SM Energy Co Q2 FY2023 Earnings Call

Good morning. My name is Rob, and I will be your conference operator today. At this time, I would like to welcome everyone to SM Energy's Second Quarter 2023 Financial and Operating Results Q&A. Jennifer Samuels, Vice President, Investor Relations and ESG Stewardship, you may begin your conference.

Thank you, Rob. Good morning, everyone. First off, I apologize for any inconvenience yesterday for the delay in posting all of the quarterly materials. Our third-party web host had technical issues. Reporting on the busiest day can overload the system. We may reference those materials today, including the investor presentation and call transcript during today's Q&A call. Thank you for joining us this morning. 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 describe 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. Also look for our second quarter 10-Q filed this morning. And with that, I will finally turn it over to Herb for a brief opening commentary. Herb?

Thank you, Jennifer. Good morning, and thank you for joining us. Before we get started, I wanted to reiterate a few key messages this quarter. Our return of capital program has been well received, with the repurchase of 2.6 million shares in the quarter and 5.3 million since the inception of the program last September. Including our sustainable dividend, we have returned $221 million to stockholders since September, or a 6% yield over 9 months based on the June 30 market cap. Execution was solid in the second quarter, building on a very solid first quarter. We're very pleased to have increased production guidance, reduced CapEx guidance, and geared up to add a rig in October that will help drive slightly higher oil growth in 2024. People who have followed us know that our ability to build inventory organically really differentiates SM. We've added 29,100 net acres this year to date in the Midland Basin, a 35% increase, and the team is excited about these latest 20,000 acres to target more Dean potential, which has been the producing interval in some of our best wells in the Midland Basin. This is the best way to add true value to an E&P company. The first half of 2023 puts SM on a trajectory for an excellent year. With that, I'll turn it back to Rob to start taking your questions. Rob?

And your first question comes from the line of Zach Parham from JPMorgan.

I guess, first off, just like cash return, you have returned a significant amount of free cash flow through buybacks over the last couple of quarters. In the second half of the year, your free cash flow is set to expand as production increases and CapEx declines. How should we be thinking about your buyback in the second half? Will you continue to utilize 70-plus percent of free cash flow to buy back stock? And maybe just talk about how the stock price plays into how you're thinking about the buyback?

This is Wade. Great question. Yes. All I can say there is $500 million authorized. We've now used $166 million of that, so $334 million to go. I did mention in the remarks that the current price looks very attractive to us. I probably shouldn't speculate any more than that. I think if I were you, I would just kind of model the remainder pretty pro rata for the rest of this year and into 2024.

And maybe just one on the new operating position, the 20,000 acres. Can you just talk a little bit more about your development plans on that new acreage? I know you've talked about developing the Dean there. But when will you start to initially drill some wells there? When should we expect to see some results?

Zach, this is Herb. I think we discussed this at the conference in June, but we're picking up a fourth rig in the Permian Basin in the fourth quarter. We're going to be first going into another part of RockStar and then moving over to the acreage as soon as we're ready. We should start drilling on that acreage late in the year, and then we'll continue on into 2024. We haven't budgeted how much of the year we'll be doing that. We'll be doing the normal efficient pad execution in terms of when we put the frac spread on there and how quickly we'll do it. We're lining out the plans now, and we're really excited about it. This is a sort of play where our best wells have been in the Dean. So we're really excited to see what we can do up here. We have a lot of confidence given the offset well data, both vertical and horizontal wells. So that's really the plan, no more than that.

And your next question comes from the line of Oliver Huang from TPH & Company.

Congrats on the strong quarter. Just wanted to follow up on the Martin, Dawson acquisition a little bit more. I know you all are very excited about the asset, having highlighted the Dean and Middle Spraberry sand intervals as key targets. Just any initial thoughts in terms of how you all are planning to develop the asset from a spacing perspective? Also, what’s the opportunity set to other zones within the area? And any color with respect to HBP commitments that you all might have to carry out, if any?

Yes. Oliver, so first of all, this is not your usual stack mudrock Permian play. In this area, we're really targeting much more conventional sands with a higher porosity and really oil-saturated rock, which underpins the prolific wells with the type curve characteristic that is a bit different than your normal plays. It's quite good from an economic standpoint. Right now, we're looking at optimizing the lateral length. As part of that, we'll be putting the spacing in that will optimize our economics. We use the same approach throughout where we really look at the incremental return for the last well assigned to a DSU. So that will basically be making sure that we achieve great economics on the wells. That's really the story there. And we'll be getting some well results there, probably in the first half of next year. We should get some well results from up there. But there's already been quite a bit of offset drilling too. Just to the southeast of it, we have our best wells ever in the Permian Basin that are in the Dean.

Okay. That's helpful color. Just for a second question, in South Texas, certainly great to see the positive ops update out of there. But just really trying to understand the oil handling project a little bit better. It sounds like it's completed at this point. Are we now at the point where volumes from the Austin Chalk can be flowed in the most optimal way? Or is there still some level of constraint? And how should we think about future investment on this front? Or does this all pretty much satisfy any sort of growth that we might see over the next couple of years?

Yes, Oliver, I'm just going to refer back to what we said about a year ago. We were expanding the pipeline to carry the oil out over a 3-year period progressively synced up with where we were developing. Last year, we did the first part. This year, we did the second part, and we finished that early in the second quarter. There will be a third extension of that pipeline next year. The constraints are relieved at this time. The only time that we would wind up with constraints is if we put a couple of really oily pads adjacent to each other that can flow quite strongly. It doesn't affect the wells at all. It just means it stretches out how long it takes to plateau longer. But we're doing that very efficiently, and we try and schedule things so that we mitigate that. We want to bring the wells on timely and efficiently, which drives it. So, the bottom line is, yes, the constraints are relieved. The constraints will continue to pop up if we don't manage things tightly, but we're planning to manage things tightly.

And your next question comes from the line of Tim Rezvan from KeyBanc Capital Markets.

I believe Oliver addressed what I was planning to ask. So, if I could shift to the Midland Basin asset, you mentioned having 9,100 net acres. I'm considering this in relation to the cash on your balance sheet and your choice not to redeem your callable notes at par right now. How significant is the opportunity you're pursuing? Are you close to assembling the acreage you wanted? Will you have the chance to share more information with the market soon?

Yes. Tim, I think we've mentioned this before at the JPMorgan Conference that we still see some opportunity to get additional acreage around that. On Slide 13, we showed 2023 newly acquired acreage. That's only the most recent 20,000 acres. We haven't disclosed where the 9,100 acres are that we'd like to expand. We haven't really given more color. We will at some point. Once we have some wells in there, we'll be sharing the results, but you won't be seeing those until mid-next year based on the way we're planning to go about things.

Yes. I'll just add to that on your balance sheet question, Tim. It's a good one. Carrying cash right now is pretty close to a no-brainer. Those '25 notes don't mature for a couple of years, and the coupon is reasonable. Our cash is earning pretty close to 5% now. So it's not a big negative carry to be more conservative and opportunistic. Having some cash and liquidity is always a good thing.

Okay. That makes sense. And then one more question, circling back on the Dean opportunity. Herb, I spoke to you in December, and you went into great detail on your view on how good and prolific the formation is. Do you believe there's more potential to add to Dean inventory? And I was hoping to pin you down a little more on spacing. Can we think about this traditionally as like a 4-wells-per-unit type development? Or just trying if you could give a little more context on what you see there because there's been some debate in the marketplace, and you seem firmly in the view that this is a distinct and highly prolific area.

Yes. Tim, I understand why people would have different views about it. It really doesn't work everywhere. You have to understand the geoscience and the nature of the sands, where they are and where they are oil-saturated, and where the porosity is strong that allows for high productivity. That takes quite a bit of detailed mapping. You can really start with the vertical wells, and it helps when there are offset horizontals to confirm your thought process. I would say it isn't for everyone and on everyone's acreage, but there are certain areas where it will work extremely well. That's what we've honed in on. We've mapped throughout the basin and said okay, here the Dean works, here the Dean would be wet, and here the Dean, the sands are too thin, here, the sands are really thick. We've mapped that through to identify the sweet spots that will give what I call top-tier returns, which is what we've had in our existing Northwest RockStar position, which underpinned our Dean performance.

Okay. That's helpful. So I guess we should think about this as an ongoing process to continue to find more inventory perspective for the Dean...

Yes. I would say we know where the inventory is, and then it's whether we can get access to the land or not.

Okay. Fair enough. And then if I could just sneak 1 last one in to close the loop on the oil handling question. So in theory, there could be some constraints next year if there are issues with the build-out. But that piece next year, would that handle your medium-term development in South Texas for many years once that final build is done next year?

Yes, that would do it, Tim. It's just the last southernmost extension of that line is all we'll have left. We'll make sure we get it in there before we bring the pads on. It's unlikely that we get pads on early. But if it does happen, that's always an issue. In this case, we're ahead of it.

Your next question comes from the line of Scott Hanold from RBC Capital Markets.

You all gave some pretty good color on how you think about buybacks. Maybe a little context for the dividend side of things. Do you feel comfortable with where it is? What do you think about the yield and where that might go going forward?

Scott, it's Wade. Good question. We established that dividend level last September, October. We'll be coming up on a year. I certainly can't predict anything at this point. But as we said, we'll reassess occasionally. You can assume we'd be doing that soon to decide whether we want to increase it or leave it where it is based on our view of the market, commodity, and free cash flow generation in the coming years, so stay tuned.

Yes. Can you give us some context on how you think about sizing that? Do you want it to be competitive with some peers in this mid-cap, with larger caps, with the S&P 500, a percent of cash flow? Any kind of view on how you think about sizing it?

That's hard to answer at this point. Whether we want to compare it too much with who we want to compare it to is a great question. What we really want to accomplish is a very sustainable dividend that shareholders can count on even in low commodity price environments. We'll do the same analysis again to determine what we think fits that bill.

Okay. Fair enough. Thinking about 2024, you gave a few breadcrumbs on how you're thinking with that mid-single-digit growth. Can you give some context around that? I think there was some context around the Permian getting a little more momentum going into next year. So if you can discuss how you think about capital allocation and any further cost savings tailwind that would have some implications for the budget?

I'll say a word about that, and then Herb can answer better. As far as capital allocation, we're going to be watching closely the next 3 months and determining what that free cash flow number is going to look like next year. Deflation is a big question, and it appears that costs will be lower next year. Commodity prices stabilizing here at a higher level, hopefully, will lead to some allocation decisions coming from that. But determining how much free cash flow we're going to have first is going to be a big thing for us in the coming months.

Yes. I'll just add. You've heard exactly right. We do see a mid-single-digit growth. We will be leaning a little bit more into the Midland Basin. We're just picking up the fourth rig in the fourth quarter, and we haven't identified how long we'll be running it through next year. That alone would allocate more to the Permian than we did this year and last year. Obviously, it's oily and the commodity environment is quite good for that. That's really what we're planning to do.

And there are no further questions at this time. Mr. Herb Vogel, I turn the call back over to you for some final closing remarks.

Okay. Well, thank you, Rob, and we are very pleased with our first half successes, and we're well-positioned to continue this trajectory to build value and deliver returns. Thank you all for your interest, and we look forward to seeing many of you at upcoming events.

This concludes today's conference call. Thank you for your participation. You may now disconnect.