears a little bit. The management team has been relatively open about the fact that adding scale is important in the E&P business as a whole. The A&D market has been very active of late. We've seen some deals trade in the Delaware as well. Oasis selling the private transaction as well. Just how do you see CDEV participating in that market going forward?

I would say we're going to be active, but prudent. As I mentioned earlier in the call, we've got 15 years of inventory at much, much lower commodity prices. So where we are now is significantly more than 15 years of high rate of return inventory. So to me, that's a real important item that we need to gauge as we're looking at opportunities is would the inventory that we bring in be accretive? Does it compete for capital? I think it's got a very high bar to pass. And so that's 1 gating item. The other item is from a leverage perspective, I think that's another reason for companies to combine or look to do something. And the fact that we're deleveraging so quickly on our own, it's another tough hurdle to pass that it would be accretive to our already deleveraging story. So while we're going to be looking very hard to add some accretive acreage to our position, we're going to be prudent with -- by doing so. We are not being pushed in 1 direction to fix our balance sheet, to add inventory. We kind of have already -- have all of that under our own -- our current company goals right now. And so there's no reason to force ourselves into that. I am personally a believer in size and scale as a way to take out corporate costs and lower your unit cost across the board. But again, it has to be accretive to our metrics. And so if you see us do something, you'll know that we have done the due diligence to make sure it's accretive for all of our shareholders.

Got it. And then another question on M&A. We've seen a number of kind of low, no premium mergers between E&Ps recently. Is that something that could make sense for CDEV to gain scale by merging with another SMID cap E&P?

I think it could make sense. I think that there are very few opportunities, again, that would be accretive to us. I think that we could be accretive perhaps to people. But I think that as I look across the board and do the obvious names of -- I think everybody would put the same 5 names together, there aren't very many of those that make a whole lot of sense, in my opinion, for us. I think you're more likely to see us to do sort of strategic bolt-ons, whether that's at the asset level or smaller entities. So while I wouldn't rule out a low, no premium combination, I have a hard time identifying which one would make sense for the shareholders, in our case.

Got it. You all do have some acreage in New Mexico. And earlier this year, we had the moratorium on leasing on federal lands. I know you all aren't that exposed to federal lands, but how would you view adding additional acreage on federal lands at this point? Do you feel like that's too risky? Or is it something you would pursue?

I think that as the new administration took over and they put the 60-day moratorium on federal lands, it spooked a lot of folks and lots of questions around that and how the new administration was going to handle oil and gas. Since the 60-day moratorium has been removed, I know ourselves as well as others have received permits and extensions. And essentially, it's kind of gotten back to business as usual on our federal position. I'll remind you that, and you kind of mentioned this, that it's a very small portion of our total position we have, which I think is around 4% of our total position, which is around 3,300 acres is on federal lands. And so feel good about our current position. Would we add more there? I would if it were at attractive prices because I think we've got enough diversification to allocate capital elsewhere. Should there be another issue with the administration, we could pivot quickly. That being said, I think that some very attractive acreage on some of the federal lands. And so if we could get it at the right price, I think it would tuck in nicely to our current inventory.

Got it. Shifting back over to operations. I think about 70% of your '21 completions are in New Mexico this year. Will you see that normalizing the closer to 50-50 over time? And how do you see that impacting capital efficiency, just given New Mexico is a little bit oilier?

Yes, it's a good question. Yes, this year, we are 70-30, kind of 70% capital in New Mexico and 30% in Texas. Some of that has to do with the age of the assets. Texas is a bit more mature. It was built out. So we had focused essentially all of our energy in Texas over the previous years and started to shift slowly to the north as we build out our infrastructure and invested in all the systems that make it an efficient operation to run. Now we're at that stage where it's very efficient to run and drill and complete hookup wells, both from the oil, gas and water side of things. So it makes sense to pivot our capital in that direction. And it's a bit more oily, as you pointed out. But I think from a rate of return perspective, I'm very pleased with the results both in Texas and New Mexico. On a go-forward basis, though, we haven't released what next year's guidance looks like. My guess is it will be slightly skewed to the north versus the south, so not quite that 50-50 scenario that you brought up. But we'll see how that rig schedule develops next year. And as we release guidance, obviously, we'll give more detail then.

Got it. And then within your Texas development, you've kind of got the legacy Centennial acreage and the Miramar acreage. How do you think about the development split between those 2 areas going forward?

Yes, it's interesting to think about that because there are times when I think we get pressure from the industry, the investment community that we should be developing 1 versus the other, and it's gone back and forth. As gas prices and NGL prices have been elevated, there has been a shift towards some of the Miramar position, which is higher GOR, and we're very pleased with the returns. On the flip side of that, as NGL prices weren't as strong or we're not in full capture mode there, then we pivot towards our more oily assets. So I'd say that it's a rather even distribution, whether it's in the Miramar or the lower GOR areas in Texas. I don't think we have a definite way that we're going to only develop 1 area versus the other. I think it just makes sense [ and our timing are developed ] and making sure that we're mixing our assets properly, reducing interference between wells and just managing the full development field.

Can you talk about -- a little bit about the pad sizes that you're utilizing now and how you're thinking about co-development, both in New Mexico and in Texas?

Sure. Running 2 rigs and being a public company is interesting when you think about quarterly releases and things like that. So what we have found to be the most effective and useful is kind of in the 2 to 4 wells per pad is what we think is effective and efficient way to develop the asset from a single rig perspective. It doesn't mean we don't put both rigs next to each other and develop a larger pad from 2 to 3 to 4 wells per rig. But on an individual rig basis, that's kind of how we think about it. From a co-mingling perspective, we do a fair amount of that, and we'll identify 2 zones that we think are best developed together. For example, in Texas, the Wolfcamp Upper A and the Bone Spring are good zones to develop together on our properties. So we tend to do that. In New Mexico, you have a bit more vertical separation. And so that allows you to be a bit more open to how you're developing from a vertical communication point of view. So there are areas where we'll develop only the 3rd Bone Spring Sand by itself and then come back in later and develop the second. And there are certain areas where we think it is more prudent to develop both of those together. So it's kind of on an area-by-area basis, but we certainly take that into account as we come up with our development plan.

Got it. And then on lateral lengths, I think you all were at 8,100 foot, like, on average in 1Q, which is up significantly than where it was in the past. Can you talk about how that's going to trend going forward? Are you going to be able to continue to kind of take that average lateral length higher both in Texas and in New Mexico?

Sure. Yes, that's a great question. We -- as you mentioned, first quarter was 8,100 feet. What we said for the years, we plan to average around 8,800 feet per well. And so obviously, first quarter being 8,100, that means the back half of the year has to be a fair amount higher than that, and that is the plan. It's really a credit to our land team. You mentioned it's been a pretty material increase year-over-year and even quarter-over-quarter on lateral lengths. We've been able to swap, trade and move some acreage positions around to allow for longer laterals. I think we all agree that the longer laterals are the most efficient way of developing these assets, and we see it the same way. And so our position now, as I mentioned earlier in the call, is kind of cored up such that it's allowing for us to have even more extended laterals than what we had in previous quarters.

One more operational question. On the 1Q call, I think you mentioned some excitement coming on -- on what's coming up as far from a well productivity standpoint over the next few quarters. Can you just give us a little more color on kind of what you're expecting there in regards to well productivity and maybe a little background on what could be driving those changes?

Sure. So part of it is a pivot to New Mexico. And as we learn about exactly how to target certain reservoirs there, we continue to see exciting things come out of that development. Q1 was our lowest producing quarter for the year, and that's what we expected. And as we have brought on some of these newer wells in New Mexico, I'd say we've seen some nice positive effects of some of those wells, both from the productivity point of view, but also from the cost side. Again, cycle time, we're just continuing to see downward pressure on cycle time, which is outstanding. So it's really a combination of both productivity and the time, which then equates to cost of these wells have both seen continued improvement. So without giving 2Q forward guidance, I look forward to sharing some of those operational things that, really, our COO and his team have driven out of the business. But it will be a pleasant thing to report next quarter. Previous quarters, but the most recent 2 quarters, has really been focused on the finances and getting through this amazing industry event that just happened and making sure that our finances are settled. Now we can get back into a mode where we can talk about operations and how we've driven efficiencies in the field. So to look forward to sharing that in the coming quarters.

Great. Maybe just one on hedging. In 2020, I think you all added the first hedges in the company's history. Can you talk about your hedging philosophy going forward? And does that change as you become less levered? Do you want to maintain more commodity leverage as you maintain less financial leverage?

Yes. So early on in the life of the company, I think there was a decision that the commodity prices were bullish and they were, and we want to take full advantage of that and could have some exposure there because we had 0 debt, right? And very little debt at the time allows you to take a bit more risk. As the company matures, as now we are getting a few more years long in the tooth, if you will, it makes sense to be a bit more conservative and protective of the cash flow that we're now generating. So we've pivoted to having a very active hedge book and active hedging team. We meet on a very regular basis. And the team presents material to me, and we all talk about strategies and where we see the markets. And we make some decisions on a weekly, monthly, kind of quarterly basis. And I think it's been in a very efficient way of layering on strategic hedges. We are, I call it, strategic and opportunistic in that we don't have set marks that we're trying to hit by a certain week or month or quarter. We have decision points around how the business is evolving. And when there look to be opportunities in the market that we can take advantage of that we think are both protective of our cash flow but also allow for our shareholders to realize some of the upside, those prices have continued to go up, then we take those into account. From a hedge book this year, we'll end the year -- I think if you took all of our hedges together, you'd say we were about 50% hedged for 2021. That's front half-weighted, and then it gets less as we get to the back half. I think that's a decent way of looking at the business going forward. You mentioned now that we're becoming delevered, does that reduce our exposure to hedging? Perhaps. But again, it's very market dependent. So I hate to put specific targets out there for how we're going to go forward, but we will always have some kind of hedge position to protect the cash flow. I think again, #1 for us is generating free cash flow and delevering the business. And I want to make sure that we are protected.

Got it. We're running towards the end of our time here, but just one last one for me. ESG has been kind of a front-of-mind topic for investors. Can you talk about what Centennial is doing from an ESG perspective? And also maybe comment on gas flaring and what you all are doing from that angle as well.

Great. Right. Lots of bragging points there, and I know we're short on time. I can talk for a whole hour just on that alone. Very pleased that we produced our sustainability report last quarter, and I think that it showed very well. We got a lot of positive feedback from our investors and others on the detail and the lengths that we went to disclose various things. It's interesting that sometimes you brag on yourself, but getting a third-party review that's as positive as one that came out. Wells Fargo produced third-party review of really the entire industry, so large caps all the way through the SMIDs, gas companies as well as oil companies, and they had us running to kind of top quartile there, again, some very strong leaders. And so it was a proud moment. The fact that, that was our initial push into the space, I feel good that we have been tracking most of those things and just hadn't put it into a fulsome report and now it's out there. From a flaring perspective, I'd say we've been -- the last couple of quarters, we're at 99% gas capture, so 1% or less flaring, which is outstanding. We track our GHG emissions, of course, spills and incidents and accidents. I think we're doing a very good job across the board. We continue to implement new things to help reduce emissions, whether it's dual fuel or electrification of the field, oil [ health ], water recycling, all of those things we're pushing hard on to do our part in regards to the new ESG standards.

Great, Sean. We're running up against the end of our time here. Sean, thank you for participating today, and thanks to Centennial for supporting the conference. Thanks to everyone that's on the line with us as well.

Thanks, Zach. Appreciate your time, and look forward to having these in person again sometime soon.

Same.