Greetings, and welcome to the SM Energy's First Quarter 2024 Financial and Operating Results Q&A. As a reminder, this conference is being recorded.

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 describes 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?

Our first question comes from Zach Parham with JPMorgan.

Just wanted to ask about the buyback first. You talked about in the prepared remarks a reasonable 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. The guidance on assuming consistent buybacks seems to be the best modeling approach for now. However, things rarely unfold that smoothly. As we progress through the quarters, we will take the opportunity to repurchase shares during the open windows. With higher commodity prices generating more free cash flow, we might increase the pace of buybacks based on available opportunities. Some have inquired about our plans after fulfilling the commitment, and the Board will evaluate that. It's conceivable that we could initiate a new buyback program, but I cannot guarantee that at this stage.

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 accelerating higher than it was before in our guidance. So 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 tests 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 I'm just curious if you can maybe talk a little bit about some of the tests there. Some of the Deans in the area look quite prolific on an 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. We're quite excited about the Klondike acreage, and we've already drilled a 4-well pad, which we are currently completing. On the scientific side, we drilled a vertical pilot hole quite deep and conducted several sidewall cores and high-quality logs through that interval to assess all potentially promising areas there. Our current focus is on the development of the Dean and those 8 to 9 wells planned for this year, with the first 4 expected to be operational in the second quarter. It appears to be a highly promising play for us, especially with several offsetting wells to the southeast and additional wells we acquired 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 gathering lines that need to be in place, so we don't have to truck as much and getting the gas lines built to scale, which is a lot of the midstream. 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 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 in 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 it out to us.

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

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

Sure, Tim. But one thing I want to correct you on is that 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. It's great to hear that there's prospectivity in the Wolfcamp A. I would say we are not counting on that. If we're surprised and the maturity is higher for some reason there than we expected, that would be great news. But we're counting on this being more of a migrated oil play, which I've discussed before, which is oil coming from deeper in the basin and migrates into the sandstone intervals. That's why they are so prolific up there.

And then are these initial 4 wells all Dean?

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

Okay. That's great. And 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 discussing that. I know it's early days from one pad, but there was a big marketplace debate about the validity of your claims that you had 300 locations there. Just to help frame a resource, if the stacked pay proves to be something you can replicate, does that 300 location count move up dramatically? I'm just trying to understand the significance of this test that you're doing.

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, where they've been half bounded. But we've had fully bounded in the upper interval and several other pads. The thing to note is that these spaces are about 625 feet, and we've done that before. These go between two 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. It's exciting because of how productive and oily they are, and how NGL-rich they are. The wells on that one pad are between 11,600 and 14,500 feet long. 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, which really helps the economics, and they're oil-rich. So I'm really excited about that area, and you can see the strength of the wells and 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.

Our next question comes from Oliver Huang with Tudor, Pickering, Holt & Co.

Just wanted to start on the efficiencies. It's certainly good to see the continued capture there. I was just kind of wondering what you have achieved in Q1? Is it something that's already been incorporated for new plant activity starting in Q2 when you're providing the quarter ahead of the full-year outlook? Or is there 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 on new aspects of efficiencies, and we have quite a laundry list that our team is running through right now. That looks attractive, but we're not counting it unless we see it working. 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. Wade mentioned those in the prepared remarks, and that has the added benefit of reducing CO2 emissions from completion operations. Then we're seeing quite a bit in the way of efficiency gains in drilling, which translates to the number of feet we drill per day. It's more advanced and reliable downhole equipment, so you don't have to trip the bit as much. We're using a rotary steerable assembly, so we can keep the bit on the bottom longer, which helps also. On the cost efficiency side, a big contribution is using existing central production facilities that now are sitting with some latent capacity, which avoids the need for capital into new facilities.

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 drilling and completion for that 50% working interest? And are there any 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 two 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 we'd do everything for the 50%. And then the second question was, have we included this in our plans? 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. We're planning to drill 3 wells 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. We look forward to seeing many of you at upcoming events.

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