Greetings, and welcome to the SM Energy's First Quarter 2024 Financial and Operating Results Q&A. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Jennifer Samuels, Vice President of Investor Relations and ESG Stewardship. Thank you. You may begin.

Thank you, Maria. Good morning, everyone. In today's call, we may reference the earnings release IR presentation or prepared remarks. All of which are posted to our website. Thank you for joining us to answer your questions today, we have our President and CEO, Herb Vogel; and CFO, Wade Pursell. Before we get started, I need to remind you that our discussion today may include forward-looking statements and discussion of non-GAAP measures. I direct you to Slide 2 of the accompanying slide deck, Page 5 of the accompanying earnings release and the Risk Factors section of our most recently filed 10-K, which described risks associated with forward-looking statements that could cause actual results to differ. We may also refer to non-GAAP measures, please see the slide deck appendix and earnings release for definitions and reconciliations of non-GAAP measures to the most directly comparable GAAP measures and discussion of forward-looking non-GAAP measures. Got that out of the way. Also, look for our first quarter 10-Q filed this morning. And with that, I will turn it over to Herb for just a brief opening comment. Herb?

Thanks, Jennifer, and good morning. Thanks for joining us. We're obviously very excited about how 2024 is shaping up for SM Energy. So let's go ahead and get started. I'll turn the call back to Maria to start taking your questions. Maria?

[Operator Instructions] Our first question comes from Zach Parham with JPMorgan.

Just wanted to ask on the buyback first. You talked about in the prepared remarks a ratable pace for the buyback for the remainder of the year, that would imply around $60 million in buybacks per quarter. At current commodity prices, it seems like you'll have a significant amount of free cash flow that will allow you to build a lot of cash even after paying the base dividend and finishing off that buyback authorization. How do you think about using that excess cash, could further accelerating that buyback make sense? Just trying to get a sense of what happens with that cash.

Yes. Good question, Zach. This is Wade. Yes. We just -- the guidance on assuming ratable buybacks, I think it's just the best way to model it right now. Obviously, things never happen that ratably, right? And as we go through the quarters, we opportunistically repurchased during the open windows and you could see under your scenario with higher commodity prices, that's generating more free cash flow, you could see us buying back at a little bit more accelerated pace than that given what the opportunity set is before us. So that could happen. And many people have asked, what are you going to do when you get through the commitment and the Board will consider that. And I can imagine it being possible that we would continue on with a new buyback. But certainly no guarantees of that at this point.

And then just a follow-up. In the prepared remarks, you mentioned flattish production in 3Q and then kind of another step up in 4Q. That seems to indicate you would exit the year with oil in the upper 70s. Is that a fair number? Just trying to get a little bit more color on what that trajectory of volumes would look like through the back half of the year.

Yes. I think that's reasonable, mid-70s-ish given what we said. What we said about the third quarter being flattish, I mean it will be up. I think what's changed a little bit is the second quarter is obviously with acceleration higher than it was before in our guidance. So you're -- I think you're reading that pretty well. But you can assume the third quarter is up somewhat over the second quarter.

Our next question comes from Gabe Daoud with TD Cowen.

Maybe I was hoping if we could start at Klondike. You mentioned you did some signs there during the quarter and maybe starting to complete those 8 to 9 wells, where I think results should be ready by the third quarter call. But just curious if you can maybe talk a little bit about some of the science work there, some of the Deans in the area look quite prolific on oil productivity per foot basis. So just trying to get a sense if we could assume or expect similar results out of your program.

Yes, Gabe, this is Herb. Yes, we're quite excited about the Klondike acreage, and we've already drilled a 4-well pad and completing it right now. I will say on the science side, we did take a vertical pilot hole down quite deep and did a lot of sidewall cores and high-end logs through that interval so we could assess all the intervals that are potentially prospective up there. But we're focused now on the development of those -- initially the Dean and those 8 to 9 wells this year. And the first 4 will be online during the second quarter. So it looks like a great play for us. And you know we have quite wells offsetting it to the southeast plus the wells we -- that came with the acquisition in reliance -- from our reliance.

Yes. No, that's right. That's helpful. I guess as a quick follow-up to that, just taking to Klondike, 20,000 net acres. If you were to progress towards a true development program, is there any type of infrastructure spend that we should be thinking about there?

There is quite a bit of infrastructure there, but mainly it's the -- getting the gathering lines in place, so we don't have to truck as much in getting the gas lines built to the scale, which is a lot of the midstream. And then -- but otherwise, it's just pretty much normal equipment out there.

And then just the last one, the South Texas drill-to-earn any additional color you can provide on that?

Yes. A lot of people wonder how does the drill-to-earn works if they're not familiar with it? And generally, drill-to-earn is where you agree to drill a well or wells and return for acreage. In this case, we're going to operate and drill wells to gain a 50% working interest in around a 16,000 acre block, so that will get us about 8,000 net acres. The other details around that drill-to-earn really are kept confidential between us and the company that farmed out to us.

Our next question comes from Tim Rezvan with KeyBanc Capital Markets.

I want to follow up on Gabe's question on Klondike. We did analysis of the area. And I know you all have talked about the Middle Spraberry and the Dean. The Wolfcamp A looks extremely strong with sort of offset results. And so I was curious kind of among these 3 initial wells being completed, excluding the science well. Can you talk about what intervals you're targeting? And kind of maybe why you haven't talked about the Wolfcamp A as a primary target on that acreage?

Sure, Tim. But one thing I want to correct you on that there, there would be 4 producers, just 1 when we took a pilot hole down first, then we plugged back and drilled the lateral. So there are 4 wells there. Just 1 of them we have that vertical that we just got the data on. So it's great to hear that there's prospectivity in the Wolfcamp A. I would say we are not counting that. If we're surprised and that the maturity is higher for some reason there than we expected to be, that would be great news. But we're really counting on this being more a migrated oil play, which I've talked about before, which is oil comes for a bit deeper in the basin and migrates into the sandstone intervals. And that's why they are so prolific up there.

And then are these initial 4 wells Dean? All Dean or...

Yes, they are. They're all Dean wells.

Okay. That's great. And then as a follow-up, I think the comments on the Briscoe pad and the stacked pay opportunities are pretty interesting. Some other public companies are talking about that. I know it's early days from one pad, but big marketplace debate was on the validity of your claims that you had 300 locations there. And I guess just to help kind of frame a resource, if the stack pay proves to be something you can replicate, does that 300 location count kind of move up dramatically? I'm just trying to understand sort of what the significance is of this test that you're doing that you disclosed.

Yes, Tim, I would say it's not that much of a big increment in the test. The only difference is that the lower wells are fully bounded versus other places, they've been half bounded. But we've had fully bounded in the upper interval and several other pads. The thing to note is these are space is about 625 feet and we've done that before. These go between 2 different -- subtle differences in the landing zone in the upper Austin Chalk or the middle Austin Chalk and the upper interval that we've developed. So it's just really exciting because of how productive they are, how oily they are and how NGL rich they are. And those wells on that one pad are between 11,600 and 14,500 feet long. So we didn't have difficulty executing there. And the other 3 are between 11,900 and 14,000 feet. But there are long laterals, too, and that just really helps the economics also and their oil rig. So really excited about it on that area, and you can see the strength of the wells and just how they started. But it's not like they're a really big step in any way other than the bounding of the lower Austin Chalk wells.

[Operator Instructions] Our next question comes from Oliver Huang with Tudor, Pickering, Holt & Co.

Just wanted to start on the efficiencies. Certainly good to see the continued capture there. I was just kind of wondering of what you all have kind of achieved in Q1? Is it something that's already been baked in for new plant activity starting in Q2 when you're kind of providing the quarter ahead of full year outlook? Or is there kind of a wait-and-see aspect to it since it's only a quarter before kind of taking that fully on that incrementally faster case that we saw?

Yes. Oliver, when we change guidance, that means we've got a lot of confidence that it's appropriate to include it. So we're continually working new aspects of efficiencies in and we have quite a laundry list that our team is running through right now. That looks attractive, but we're not counting once unless we see them working. So the big ticket items for us right now are the increased substitution of natural gas for diesel and frac pumping operations on those DGB fleets that we're employing. And Wade mentioned those on the prepared remarks. And that has the added benefit of the reduced CO2 emissions from completion operations. Then we're seeing quite a bit in the way of efficiency gains in drilling. So this translates to number of feet we drill per day. They're really -- it's more advanced and reliable downhole equipment, so you don't have to trip the bit as much. And we're using rotary steerable assembly, so we can keep the bid on bottom longer. That helps also. Then on the efficiency -- cost efficiency side, a big one is using existing central production facilities that now are sitting there with some latent capacity and that avoids the need for capital into new facilities. We knew all along about what's going to happen, and we're just starting to see it really happen in a pretty significant way now. And then we're also bundling some services between South Texas and Permian. So we've got the benefits of the scale of the full operation between the 2 areas and that helps. And then you know how activity has reduced, so rig counts are down, frac spread counts are down. So we're actively rebidding services and seeing discounts that way. And I can't tell you when that will stop or how much more we'll get there. But that obviously is a contributor. So that's a list of things that I'd say we're highly confident and not a list of things that we're still pursuing.

Okay. That's super helpful. And maybe for a follow-up, you mentioned earlier some of the details that are confidential on that drill-to-earn. But I just wanted to try and clarify, are you all responsible for 100% of the D&C for that 50% working interest that you kind of referenced? And is there any sort of details in terms of how many wells you're planning to do on that acreage this year and if that's already embedded within the full year well count out of the South Texas region?

Yes. Okay. You got 2 questions there. The first, we can't reveal or divulge details on the deal. But I'd say no is the simple answer to your first question there. No, we're not saying everything for the 50%. And then the second question was, have we baked this in? Yes, we knew the deal was far enough along when we set the budget in February that we integrated that into our plans for the year. The 3 wells that we'll drill there this year.

There are no further questions at this time. I would now like to turn the floor back over to Herb Vogel for closing comments.

Thanks, Maria, and thank you for joining us, and we look forward to seeing a number of you at upcoming events.

This concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation.