SM Energy Co (SM) 2021 Q3 法說會逐字稿

Good day, and thank you for standing by. Welcome to the SM Energy's Q3 2021 Financial Results and Operating Results Q&A conference call. (Operator Instructions) And now I would like to hand the conference over to your first speaker today, Jennifer Samuels, Vice President, Investor Relations. Thank you. Please go ahead.

Thank you, Paul. Good morning, and thank you for joining us for our third quarter 2021 question-and-answers call. We had a fantastic quarter. To answer your questions today, we have our President and CEO, Herb Vogel; and CFO, Wade Pursell.

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 6 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, and refer to Slides 28 through 21 of the slide deck and Pages 14 to 17 of the 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. Of note, our third quarter 10-Q was filed this morning.

With that, I'll turn it back to the operator to take our first question. Paul?

(Operator Instructions) Your first question is from Leo Mariani with KeyBanc.

Just wanted to kind of ask a little bit about kind of the plan as we head into fourth quarter. Clearly, it looks like you guys are kind of slowing down on the activity side here in 4Q. Perhaps, maybe you could talk a little bit about sort of rig pace and translate that into kind of what's happening in the field or you have -- you're dropping some rigs or are you temporarily dropping some crews, maybe there's some frac holidays? Can you give us a little insight into how you're slowing down here in 4Q?

And then I guess just the other sort of related question there is, obviously, commodity prices are best they've been in a number of years. How do you think about that decision to kind of slow a bit as we head into the fourth quarter, given that the returns right now are so great and the payouts on these wells look great?

Leo, this is Herb. Yes, thanks for that question. So for the -- for the year, we accelerated into 2Q and 3Q, some of our activity, and we tested a number of things like simul fracking and other optimizations. So now we're putting together scenarios for 2022 and how we gear up and how we lay out that program for 2022. So that's really what's driving what we do 4Q, 1Q, 2Q. It's really about free cash flow over the next 2, 3 years and laying out that program that maximizes that. That's really what we're doing there. So looking at the rig count at any individual time is not really going to tell you much. What we want to do is have a very capital-efficient program. That's really what we're driven to do and that incorporates quite a few of those enhancements that we really tested this year during the year.

Okay. I appreciate it. I guess just wanted to ask about the Chalk. Certainly, some very strong well results certainly helped drive the great earnings here of late. Just wanted to get a sense of how you're thinking about what kind of phase of window to drill here in the Chalk. Obviously, you guys have got acreage that kind of ranges more on the oily side to the gassier side. Do you guys kind of have a preference? Are you thinking about drilling maybe some of the more gassy stuff, given that we have the highest gas prices we've had in a number of years here?

Yes, Leo. So we're really pleased with the way the Chalk has turned out. I mean the inventory potential here and how the wells have come in has been phenomenal. We've really just started doing development spacing as you've seen, and the results are coming out quite good. So we'll be laying that 2022 program out, and it will probably be a mix of locations across our acreage position. And -- but we haven't locked that in yet. So I would say it's not going to be just oil, it's not going to be just gas. It's going to be a blend of -- across our position.

Okay. That's good to hear. And just lastly, can you talk about well costs in the Chalk as you move into development mode? Are you starting to see money on those wells? Can you comment on that?

So on the Chalk, we really have continued to -- as we've learned over time, more and more improvements, that's really what's driven it. So we'll probably get some efficiency gains. We'll probably encounter a little bit of inflation. So we have not locked in a number for 2022 yet.

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

Great quarter, guys. I was wondering, and I know it's going to be too early to talk about 2022, but I know earlier this year, you did provide a reference for investors and analysts at a much lower deck. Can you give us an updated view on that reference point with respect to CapEx, given obviously a much higher commodity price and a little bit more inflation in?

And along with that, as you think about 2022, and I know the point is to maximize free cash flow, but given the outperformance that you all have seen with your better completion techniques in the Midland and just great results in the Austin Chalk, when you look at next year, would you taper CapEx at all given production outperformance? Or will you just let production into where it ends and just focus on like a well count that you think maximizes free cash flow?

Yes, Scott, you know how we do this, where we run a lot of scenarios at this time. And then as we get closer to locking the budget, then we optimize it to maximize the free cash flow for a certain period of time, 2 years plus. And that's really what drives it. So yes, we don't have a 2022 CapEx number or a production number yet. We've got scenarios. And we use strip pricing as we get closer to the date we lock in the budget. So I can't really give any additional color there other than we're going to incorporate what we learned this year in terms of Chalk performance, Permian performance and the benefit of the larger completion designs, and the capital efficiency from simul-frac, (inaudible) laterals, et cetera.

Understood it. But could you provide a reference relative to the earlier this year the 2022 CapEx number? And what that in theory looks like now based on the service cost inflation that's occurred or anything else that's occurred with efficiencies at this point?

Yes. So we have not locked it in inflation. We're kind of in data gathering mode right now, I call it, where we're sorting out, okay, which service lines would we expect to see inflation, and which service lines would we expect to see flat or decreases, and where can we see efficiency gains. And we're in that process right now. So I really -- I can't get ahead of the game there.

No, I appreciate that. And then my follow-up question is on shareholder returns. Obviously, you're hitting your leverage reduction targets a lot sooner than expected. And can you give us a framework of when we all should think about like SM having that conversation about shareholder returns in more detail and when it would actually start to be an actual payout to investors?

Yes, Scott, it's a great position to be in and I'll ask Wade to answer that one.

Scott, thanks for asking. Yes, we're obviously very excited to be delevering a little bit ahead of schedule. Frankly, we're below 2x already, which is fantastic. And it does relate to the quantum of debt also, though. While the debt to EBITDAX is falling quickly, we want that outright debt number to fall as well. So just from a framing standpoint, I mean I think that's your question. I mean for me getting leverage down kind of close to that 1x area and maybe absolute debt down in the $1 billion area is something to look forward. That feels like a prudent area to be considering something in a meaningful way from a dividend or stock buyback program standpoint. So I guess that's what I would tell you there.

And is the 1.0 leverage based on a mid-cycle price or would you use whatever it is, could you give us a little color on that?

See, that's a great question, right? I mean I think getting below 1.5x, if it's like at a mid-cycle price is probably an okay area to be considering. But the 1.0 is just to factor all of that in a little bit better. If we get there really quickly and at a price up around $80, I think that's 1 fact. If we're getting there, and we're able to see that everything appears very sustainable at reasonable mid-cycle prices, that's different. So all of those factor in to the decision at the appropriate time to consider something like that.

Your next question comes from the line of Michael Scialla with Stifel.

Maybe just another question on the cost side. You maintained that $520 per foot cost guidance for the Permian as an average for the year. Is that reflective of current wells? Or could you say where the current wells are relative to that average?

Yes, Michael, this is Herb. So the $520 number was our number for the year. And we front-end loaded all the CapEx. So really, the $520 is predominantly spent with the program we had. So it's a good number for the Permian. Looking forward, we're just going to see what parts of our inflation -- as I just answered, some of the sectors or service lines will see some inflation, some will be flat, and then we're going to get some efficiency gains. So we haven't set the numbers yet for 2022. And when we do, we'll see where it comes down relative to that $520.

Okay. Question on the Chalk. You gave a pretty wide range of spacing there for the development pilot. I guess, you'd call it a 675 to 1,000 foot. Are you seeing any performance difference between the well (inaudible) the range and can say if you're leaning towards 1 end or the other as you look to advance that play to full development?

Yes. Michael, it's (inaudible). So 3 of them are spaced at 675 feet and 3 of them are at 1,000 feet. And then we've previously done both (inaudible) at 1,000-plus foot and then those southern ones at about 1,250 feet of staggered (inaudible). So we're gathering data in multiple places, and we'll see (inaudible). Typically, you would -- you got to give us some time to see how they perform. But we're really happy with what we see and with the returns and the payouts on levels right now.

Okay. And then just maybe 1 last 1 for Wade. Wade, (inaudible) you mentioned you'd like to continue to reduce absolute debt. You did that, obviously, in the third quarter. As you look into '22, maybe thoughts about your ability to retire some additional debt there versus would you look to refinance the '24 and '25 maturities? Or are you more likely to just retire those with free cash flow?

Yes. I think, Michael, the point is certainly to generate free cash flow (inaudible) actually retire debt. So all of our -- I mean you know our -- how our maturity profile lays out, I think actually Slide 6 in the deck, does a pretty decent job of showing you kind of initial call dates. And there's a lot of flexibility within our debt structure, and we do that on purpose. Early callable debt at different prices, we always have (inaudible) anticipate the point where it is getting taken out first with free cash, and then we'll start as we generate cash and feel sustainable about it, we'll be targeting to '25 as we move through the year. And there's a couple of tranches there with the unsecured bonds, which are prepayable.

And also, of course, the second lien notes which become prepayable in the middle of the year, about 8 months from now. You can imagine, I think I've said it before, those will be kind of right in our sights. As they become prepayable, we'd like to eliminate those from the capital structure. So that's kind of the plan for next year.

Your next question comes from the line of Karl Blunden with Goldman Sachs.

Congrats on the deleveraging progress. Just to firm up some of the questions on the debt reduction. When you think about that like a $1 billion or more of debt to come out. Does M&A play a role in that? Could that slow the reduction or speed to reduction, when you think about selling assets or buying assets?

I'll make a very general comment and then let Herb comment. It -- the debt within the context of M&A is just 1 of many factors. So whether that became a deleveraging part of the process through M&A or acquisition, it would be 1 factor. What's exciting is we don't need any transactions to execute a very, very delevering process on our balance sheet. So do we look at other ways to accelerate those things? Yes. Is debt reduction a driver? It's 1 factor, I guess, is the way I would answer that.

Yes. And then, Karl, just generally on M&A, our stance hasn't changed at all. We think scale matters, but more than just a lower G&A story. And we've said these criteria are that we got to have comparable quality assets, and we have really high-quality assets, got to be accretive to free cash flow. And it's got to be neutral to beneficial to leverage. So that's pretty much the position we've taken. And then there should be some industrial logic around it and some capital efficiency if we were to do it. So that's really how we look at it. So it's not like we're going to go look for M&A to go delever as a single target (inaudible).

Got a line of sight to cash flow at this point. Just on the hedging strategy, you've seen a couple of other players in the space change the way they approach that. I know historically, you've indicated that as leverage comes down, hedging could decline a bit. Is there any bigger change contemplated as you go forward based on your oil price views, for example? Or is that kind of the continued approach?

Yes, great question. The short answer is no change. I mean we've been implementing the same strategy for over a decade, and it's served us very well, especially during downturns like last year. You said it well. We tie it directly to leverage. So that means during periods like this where our leverage is going down, our hedge percentage will go down as well, but the hedging doesn't go away. So we have been layering in methodically, smaller slivers, I would say, though. And we don't hedge too far out, and that's actually a good thing when the strips are so backward dated like they are currently.

So you won't see us hedge over 50% next year. And I think I mentioned in my notes, we're below 40% on a BOE basis right now for '22. The other thing that is a little unique that we do is during periods like this, we use a lot more collars, than we do swaps to retain more of the upside at these higher prices.

(Operator Instructions) Your next question comes the line of Gabe Daoud with Cowen.

Question, just going back to the cost equation in the Midland. You'd mentioned $520 a foot was the number all year, and then you also you talked about upsized completions. I was just curious, is there -- what's the delta between just the upsize completions and maybe the base completion design that you had coming into this year? Just trying to get a sense of how meaningful that delta could be.

Yes. Gabe, we actually set that at the beginning of the year when we set the budget. So we were running actually in fourth quarter below $500 and then we kind of looked at it and said with the old completion design, we'd be about $500 per foot and now -- and then we said, well, we're going to budget $520 with this upsized completion and those range from 2,300 pounds per foot up over 3,000. So it's an uptick from our 1,800 to 1,900 that we were at before. So that kind of tells you the number. It's about $20 incremental. Now as we go into 2022, we'll look at what the cost environment tells us it's going to be.

Okay. Got it. That's right. That's helpful. And then maybe if you could just give us an update on inventory in the Permian. I think maybe coming into this year, you had said there's maybe 8 years or 8 to 10 years left. Could you just give us an update on that number? And does that just assume the 3 primary zones there, the Wolfcamp A, B and Lower Spraberry?

So Gabe, you're -- where we do that look once a year, and it kind of starts with our research process, which is underway right now, and we update the inventory with all the different additional wells, we did with different intervals, and we see what the potential is in different intervals and what the returns are. So that's just a once-a-year process. And so basically, everything stands from what we showed in February. And then we update at the end of the year, and we'll share it in February again.

Your next question comes from the line of Arun Jayaram with JPMorgan.

I wanted to get a bit more detail on the new frac design that you initiated in the fall of last year. I was wondering if you could give us a sense of how the results have performed in Howard County versus maybe Sweetie Peck and how -- it looks like you have a few months of data and how do the (inaudible) trending relative to offset wells in each of those areas?

Yes, Arun, so we did start implementing this in 4Q, and we had some data from offset operators and others to get an idea of what these improvements could do, and we saw it as a very capital-efficient incremental capital spend. And as I just mentioned, going from $500 to $520 per foot. So we put it in 80 of our completions out of the 90 in the Permian year-to-date. And of those, 28 have been in place over 6 months, and we saw a clear, very discernible uptick in the performance through 6 months, but as you can guess, it's a wedge that opens up over time. So it's premature to say exactly what the ultimate benefit will be, but we definitely saw a clear trend.

And then in specific places like Coyote Valley on our Eastern position, we saw a significant uptick. And that's the 3 wells, the Miracle Max wells, that we showed in the slide deck. So we do see a benefit, but I would say we've got a bigger database than just those 28 wells that tells us it's the right thing to do and it's very economic to do so.

Great. And just my follow-up is SM has kind of been on the forefront of completing a lot of extended reach laterals, in the Midland Basin quite a few wells over 15K. And I think you did -- you talked about 1 over 20K. But as we started thinking about 2022 kind of capital efficiency, Herb, would you expect SM's ability to maybe drive lateral length? Could that be kind of a tailwind to your capital efficiency, as we start putting the math together on next year?

So the way I'd answer to that, Arun, is that our team, we do these scenarios. And so we really model and get to the plan that lays out the most free cash flow. So that's two 10,000-foot wells versus one 20,000-foot well. We would have done the analytics to determine, which was the better choice. So it's very thorough and detailed, I'd put it, in establishing what we're going to do on the lateral lengths. And so far, you've seen steady increases in the lateral length, and that depends on the cost environment and the production of the wells. So all I can tell you is that we are going to do what maximizes free cash flow in the design of the lateral lengths.

Nice results this quarter.

And that concludes the question and answer for today. I'll hand the conference back to Herb Vogel, President and CEO, for closing remarks.

Okay. Well, I just want to thank everybody for their interest in SM Energy. We're doing our best to maximize the value of the company, and we'll continue to do so. Thanks again.

Ladies and gentlemen, this concludes today's conference. You may now disconnect. Have a great day.