SM Energy Company

Thank you for standing by. My name is Jeanne and I will be your conference operator today. At this time, I would like to welcome everyone to the SM Energy's second quarter 2024 Financial and Operating Results Q&A conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star followed by the number one on your telephone keypad. If you would like to withdraw your question, press star one again. Thank you. I would now like to turn the conference over to Jennifer Martin-Samuel as the Vice President, Investor Relations and ESG stewardship. You may begin.

Thank you, Jeanne. 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 Bogle and CFO Wade Purcell. 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 the accompanying slide deck earnings release and risk factor section of our most recently filed 10K, which describe risks associated with forward-looking statements that could results to differ. Also, 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. Also, look for our second quarter 10Q that was filed this morning. And with that, I will turn it over to Herb for brief opening commentary. Herb?

Thank you, Jennifer. Good morning and thank you for joining us. It was an outstanding quarter with a lot of great news. So let's go ahead and get started with the Q&A. I'll turn it back to Jeanne to start taking your questions.

Thank you. The floor is now open for questions. If you have dialed in and would like to ask a question, please press star 1 on your telephone keypad to raise your hand and join the queue. If you would like to withdraw your question, simply press star 1 again. If you are called upon to ask your question and are listening via loudspeaker on your device, please pick up your handset and ensure that your phone is not on mute when asking a question. We do request for today's session that you please limit yourself to one question and one follow-up. Again, press star 1 to join the queue. Your first question comes from the line of Gabe Dowd with TD Cowan. Please go ahead.

Thanks, Jeanne. Good morning, everyone. I appreciate the time this morning. I was hoping we could maybe learn a little bit more about the Woodford Barnett results. I guess curious about the development plan here, whether or not there are more wells in the formation that are expected to turn in line this year. What does development look like from a spacing standpoint? And then I guess what are the oil cuts expected on these wells?

Thanks, Gabe. This is Herb. We are excited about the Woodford Barnett and the Permian. It's an over-pressured play, which is great. The wells initially flowed naturally and for quite a while before we put artificial lifts on. They are 56 to 58% oil, and that's on a two-stream basis. I imagine the gas will be quite rich. I don't know the BTU content there yet. That's about 50 API oil. In terms of the development, we are a ways away from that, but we do know that we are well surrounded by offset operators, and we showed that in one of the slides that the performance of these wells is really excellent, and we will be working the development plans over the coming months. We do not have any additional turn in lines planned for this year in Woodford Barnett.

Thanks, Herb. That's great detail. I appreciate all that. Then I guess just as a follow-up, shifting gears to the buyback and commentary around maybe more of a focus on debt reduction near term versus leaning into the buyback. I think last several quarters you've been around 40 to 50 million a quarter on buyback. What does the pace look like to close 2024 and then any additional color on the pace in 2025? Thanks, guys.

Yeah, this is Wade. As we've said with the acquisition, with taking on an additional leverage, we will be prioritizing free cash flow in the near term to debt reduction before we get back into the pace that we were on buying back shares. I will say, though, that all or nothing during this period prioritizing debt reduction, there very well may be times, probably will be times, where we step into the market and buy back some shares, especially on days of weakness or other times. We certainly still like stock price. There's no doubt about that. We have our internal view of NAV, but that will be a priority with free cash flow, though, until we get back below kind of in that one times area, which we project being the middle of next year, depending on commodity prices, of course.

Okay. Okay. Thanks, guys. So not all or nothing approach. Okay. Very helpful. Thanks a lot. No. You bet.

Your next question comes from the line of Zach Parham with JPMorgan. Please go ahead.

Thanks for taking my question. First, just wanted to ask a little bit on the trajectory of oil volumes from here and as we move into 2025. Your implied 4Q guidance rates around 115,000 barrels a day pro forma for the UETDA deal. That compares to the preliminary guide you gave of 100,000 barrels a day for 2025. Can you just talk a little bit about the production trajectory you expect through the year? Do you expect, as you slow down activity, do you expect to see the change in the year? Can you kind of level out? Just curious on kind of tying those two numbers together.

Hey. Thanks for the question, Zach. This is Herb. You know, in projecting how many TILs we have, we're obviously early days here. It's August, and we're still in the HSR approval stage. So we'll figure out how many completions XEL actually puts online, and that will sort out where we are at year end and how 2025 will play out. We're still working a lot of scenarios on, you know, depends on what the commodity prices will be next year. And so we're really sorting that out. We don't know the details of all the rig contracts yet on the XEL side. So we work in the rig cadence, the completion cadence. But what we'll really look at is how do we get the best capital efficiency between the three assets? We know the returns are similar between the three, which is a great position to be in. Now how do we get the capital efficiency as good as possible? So that's what we're working right now, and we'll get a lot more information assuming HSR approval in late August.

Thanks, Herb. My follow-up, just wanted to ask on OPEX, particularly LOE, this quarter was 482 for BOE. That's significantly below the low end of the four-year guidance range. Can you just give us any color on why LOE came in so low this quarter and maybe your expectations on how LOE trends from here? Yeah, on the LOE side,

the second quarter was excellent. We obviously have seen some cost reductions in a number of areas across the board other than labor. We do expect a little bit of increase in third quarter with some additional electric generators as we're waiting for the utility to connect up some of our well pads. And then there's some additional water handling costs also that we'll have to cover. So I don't want to say it's an anomaly. We're going to keep driving costs down, but we do expect third quarter to be a bit higher than second quarter.

Thanks.

Your next question comes from the line of Neil Dingman with Truist Securities. Please go ahead.

Morning, nice to see you guys. My first question is around the Eagle Ford activity specifically. Can you discuss the future risk of sea activity? I'm just wondering, will you co-develop the middle and lower Austin Chalk going forward along with Eagle Ford now that you've had success on the Briscoe Sea? I'm just wondering how you're going to get after that.

Yeah, Neil, I'll answer your question. I didn't catch one word that you said there, but I'll just start and then tell me if there was another question there. But on the Eagle Ford, on the west side, we do anticipate co-developing the upper and the lower landing zone that we have in the Austin Chalk. And staggering notes, we had great results on the first place where we had fully bounded a number of wells altogether. And where judicious, we will also tie in Eagle Ford wells over on that western acreage. On the eastern acreage, we probably won't be staggering wells to that degree just because the Austin Chalk is a bit thinner over there and gassier. But it sure looks to work great on the western side to go with all three.

Well said. And then just to make sure on the my question, this one is just on the UN2 side. Now that you were able to add additional acres, is the plan to develop all those acres sort of that same pattern that you had talked about with the original XEL acquisition? Or is there any change now that you have that additional inventory?

Yeah, great question. You can imagine what the state of play is currently. We will be inheriting a lot of activity underway. We'll be inheriting quite a few ducks. We'll be looking to optimize the capital. And then ultimately, by the time we get to 2026, we'll be looking at an integrated how do we optimize the infrastructure that's in place? How do we benefit from XEL's infrastructure for the Altamont assets? So we're looking forward to that optimization. We see that as some low-hanging fruit there to take advantage of what XEL pre-invested in throughout their acreage. Great to hear. Thank you.

Your next question comes from Mike Scala with Stevens. Please go ahead.

Good morning. I wanted to follow up on the Barnett Woodford Wells. Just to clarify, those were on that western extension acreage, I believe. Correct me if I'm wrong there. How do you get to the 20-plus thousand net acres perspective for that? Assuming all 9100 of the extension area plus a portion of the legacy Sweetie Peck. And I guess also are those zones perspective anywhere else in the Midland, particularly in Howard County, where you have acreage?

Great question, Mike. I can see why there could be some confusion about that. The 20,000 acres basically is the entirety underneath Sweetie Peck. We did some part of the land work to secure the deep rights under our Sweetie Peck position. And then we added that 9100 acres to the west. If you look at the Woodford-Barnett well control of offset operators, you'll see that there was a gap under Sweetie Peck. So those two wells that we just did are actually under Sweetie Peck. And that's why we have the confidence, why we said the 20,000 acres, because we are surrounded by good Woodford-Barnett wells over there. And then just with the obviously there's a lot of vertical well control around and that enhances our ability to map the play. And that's why we have the confidence. And obviously we'll be working over time to figure out the optimal spacing for the play. But we're excited that over pressured nature of it and the oiliness of it is really helps on getting the economics improved over time too.

Okay. And not really looking anywhere outside of Sweetie Peck. I would

say I'm never going to speak for our geoscience team because what they come up with is pretty amazing sometimes. And we'll see. I have no doubt that we have Woodford-Barnett maps and if we can, with the discipline we have in terms of putting capital to land, if they come up with good opportunities, we pursue them. But they have definitely mapped the Woodford-Barnett and I'm sure I'll be seeing stuff in the future that I don't know about yet.

Okay. Look forward to that. And then I just want to follow up on the Ultraman Energy Assets. It looks like that acquisition, like you said previously, is mostly acreage. How would you characterize that? Has it been delineated? Is it more exploratory in nature than the XEL properties? Just looking for a little more color there.

Yeah, it's a great question, Mike. There's quite a bit of vertical well control around so we can map it quite well. The industry's learned quite a bit over what makes successful The southern portion of the acreage is really well delineated and then a little bit less delineated as you go further north. The technology applied is not as advanced on Ultraman as it is on XEL. I just got to say the XEL team is really excellent at what they do in terms of optimizing and driving capital efficiencies and putting smart infrastructure in place. And so that's why we feel really good about Ultraman also. Ultimately, we put 75 locations on it for now and we'll see over time how much more we can add. And that doesn't include any deep cube or anything like that that has upside inventory potential.

Very good. Thanks, Herb. You bet.

Your next question comes from the line of Timothy Rezvan with KeyBank. Please go ahead.

Good morning, folks, and thank you for taking my question. An area that really hasn't been discussed in the release or today is on Klondike. And I know I think recent dialogue suggested you have more to say with third quarter earnings. But I know there's a lot of completion work going on. So, Herb, can you maybe give a qualitative assessment of what's happening up there right now?

Yeah, great question, Tim. You know, we had to hold something back for the third quarter. So I would say that the Klondike Wells, we have them online. Doing well, we've got two that have been online for a while, two more that have come on just recently. We anticipate two more during the third quarter and then there'll be a final two. So it looks like we're tracking for eight completions in Klondike this year. I guess all I'll say is, you know, we don't give breaks until we get the IP 30s. And there's still, I wouldn't call them IP 30s yet, even though they've been, some of them have been producing for a bit. So they're still ramping, some of them are still ramping up.

Okay, we'll stay tuned, I guess. And then I just wanted to follow up on Gabe's question on Sweetie Peck. I understand it's early days and you don't have much to, too much to disclose. We've heard some peers talk about oil cuts more in the 75 to 80% range. I mean, obviously 50 to 60 is a good number. Can you talk to what you know about how those should trend and if there is sort of variability across that formation? Is any insight helpful? Tim,

you could be a geologist there. The east side is deeper, so that will be gassier and the west side of our acreage is shallower and will be oilier. So you'll see that trending as you move west from our existing wells, you'll see it get oilier. And that's simply the depth and the thermal maturity level in the Woodford Barnett there. So you will see some variability and so I fully expect, you know, if you look at some of our peer wells that are just off our western flank, they will be higher oil percentage. Okay,

thank you.

Your next question comes from the line of Oliver Huang with TPH. Please go ahead.

Good morning, Herb, Wade and team Strong Quarter and thanks for taking the questions.

Just had a couple of follow-ups. Starting in South Texas, I know you all highlight the new Briscoe Sea Wells performing well. Just wondering how did the initial results that you all seen thus far on that -foot-spaced fully bounded test impact your thinking about optimal spacing on future development in that liquids-rich area part of the play for you all? And then just kind of additionally on the Briscoe Sea Wells, notice that while you all typically drill wells going northwest to southeast, there's this one pad where the geometry of the wells are moving northeast to southwest. Any sort of observations or takeaways worth highlighting that came about from that set of wells?

Hey, Oliver, thanks for that question. That's actually an excellent question and very few people have noticed that. But let me start with the spacing. You know, we believe that we could get to that spacing and get good results with co-development and pretty much the results confirmed what we expected and there's quite a few wells there. We'll continue to track on that kind of spacing where it makes sense. And obviously the returns did not degrade like some people expected and it kind of was in line with how we modeled it in terms of the reservoir models. So that is something that we will continue where it makes sense and then EagleFord will be selective depending on where there's less EagleFord development currently. The off-azimuth wells that you noted are performing excellent. We were doing that to see if we could get costs down and lower the risks on some of the wells in terms of just because of the orientation there. And those have turned out excellent, better than we expected. You'll note that our first three wells over in the Chupadera area, that 8,000 net acre drill to urn area, we have drilled three off-azimuth wells over there also. So you'll be seeing the results from those also. So we see that as a way to really help capital efficiency with those off-azimuth wells.

Perfect. That's helpful, color. And just a quick follow-up on Permian LOE. Just kind of considering next year's preliminary outlook that you all had alongside BU Intadek back in June, anything that we should be aware of or thinking about that might be driving another leg down further to the low sixes on Permian LOE after the step down we saw this quarter?

Yeah, I don't know yet on 2025. We haven't worked up the plans on 2025. So if we get in areas where there's already power supply, then it's pretty straightforward to keep the LOE down. If we're near our existing water injectors, it's going to be lower cost than where we go to third party water. So it'll really depend on very specific things on where we're locating the wells in 2025. And I don't have that yet. The team's working that up right now. But just rest assured we're going to be really driving capital efficiency again. And we're in a good operating environment right now with the activity reductions in the industry for both rigs and frac spreads.

Okay, perfect. Thanks for the time.

You bet.

Again, if you would like to ask a question, press star followed by the number one on your telephone keypad. Your next question comes from the line of Nicholas Pope with Seaport Research Partners. Please go ahead.

Morning, everyone. Hope we could dig a little bit more into into South Texas because I mean, it was a it was a huge jump in oil production. And just kind of curious with this basket of wells that you saw come online during the quarter, I mean, I knew you have a lot of well control in South Texas. What is your ability to kind of maintain that oil percentage that we saw here in the second quarter? And, you know, in terms of how you're, I guess, selecting wells and what you're going to bring in online, I guess, how consistent can we can we expect these these kind of oil percentages going forward in South Texas?

Yeah, Nick, thanks to this, Herb again. So on South Texas, you know, we regularly optimize and we keep improving the performance in each area. When you look at oil percentage, that's going to depend a little bit on how much capital allocation is on the west side and how many new turning lines we have on the west side versus on the east side, which is, you know, higher BOE rates on the east side, but lower oil percentage. So you'll just see move around somewhat, but the more capital we put into the west side will wind up with a higher oil percentage, the more capital we put on the east side will wind up with a higher gas, higher NGL percentage, and that really drives it. But overall, if you just look at it, we just keep improving the well performance and we're really aware of where their high oil percentage and where their higher gas percentage and we're really just looking at the returns. We're not worried about percentage so much. We're driving the capital efficiency side of things. So that's really the way I'd sum that up.

Yeah, I appreciate it. The other thing, and I know there's like, you know, dig a little more that I think you'll probably want to, but in 2025, the production kind of broad range that you all gave during the XEL release, that 195, got a lot of pushback on that number. I'm just kind of curious as you kind of look at where things are now, what your current kind of implied guidance is with the added production and you went coming in, you added with this release, kind of how you're thinking about that, you know, the implied decline that you're seeing there in 2025 from that fourth quarter rate. And if there's anything, I guess maybe when we get to more clarity on kind of what you're expecting there for 2025.

Yeah, Nick, it's a real fair question. You know, when it's early days like this on a new acquisition, we're working up scenarios and really figuring out the capital efficiency that we can gain. We are somewhat limited in what we can see in terms of rig contracts and other contracts because we are in that HSR period. So the best we can see are redacted contracts. So we don't know the how the term of the contracts and what will make sense. So we are working that I will say we'll really be able to ramp up our certainty after HSR approval, assuming we get that at the end of August. And then we'll be baking that into our 2025 plans that we released in February. So we're just excited that all three assets have really similar returns. And we're just looking at how we can optimize that in terms of rig and track spread cadence. We know that we get better capital efficiency, we can get the right mix of rig and track spread in a given play.

And maximize free cash flow.

Yeah. And the objective is we will maximize free cash flow over the next two to three years, as we always do.

Got it. All right. That's all I had. I appreciate the time.

Thanks. That concludes our Q&A session. I will now turn the conference back over to Herb Vogel, President and Chief Executive Officer for closing remarks.

Okay. Thank you, Jeannie. And thank you all for joining us. I do have one area that we got some questions on that did not come up today. They're about the takeaway in the unit to basin for both oil and natural gas. And the question is really is it sufficient in terms of takeaway and can we grow production? And we believe that was a great question because there are perceptions about takeaway or complications related to rail that are actually quite outdated now. Until mid-2021, Waxie crude production was limited in the -a-day range for the industry and was all delivered to Salt Lake City refineries. The sharp rise since mid-2021 is due to growth and interest from Gulf Coast refineries in incorporating Waxie crude into their cruise slates, favorable oil prices and gains in production efficiency. And that's increased to include Cushing and Wyoming refineries. There are no rail constraints for current production or for expanding production. The railways are generally underutilized in the region because there's less coal being moved, as most of you know. While only a portion of the oil goes to Salt Lake City, there's a number of outlets by rail including Wyoming, Gulf Coast and Cushing. And the oil is in insulated cars, not heated cars. So in regards to gas, there have been constraints, but these are being alleviated. Pipeline expansion was completed last month by Mountain West, capable of moving an additional 80 million cubic feet a day. And Kinder Morgan recently announced that they're proceeding with a pipeline project to relieve constraints in the basin. Their pipe will carry up to 150 million cubic feet a day from the basin to a processing plant and will be in service in mid-2025. So with that, thank you for joining us and we look forward to seeing a number of you at upcoming events.

This does conclude today's call. You may now disconnect.