SM Energy Co (SM) 2020 Q4 法說會逐字稿

Ladies and gentlemen, thank you for standing by, and welcome to SM Energy's Q4 2020 Financial and Operating Results Question-and-Answer Session. (Operator Instructions) Please be advised that today's conference is being recorded. (Operator Instructions)

I'd now like to hand the conference over to your speaker today, Jennifer Samuels, Vice President, Investor Relations. Thank you. Please go ahead, Ms. Samuels.

Thank you, Julianne. Good morning, everyone, and thank you for joining us. I hope you're all warm and safe.

As always, allow me to quickly remind you that we may discuss forward-looking statements about our plans, expectations and assumptions regarding future performance. These statements involve risks that may cause our actual results to differ materially from the results expressed or implied in our forward-looking statements. Please refer to the cautionary information about forward-looking statements in the earnings release, the IR presentation and the Risk Factors section of our Form 10-K, which was filed this morning, all of which are posted to our website.

Our discussion today may include discussion of non-GAAP financial measures that we believe are useful in understanding and evaluating our performance. Reconciliation of those measures to most directly comparable GAAP measures and other information about these non-GAAP metrics are provided in our earnings release and IR presentation.

Here to answer your questions this morning, our President and CEO, Herb Vogel; and EVP and CFO, Wade Pursell. I will now turn it to Herb Vogel for some opening remarks. Herb?

Thank you, Jennifer. Good morning, and thank you for your interest in SM Energy.

Before opening up the call to your questions, I would like to say a few words to our Texas communities. With millions of Texans still without power, many without water and many homes that have not had heat for days, the SM Energy community is certainly affected by these storms. Our focus is on the health and safety of our employees and doing what we can in our local communities.

In South Texas, our regional gas processing plant was grateful Monday night that SM natural gas was moving and instrumental in keeping the plant open, enabling them to support power generation and keep many people's homes heated.

In terms of implications to our first quarter production, certain weather-related issues continue as we speak, and our team is responding with their best efforts. We will be assessing and quantifying the impact over the coming days.

Now let me turn it back to Julianne to open up for questions.

(Operator Instructions) Your first question will come from Scott Hanold from RBC Capital Markets.

Can I ask you about those 5 Austin Chalk wells that you talked about wellbore issues and some deferral? Can you give us a little bit of color and insight into what happened there? And has this happened before in either the Eagle Ford or the Austin Chalk before?

Yes. Scott, this is Herb. Yes, I'll get to that here. The -- it's a really localized issue. And just briefly, we just had 5 newly drilled Austin Chalk wells on 2 pads that were close to each other on the northwestern portion of our acreage that had not been completed yet. And on one pad, 3 wells just developed some casing issues in their vertical sections up above the Austin Chalk. So nothing related to the Austin Chalk reservoir at all. Fortunately, we've got service companies on it with us, and they've had success running a method to basically run in the pipe and side pipe to fix this sort of problem.

So what we did is in our planning, we just said, hey, worst case, we'd have to redrill 3 out of the 5 wells and possibly 5 out of the 5 wells, which is a total exposure of about $6 million to $10 million because it's about $2 million per well. So that -- we just thought it was important to bring up because that was the reason for the adjusted -- for the production CapEx in the fourth quarter.

So -- but nothing -- in terms of long term in terms of impact, really none. And then we've drilled through this interval, and with 600 wells -- we only had one problem before. So this is a local issue there.

Okay. When you say local issue, just to clarify, is it -- was it something to do with something that happened in, I guess, geology going down there? Or was it more of an operational issue, a service issue that was -- whether it was a mistake or whatnot. Was it more of that? Or was it more of something on the geology side?

No, it's a casing issue. And so -- and it's quite local. And we know we can run right through where the problem area is. We just have to make sure we have integrity through that section. Not...

Not geology.

That's not geology.

Not geology, got it. Okay, understood. And so my follow-up question then is, obviously, you're allocating more to the Austin Chalk next year. And can you give us a little bit of like high-level color in your thought there? Obviously, you get great returns in the Permian, and performance and costs continue to look pretty solid.

Do you -- is the move there really based on just the strong well performance and you think it's a good contribution? Or is part of it you just want to do a little bit more delineation and stay within your sort of budget range?

Well, Scott, first of all, these wells with what we can see are fully competitive with Permian with our co-developments there. And there is an element of wanting to demonstrate the Austin Chalk and how well it can do and what it can do for our inventory and our reserves. So there's a component of delineation in the 2021 program. There's a component of development in there also.

Your next question comes from Leo Mariani from KeyBanc.

I know this is probably a tough question to answer, but do you have any indications you could tell us about kind of downtime you're experiencing out in the Permian at this point in time? And just based on your prepared comments, I got the sense that there was no disruptions in the South Texas access. So just wanted to clarify that. And I guess just a final point related to that. On the guidance that you just came out with, does that already contemplate any significant first quarter '21 weather disruption in the full year '21 guide?

So Leo, let me start with the last question first. Yes, we have not baked any sort of weather-related impact into our estimates. And it's really deferral rather than -- it can be a first quarter impact, but then you'll wind up getting -- when we bring wells to flow back up. So the answer sort of really briefly is that roads are a problem, so you can't get sand trucks in. So our frac operations are shut down. Our rigs generally just shut down for a little while, but most of them are running now.

And then in terms of production, there are impacts where basically when there's no electricity, you have to shut down pumps and compressors. And that affects production. Certain production that doesn't rely on electricity can flow as long as everything downstream of them is up and running. Does that help, Leo, on that one?

Yes, that definitely helps. And again, maybe just the last part on South Texas. Was that totally unaffected in South Texas? Is this just a West Texas problem? Just trying to isolate that a little bit.

No, there's some problems in South Texas. The impacts don't seem as severe, but we're going to come back. We're going to look at everything once we're past this short-term bad weather event even though it's significant and see what the impact is. And then we'll be able to make an estimate. But when we shut these wells, and it's simply a deferral really.

Right. Okay. No, that's definitely helpful. And then just with respect to the CapEx plan for the year here, I certainly saw the numbers. It looks like your first quarter CapEx was kind of a little bit higher if we annualize that as kind of the full year budget. I just want to get a sense, is there a plan to kind of have CapEx more front half weighted in '21 as you kind of look at the activity plan? What can you kind of tell me on that?

Yes. Leo, the -- our original plan had front-end loading to the first half of the year somewhat. Not major, but yes, there was front-end loading. And now with frac spreads shut down, that obviously reduces our CapEx spending right now. And so we don't know exactly where we wind up until this event's over with.

Got it. No, that makes sense. All right. Just a quick follow-up on the South Texas asset, the question was sort of asked previously. And clearly, there's an element of delineation here in what you're doing. Do you look at this asset now as something you see is very much core to the company? Because I know a year or so ago, you guys were talking about potential divestment at some point, but obviously, the returns look very strong. So is kind of the divestment piece a little bit more off the table, and really, you see this as something that's kind of foundational, you can drill inventory on for years?

Yes. Leo, so the key thing is in late 2019, we really more or less uncracked the code a little bit in the Austin Chalk down there. So our perspective on the wells improved, and then we confirmed that with the wells that we drilled in 2020, and we found that they were fully competitive with the Permian.

So when I said we have a combination of delineation and development, we're really looking at development in areas where we know the returns could be very competitive with the Permian and then continue to delineate to expand the inventory. And that will determine the extent of the core nature of it. But in terms of returns, it's a great asset.

Your next question comes from Arun Jayaram from JPMorgan.

I wanted to see, Herb, if you could just give us some thoughts on how the 2022 plus -- how we should think about the 2022 plus plan on a long-term basis. Obviously, you've provided some thoughts on at least some charts around free cash flow, what happens to the balance sheet and reinvestment rates. But should we be thinking about the 2022 plan as one that is kind of designed to hold production flat? And I'm thinking about oil and BOEs.

Yes. Arun, what we thought was very clear was the quality of our assets is so strong, the returns are quite good, and you see that because our base production keeps outperforming. So when we look at it, we could keep production flat to single digit growing with less than 75% of a reinvestment rate. And I don't think people realize the quality of our assets, but now you're really starting to see it in our results with this transformation that's really taken place over the last 3 to 4 years.

Got it, got it. So longer term, reinvestment rate and flat to single-digit-type growth opportunities over the long term?

Exactly.

Got it, got it. One kind of housekeeping question is this year, 22 -- in South Texas, 21 completions, 39 wells drilled, so building some DUCs. In Midland, 72 completions, 55 wells drilled, so you're pulling down on some DUCs there. As we think about the 2022 mix, should we anticipate a little bit of a higher mix in South Texas? Or -- just trying to think about kind of a longer-term model.

Well, Arun, frankly, we run multiple scenarios, and we can change the capital allocation between the South Texas and Permian asset. In terms of the returns we get and the financials we get, we can get to pretty much the same level with everything panning out that way. And so we can mix it between the 2 and get to the same end results is kind of the bottom line. And so we have one scenario here that we're using for this plan. And the only variation will be somewhat in the oil percentage, one case to the other.

Your next question comes from Karl Blunden from Goldman Sachs.

Question really focuses on the balance sheet. Your bonds have had a very nice run from the middle of last year. As you think about what the optimal capital structure is going forward, I'd be interested in your thoughts, and maybe this is more for Wade, on the benefit of interest cost savings from adding second lien debt relative to the increased flexibility you have from issuing regular way, high-yield bonds. And then I guess one nuance to that is, is there an element there around your discussions with your bank lenders that would suggest one approach or another approach?

Karl, thanks. Wade. I think -- there's a lot of questions there. I think just in general, I would answer that. You should assume -- I mean I think one of the biggest comments I made in the remarks was that our long-term plan has us generating more free cash flow than the actual debt maturities are from here through 2024. So I think you should -- I think that's -- there's not much doubt in my mind that using that free cash flow to delever is great for the shareholders, great for the bondholders. And I think that should be your base assumption as we move forward.

Asking about second lien debt, certainly, no interest in looking at that and higher cost and even increasing debt at all. So delevering below 2x at the end of next year, approaching 1x end of 2025 and then -- and free cash flow paying down maturities from here through '24, I think, is the main idea.

Got you. Yes, certainly saw the comments on the cash being adequate to pay down the maturities through '24 in time before they mature. When you think about -- now you're coming into a period of cash generation, where does inventory acquisition or M&A sit on that on your priority list in terms of use of cash?

I'll make one comment on inventory then Herb can chime in. One of the exciting things to me is when we -- that we could lean forward and talk about these metrics over the next 5 years, knowing that there's no need to replenish inventory during that period because we have very high-return inventory that, as one of the slides shows, is well beyond that period. So certainly, during the years that we're talking about, no need to add inventory, but I'll let Herb talk strategically.

Yes. Karl, it's -- we work inventory on a day in, day out basis, and there's room for optimization. There are additional intervals, and we're real fortunate where we're located with the stacked pay. Who would have thought we'd be able to see the Austin Chalk that we see today just a few years ago, right? So there's going to be organic inventory growth in there. And then we continue to do acreage trades, that sort of thing to basically even improve the returns from there.

So that's really how we look at it. We are not forced to go do something because we do have quite a runway of inventory particularly with these only 75% reinvestment rates.

That's helpful. Certainly, when you look at the bond level, it's pricing in a whole lot of options that you have available to yourselves.

Your next question comes from Gail Nicholson from Stephens.

You guys made really good improvement on your DC&E cost in South Texas versus where you guys were previously modeling. Can you just talk about the drivers there?

So Gail, this is Herb. Yes, the drivers are really just across-the-board reductions from the cost of our rigs, the cost of services associated with the rigs, the sand costs are down, pumping services costs are down. That is key to this. And then that minute-by-minute efficiency gain, so basically less run time on each well by pumping more stages per day. But it's really a combination of sector deflation and efficiencies.

Great. And then you guys did some higher proppant loading in the Midland this quarter. Can you talk about what you saw there and also the fact that the higher proppant loading, you were even able to get your well cost below what you were previously anticipating with the higher proppant loading?

So Gail, on the proppant loading, what we did is we tested some higher proppant loading in the fourth quarter, but that wasn't a real material amount. And then based on our results and others' results with higher proppant loading, we increased the proppant loading assumption for 2021. And so we baked some additional cost in there. So we were running below $500 per lateral foot in the fourth quarter. And as you can see, we said $520 for 2021, and that does integrate that higher proppant loading.

Do you know what type of well uplift do you anticipate seeing with the higher proppant loading?

I'll show you once we've got a bunch of results to share with you.

Fair enough. And then just on the standpoint of with the significant amount of free cash generation you guys have upcoming from the '21 to '25 time frame, we talked about a kind of a lower hedge level really in the '22 forward outlook. Can you just talk about what is the appropriate target hedge level you guys would like to be in '22 forward?

That's a great question. I think we've said in the past, it is very tied to leverage. As we mentioned in the past, when we've been looking more at the 3x area, we've kind of done some math that has kind of driven us to a 75%, just a general number area of hedging as you go into a year. I think if you're thinking more and getting more confident that that's more like 2x area, then you're going to be thinking somewhere closer to 50% hedged as you approach a year.

Obviously, if the strip turns -- starts inverting and going up, that could change our thinking as far as trying to be opportunistic. But in general, we're just trying to manage the risk of the balance sheet. And if you think of something 2x, I think you think closer to 50% using round numbers. As we move forward and get below that, then the percentage starts to go down from there as well. So...

Your next question comes from Tom Hughes from Wells Fargo.

Congrats on the quarter. I wanted to see how you're thinking about development versus delineation results in the chalk, maybe if you could go into both spacing and productivity application.

Tom, so this is Herb. The way we've lined up that program, I think we show in the slide where we are drilling the Austin Chalk wells in '21, so -- or completing the 21 wells in '21. And we also show where the existing wells are. So that's really where you can see what looks more like development and what looks more like delineation when we're really stepping out. So we have a combination there, and that will be testing a number of different things with those different pad areas that we show on there.

Okay. And as a follow-up, the changes made versus preliminary guidance indicate you're probably better set up for 2022 from a prime production standpoint. So as you slow activity into 2022, is it fair to assume you'd begin to eat into the DUC backlog to better match the rig base?

So Tom, it's that year-end issue that always comes up. So we got wells, so -- that we're completing the wells in terms of CapEx during 2021. And then 2022 comes on and we turn a number of wells. I think it's about 10 wells on that we completed in '21 at the start of '22.

So it's real hard to lock down exactly what your DUC drawdowns will be year in, year out. Overall, we're pretty flat in '21. In 2022, overall, it will be the same sort of thing where we're either going to be flat or it will just depend what happens right near the end of the year or the start of the year.

(Operator Instructions) Your next question comes from Michael Scialla from Stifel.

Want to get a little detail on your 5-year plan or a sense of what would maybe cause you to deviate from that 5-year plan particularly in terms of prices. If you said you're going to hedge 50% of production from '22 and beyond, what kind of price range would cause you to do anything differently than what you've laid out there?

Well, Mike, I'd point you to the risk factors in the slide. So that's a really hard question to really pin down. We look at things, and we constantly relook at our 5-year and 10-year plan. And we say, okay, given the circumstances, there's things around gas relative to oil, where in NGL they're trading that can affect how you go ahead and develop and where you develop. But there's no general answer I can really give on that.

And Mike, on the hedging, just to be clear, when we say 50% is more of a target, that's 1 year at a time. We're not going out and hedging 50% of all of the commodity for the next 5 years right now, certainly not. That just informs our decisions as we move close to the year in time as we go forward.

And as you know, when prices move, if they move too far in the upward direction, eventually costs follow. So there's a lot of -- we like to stay as variable as we can there.

Understood. Want to see to -- you mentioned the difficulty you had with the Austin Chalk wells, the casing problem. When would you expect some more incremental data on any new Chalk wells that you'd be willing to share with investors?

Well, they'll be coming in throughout the year, those 21 completions. Those 21 do not include those 5 in the -- where -- the 3 that had the issue. So we'll be getting those through the year. Probably we'll wait a couple, 3 months after we got them online to really report on them. So you won't see anything until late in the second quarter probably. And then you'll -- then they'll be just be coming on relatively quickly after that.

Okay. And then just wanted to ask one more on the -- you mentioned the higher proppant loading in the Midland Basin. Are we experimenting with both the Wolfcamp and the Spraberry? And just looking at the state data for the Spraberry, it looks like your 2020 vintage was really doing better than prior wells, and -- I don't know. That's consistent with what you're seeing. I know the state data with Texas is always a little bit suspect. But want to see if that was the case and you -- was that a result of higher proppant loading there or something else?

Okay. Yes, that's a great question, Michael. It's -- that is not related to the proppant loading. That is detailed optimization of other completion factors, a little bit of spacing that all rolls into that. But yes, we do see improvement from 2017 to '18 to '19 to '20. And our teams are focused on that. So that's -- they're really motivated to keep the well performance going up even when we're co-developing practically all those areas.

This will conclude today's question-and-answer session. I would like to turn the call back over to Herb Vogel, President and CEO, for closing remarks.

Well, thank you for your interest in SM Energy. Any questions, you know you can always contact Jennifer Samuels at the numbers shown in the deck.

This concludes today's conference call. You may now disconnect.