Permian Resources Corp Q3 FY2024 earnings call

• Successfully closed the Barilla Draw bolt on acquisition and continued driving operational efficiencies leading to well cost reductions. - Q3 production beat expectations with oil production at 161,000 bbls of oil per day and total production at 347,000 BOE per day. - Raised full-year oil guidance for the third consecutive quarter, with an 11,000 barrel of oil per day increase compared to initial guidance in February. - Maintained CapEx guide despite bringing online more wells, due to reduced cycle times and cost optimization. - Delivered leading cash costs with Q3 LOE of $5.43 per BOE, cash G&A of $0.95 per BOE and GP and T of $1.57 per BOE. - Adjusted operating cash flow was $823 million and adjusted free cash flow was $303 million in the quarter. - Increased the base dividend by 150% to $0.60 per share annually, with a base dividend yield over 4%. - Increased buyback authorization from $500 million to $1 billion. - Balance sheet is strong with over $1 billion deployed on acquisitions, leverage at one times, average bond maturity at ~six years, and ~$2.8 billion of liquidity. - Reduced current tax guidance for 2024 to $10 million to $15 million from $50 million previously.

During the third quarter, Permian Resources achieved oil production of 161,000 barrels of oil per day and total production of 347,000 barrels of oil equivalent per day. Oil is the primary driver of the company's performance, with gas and NGL production contributing modestly. The oil production contributed significantly to the overall results, with the company raising its full-year oil guidance due to strong performance in the base business and accretive M&A.

• Raised full-year oil guidance by 11,000 barrels of oil per day, with nearly 8,000 barrels per day from the base business outperformance and the rest from accretive M&A. - Maintained CapEx guide despite bringing online more wells. - Increased buyback authorization from $500 million to $1 billion. - Targeting a growth range of zero to 10% based on prior year's average for 2025, but too early to provide firm numbers. - Expecting CapEx to be slightly down quarter over quarter in Q4 from Q3, but details are preliminary.

• Regulatory uncertainties in New Mexico and potential setbacks, though management believes concerns are unfounded and the state is supportive of oil and gas development. - Market volatility and commodity price fluctuations that could impact production and financial results. - Risks associated with non-GAAP financial measures and potential differences between actual results and forward-looking statements.

Q: Good morning, guys. Outstanding quarter. Guys, my first question is just on your future operational plans. I'm just wondering, will 2025 D&C regional focus? I'm just wondering when you look at New Mexico and Texas, will that stay essentially the same? And just I'm wondering maybe probably nothing here, but just wondering if any potential loosening of restrictions by the administration, particularly maybe in like New Mexico or wherever might have any sort of changes operationally for you all?

A: I think ’25 will look similar to what the last couple of years have. Majority of the capital spend in New Mexico, with the balance probably being Texas, Delaware and kind of keeping Midland as sub-ten percent. I think there's a chance that you see a little bit less even in the Midland Basin than we had this year as we and we probably moved that to the Barilla Draw acquisition on the Texas side, but kind of majority of New Mexico development just like we've been for the last couple of years. We're well ahead of the permitting and all the needs. So like really having a looser or easier kind of regulatory environment, I think, probably doesn't change anything from our side. If on balance, it probably gives us a little bit of flexibility if we want to make some kind of more last minute changes around different pads, which is nice to have but not a need to have.

Q: Good morning, guys. I want to hit a little bit on how you view 2025. I know it's probably for you guys too early to give some firm numbers. But certainly on our side of the table, I mean, it's obviously a very strong point of emphasis right now. So just conceptually, can you help us think through like, look, you guys are really peaking on production in fourth quarter. As you look at strip commodity prices from that peak level or average levels in 2024, how should we think about the progression of production into next year at current strip prices and what does that mean roughly for CapEx?

A: Yeah, Scott, I mean, I think we're going to continue on now a long standing policy of not providing much of a look at 2025 guidance until we get to February of next year. I think that policy served us and our shareholders really well the last couple of years. I think that gives us a couple of months to further refine our plan. But I think just as importantly to assess the kind of macroeconomic backdrop and the kind of service cost environment. I think really our approach to what the next year and what growth looks like hasn't changed. I think we're targeting a growth range of zero to 10% based on the prior year's average. And I think for us it's really too early to tell what next year looks like. I think Will referenced it in his prepared remarks. Like our returns are really attractive today, but I do think there's some potential storm clouds on the horizon or some questions on the oil price from a macro standpoint. So for us, it's really too early to tell what it could look like. I think you're right in pointing out that Q4 is a really strong exit to the year and we'll kind of have to wait until next year to see what the balance of the year looks like.

Q: Hey, thank you very much for taking our questions. I want to approach 2025 a little bit differently. I want to start with 2024. So in your remarks, in your press release, you reduced well costs by approximately $1 million compared to last year. If you repeated if you have those costs today, where would you think your CapEx for 2024 would first shake out at?

A: So, maybe I'll ask that a different way. We reduced it off of $1 million off of ’23, yes. So, maybe I think the easier way I put it is, we're expecting to come in near the midpoint of our CapEx guidance and we've added 20 to 20 tilts to the year. So maybe that's a better way to answer what you're saying?

Q: Good morning, team, and thanks for taking the questions. I know in the past, you all spoken to running a fairly repeatable program targeting a similar zone mix, pad sizes, regional allocation. Just kind of given the increased size and scale of the business today, is there any consideration to potentially expanding on the average number of wells per pad as potentially a lever to further drive down well cost even further or maybe potentially tacking on an incremental zone in certain areas of the program when kind of considering the plan for the 12-24 months?

A: I'd say our plan kind of on a unit by unit basis is it's been consistent over the last few years and is still what we believe is the right balance of kind of how to develop our assets going forward. Just as a reminder, we are kind of very specific to the different areas we're developing and what the rock needs. There are some DSUs, a lot of them on the Texas side, where you need to go co complete kind of all the different benches, and that's the strategy that we execute there. As we move to New Mexico, there are some benches that need to be co completed, but others that have plenty of height separation or frac barriers that allow us to break different zones into different development packages. So that's what we'll do. We'll kind of let the rock dictate what the right answer is. And I would say our tolerance for larger pad sizes is higher today than it was last year and higher last year than it was the year prior. Just as the total number of rigs, number of wells and size and scale of the business gets bigger, kind of the lumpiness from really driving up pad size is we can mask it better within the business. So all that to be said, I bet pad size is slightly higher next year than it was this year just because of the tolerance we have. But we still had some 25 well pads this year because that's what the rock dictated in certain places. And we're not scared to do that and we'll continue to do that in the areas where we need to.