SM Energy Co (SM) 2022 Q3 法說會逐字稿

Good morning. My name is Emma, and I will be your conference operator today. At this time, I would like to welcome everyone to the SM Energy Third Quarter 2022 Financial and Operating Results Q&A. (Operator Instructions). Jennifer Samuels, Vice President of Investor Relations. You may begin.

Good morning, and thank you for joining us. To answer your questions today, we have our President and CEO, Herb Vogel, and CFO, Wade Pursell. As usual, before we get started, 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 and 10-Q, 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 third quarter 10-Q filed this morning.

And with that, I will turn it over to Herb for brief opening commentary.

Thank you, Jennifer. Good morning. Thank you for your interest in SM Energy and joining us this morning. We've reached a really exciting time for our business, and I would like to reiterate that we are very pleased to initiate our return of capital program ahead of expectations. Our initiation of share repurchases in September was earlier than expected, and our first increased fixed dividend gets paid next week. We designed our sustainable dividend program assuming $60 oil and $3 gas, which gives us upside flexibility in a stronger commodity price environment, including acceleration of buybacks.

With that, let me now turn it to Emma to open the line for questions. Emma?

(Operator Instructions). First question today comes from the line of Param Lynn with JPMorgan.

This is Zach Parham from JPMorgan. First, just wanted to ask on the oil cut, which moved a little lower in the 4Q guide. Can you just talk about the drivers of that oil cut moving lower and how you expect the oil cut to trip and as we move into 2023?

Yes. Zach, that's a question we hear quite a bit. And it's really just driven by how many completions come on in Midland versus how many completions come on in South Texas. We look at it longer term and the quarterly variations in that oil cut really don't make a difference. We just know it's ultimately going to be driven by the capital allocation between South Texas and Permian, but the returns are what they're important, and those returns are very comparable between the 2 areas.

Got it. And then just shifting over to cash return, particularly on the buyback. You did about $20 million in buybacks in September. Can you talk about the pace of that buyback going forward? And is that going to be systematic or purely opportunistic and utilized when you're not blacked out?

Yes, it's a great question. This is Wade. Yes, I would say it will be somewhat systematic and methodical but also very opportunistic. We'll certainly take harder looks on down days, I would say that. But it will be done over time, and we'll do some each quarter, and that's just the way we'll play it. We always have a view of NAV, and we certainly believe we're trading below that right now. That makes it easy.

Just one quick follow-up. Are you planning on putting in a 10b5-1 plan so that you can buy back stock consistently when you're in blackout periods?

We have not done that. And I would say right now, that's not the plan, but that could change, but currently not.

Your next question comes from the line of Timothy Rezvan with KeyBanc.

In your press release, you mentioned 3 high-performing wells that proved up the Western flank of Sweetie Peck. I was curious if you could provide some more details on the zones? Or what essentially you proved up and why you felt the need to call that out in the release.

Tim, great question. Yes, those 3 wells were 1-mile step-out to the west from our closest producers, and they were in 3 different zones, and we were quite pleased with the outcome of the wells. So that's why we called those out.

Okay. And do you have any information on the zones you tested? And how much acreage maybe that derisks freewill?

So the one is Middle Spraberry, one is Lower Spraberry and the other Wolfcamp A. And it just moves to prove the proved category an area that would have been in probable or possible previously. So it's more or less what we've been doing, which is, at the same time, we're concentrating on development in the core parts. We're also extending our boundaries, and that's a great example of doing that.

Okay. And my follow-up, I wanted to touch on a big topic in the Midland Basin on well degradation. A lot of operators are talking about it. You all seem to have been less impacted looking at your results over time. So I'm just curious what -- how you think you've sidestepped this issue and how you're thinking about that going forward.

Yes. Tim, that is an excellent question. So I think if you look in our deck, that's really the whole latter part of the deck is how much time we spend on modeling the fracs and the wells to get the well spacing tuned to each DSU driven by how much oil is in place in each zone, the vertical and horizontal interference. And that's where I think we really stand out with our ability with the proprietary tools we've developed. And we have that one slide where we show the cloud of all the potential completion designs and where we are compared to the competitors in the Midland Basin. So that's why we view ourselves as really having predictable wells for us. It's very easy to predict them. The performance is spot on always with what we expect on a per lateral foot basis and on a per well basis if we've got the lateral length fully delivered. So it's -- that's really what drives it.

Okay. And then if I could just follow up on that, your spacing assumptions over the last couple of years versus how you're thinking about the next 2 years? Are those consistent or have you made any up spacing changes?

We have basically lined out by DSU. And after all these years of tuning, there's less and less tuning going on each year. So I think we're pretty much right on. We have done really well with the Dean wells. Those have really outperformed. And so we modified some when we saw zones that performed particularly well. We've done some minor modifications. But in the entirety, it's pretty much the same.

Your next question comes from the line of Gabriel Daoud with Cowen and Company.

Gabe here. Thanks for all the prepared remarks last night. I was curious if we could maybe just get an update on some of the supply chain issues that were referenced in the pre-release about a month ago or a couple of weeks ago and then also the offset frac issue. I guess, how long do you think these issues could linger? And just given all the wells that were anticipated to come on and maybe push it to the right a bit, should we expect a pretty nice start to the year 2023?

Yes, great question. We put that early release out to cover the production differences from our expectations. And that was really about 60% from delays and turning wells in line and about 40% from offset activity. The supply chain difficulties really is where we're -- we've got a really finely tuned instrument out there, especially when we're simul fracking or even one we zipper fracking. And if the provider has to wait for parts, that slows us down. If there's slowdowns in trucking, whether that is spare parts or other materials required on the site, that can slow us down. And then for the service sector finding and keeping experienced folks, labor on the job, that's another challenge.

So those sorts of things with the activity at the highest level it's been in several years now. That's what's really driving that. In overall, the number of completions in the Midland Basin, we completed 14 but some came on later in the quarter than expected. And in South Texas, we could have brought online for fewer, and 2 of those are already online now, but 2 more are yet to come. So our base production looks great, but it's just a matter of what the uplift timing is. That's really the story on that one. On the offset activity, we -- it's funny actually that we've been out being conservative in our forecast, and it's funny that we -- 3 quarters in a row, we're acutely conservative, well, that offset activity was lower than we expected. And then this quarter, the offsite activity was higher, and that's -- than what we had baked into our estimates. So that will happen at times and not much really we can do about it.

Okay. Got it. That's great color and very helpful. Maybe now just on the buyback, maybe just curious what do you have to see to get comfortable with either accelerating it or even raising it. You noted it's on a pretty conservative price deck in calendar '23 TIs showing $84 or so. So like how is that to be sustained? Or is it something on the debt side? Obviously, you're pretty close to or about to exceed your targets. So maybe just help us think about upside to that program and what you guys need to see.

Sure. Great question. As you mentioned, we are right at our target on the leverage side of well below 1x and right around the $1 billion of net debt. And all I can say right now is that we'll move forward. We will deliver on our commitment to return the levels to the shareholders that we've talked about. And as you mentioned, we built that in pretty conservatively to make sure that would happen. So we used [6 and 3]. So as we move forward into finalizing our plans for '23 and looking at other opportunities we might have and seeing how stable the commodity prices end up being. That will just be part of the decision-making as we go -- as we move forward. I can't give you any metrics to watch for right now. But the more comfortable we get with the stability of the commodity and the free cash flow we're generating, there's obviously an opportunity and a possibility that we'll increase the levels on the return to the shareholder side, but too early to indicate any of that yet.

Your next question comes from the line of Oliver Huang of TPH&Co.

I just wanted to follow back up on the Q4 guide. Just I guess, compared to prior to initial expectations of having encountered the offset frac and supply chain issues in Q3, does that 60-40 mix that you just referenced for Q3 also hold for Q4? Or does it lean a bit heavier one way or the other?

Yes. Oliver, for 4Q, all we'd say is there's been delays in when we can turn some wells in line. Offset activity is something that's really hard to forecast. So what we did for 4Q was just more or less delayed the turn-in lines somewhat. And then for the opposite activity, if we just use our asset activity model where we know our own offset activity and then we know what offset operators will do. Sometimes they'll change their schedules. Sometimes we'll have a delay. But it's -- there's nothing specific that I would say, into on percentages of one versus the other all group together.

Okay. That makes sense. And for a second question, I know you all historically baked in some risk in for us that break down time, but just given the strong commodity prices, more players and activity in the basin. Just wondering if you all are expecting a more elevated impact relative to historical norms when thinking about 2023 just based on conversations that other operators have communicated with you in the planning phase for next year at this point in time.

Not really. It's something that it's -- every month, we'll get an update on things that sort of thing. So it's really hard to forecast exactly what the rig count will be in Howard County. That's one proxy just look at the rig count in Howard County, when it's way up. There's going to be more activity in the area. So South Texas is different because we've got quite a bit of -- it's only our own wells, really, very few places where we've got offset activity directly off us.

(Operator Instructions). Your next question comes from the line of Gregg Brody with Bank of America.

Just to follow up. In terms of the debt side, clearly, you're below your leverage target, and you've paid down your revolver. So still going to another $600 million or so to reduce in terms of debt from the bond side to try to get to your $1 billion target. Just talk to us about how you're planning on approaching that? Should we think about you just calling on the first maturities as they come due? Or are you thinking about it in a different way?

Yes. Thanks, Gregg. Good question. I would -- you know how we operate typically by maturity. So you can assume that when we're ready to reduce the absolute debt numbers to get down to that $1 billion. As you mentioned, we have a lot of cash right now. That's why we can say net debt is close to $1 billion. We would probably be the $25 million would be the first target, although we watch the trading levels and the others as well, but that's just generally speaking, how we would do that. We tapped the brakes a little bit on that just given the uncertainty with inflation and interest rates. It feels like a good time in this time of uncertainty and rising rates to have cash. So that's the way we're running things right now. As we move forward and build more cash, then that we'll make those decisions as we move forward. But that's the general thinking.

That's helpful. And then you had some comments in your precall, but I just wanted to clarify to make sure I understand that. So I think you -- when you were talking about inflation, you talked about how this year you modeled for '22, you average in 25% to 30%. And I think you said that you expected exit rate to be above that number. So implying 23 inflations higher than 25% to 30%. Did I understand that correctly? And just how does that translate potentially for your capital budget when we think about what you may have often from this year already? And maybe how you're approaching contracting? Are you thinking about having longer-duration contracts to try to address some of the inflation?

Yes. I'll respond to your comment on my prepared remarks, they let her at any color he wants, but you did hear it correctly, 25 30 and that we're seeing an exit rate out of 22 higher and we listed the things that are still going up. Too early to give any specifics on 23 in those areas, though.

Yes, the only thing I'll -- Gregg, the only thing I'll add on that is that we have not done the 2023 budget. We're watching things really closely. We've as much as we can to lock in the supply chain for next year. But there's no doubt there's inflation coming on, and we don't know when it will top out.

Are you considering smaller duration contracts now with some of your providers is to also address some of the supply chain issues that occurred this quarter?

Yes. It's a mix of the contracts themselves, getting the steel making sure we've got the feel that we can drill the well. That's a critical starting point. And then on the frac service providers, making sure we're set there. We're really going to stand supply. We're in great shape because we do lock that in a bit longer term. So we really work that hard as we add some it up.

Your next question comes from the line of Daniel John with Daniel Energy Partners.

I got a quick question on just the supply chain. If the industry activity stabilizes from here, do you think the industry sees these headaches eased in '23. But what happens in your view if we see another 5% to 10% activity across the board? How -- what's the duration of the headaches, if you will?

Yes, John, thanks for the question. You probably know better than anyone on what it looks like. There's areas that are quite tight. And if there was a hypothetical of increase in activity, those tight areas will obviously have more inflation. I think there's quite a bit of discipline on the E&P side and the service side -- but I'm not -- I think the thing is if you're going to forecast, forecast often, I don't think we're ready to forecast. We're going to make -- put a budget together with our expectations in November through January time frame, and we'll go with that, and then we'll see where things come. But we are focused on our relationships with those key suppliers and service providers and materials. So that's just what I'd say on that.

Fair enough. I've got a dumb guy question for you now. Where are we on the evolution of well-completion designs? Any big picture thoughts on that? Like how often are you testing new designs?

So John, I'm going to point you to one slide in our deck. I don't know if you've looked at it, but... You really just showed...

[My truck], sorry. I haven't had…

I'm going to point you to Slide 13, and you can see how we've moved our completion design to add value. And in some cases, it does take additional capital, but the performance, that incremental return for that additional capital is phenomenal. We're going to continue to do that. You're going to continue to see us get better and you're going to see our competitors moving towards our designs over time. I think we're right at the cutting edge on that, and it's a place we want to be.

This concludes today's Q&A. I now turn the call back to Herb Vogel, Vice President and CEO.

Thank you, Emma, and thank you all for your interest in SM Energy. Thank you.

That concludes today's call. Thank you for attending. You may now disconnect.