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Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
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]
I'd now turn 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 are President and CEO, Herb Vogel and a 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 as 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.
Thank you. [Operator Instructions]
Your first question will come from Scott Hanold from RBC Capital Markets. Please go ahead. Your line is open.
Thanks. Good morning.
Morning.
Can I ask you about those five 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 what -- has this happened before in either the Eagle Ford or the Austin Chalk before?
Scott, this is Herb. Yes, I'll get to that here. The -- it's a really localized issue and just briefly, we just had five newly drilled Austin Chalk wells on two pads that were close to each other on the northwestern portion of our acreage that had not been completed yet. And on one pad, three wells just developed some casing issues in their vertical sections up above the Austin Chalk, so nothing related to the AusChalk Reservoir at all.
Fortunately, we got service companies on it with us and they've had success running method to basically run in the pipe and type pipe to fix the sort of problem. So, what we did is in our planning, we just said, hey, worst case, we'd have to pre-drill three out of the five wells and possibly five out of five wells, which is a total exposure of about 6 million to 10 million, it comes about 2 million per well.
So that -- we just thought it was important to bring up because that was the reason for the justify -- 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, and we only had one problem before. So, this is a local issue there.
Okay. And 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? But was it more than 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 can run right through where the problem area is, we just have to make sure we have integrity through that section.
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 get great returns in the Permian and in 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.
Understood. Thanks.
Your next question comes from Leo Mariani from KeyBanc. Please go ahead, your line is open.
Hey, guys. I know this is probably a tough question to answer. But you have any indication if 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 the final point related to that on the guidance that you just came out with, does that already contemplate any significant first quarter 2021 weather disruptions in the full year 2021 guide?
So, Leo let me start with the last question first. Yes, we have not baked any sort of weather-related impacts 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 well back on. So, the answer shortly -- really briefly is roads are problems, 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. So, that helps Leo on that one?
Yes, that definitely helps. And again, it's the last part of South Texas, was that totally unaffected in South Texas, or is this just a West Texas problem, just trying to isolate that a little bit?
No, there's some problems with 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 is simply a deferral really.
Right. Okay. Well, 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 and kind of the full-year budget. Just wanted to get a sense, is there a plan to kind of have CapEx more on half weighted in 2021 as you can kind of look at the activity plan, what can tell me on that?
Yes, Leo, the original plan had front end loading to the first half of the year. So, not that 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 is over with.
Got it. No, that makes sense. Just a quick follow-up on the South Texas asset. The question was sort of asked previously, 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 were very strong. So, it's kind of a divestment piece more off the table and really we 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're really more or less uncracked the code a little bit in the Austin Chalk down there. So, our perspective on the wells are improved and then we confirm that with the wells that were drilled in 2020, and we found that they were fully competitive with 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'll determine the extent of the core nature of it. But in terms of returns, it's a great asset.
Okay. Thank you.
Your next question comes from Arun Jayaram from JPMorgan. Please go ahead, your line is open.
Yes. Good morning. 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 provided some thoughts on -- 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 always.
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 our bass 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 taking place over the last three to four years.
Got it. Got it. So, longer term, reinvestment rate and flat the single-digit type growth opportunities over the long-term?
Exactly.
Got it. Got it. One kind of, kind of housekeeping question is, this year -- 2022, in South Texas, 21 completions 39 wells drilled to building some DUCs. In Midland, in a 72, completions, 55 wells drilled, so you're pulling down on some DUCs, they are as we think about the 2022 mix, should we anticipate a little bit of a higher mix in South Texas, or just kind of think about, you know, kind of on 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 and 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 that between the two and get to the same end results is kind of the bottom-line.
And so, one scenario here that we're using for this, this plan, and the only variation will be someone in oil percentage, one case to the other.
Got it. Got it. Okay. All right. Thanks a lot Herb.
You bet.
Your next question comes from Carl [Indiscernible] from Goldman Sachs. Please go ahead, your line is open.
Hi, good morning. Thanks very much for the time. 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 weighed on the benefit of interest cost savings from adding secondly, debt relative to the increased flexibility you have from issuing regular way high yield bonds. And then I guess one you want to that is there? Is there an element there around your discussions with your bank lenders that would suggest one approach or another approach?
Hey Carl, it's 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 its 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, delivering below two times within the next year, approaching one time into 2025. And free cash flow, paying down maturities from here through 2024, I think, is the main idea.
Yes, certainly saw the comments on the cash being adequate to pay down the maturity to 2024 in time, before the cure, 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 I'll make one comment on inventory, then herb can chime in. One of the exciting things to me is when we is that we could lean forward and talk about these metrics over the next five-years, knowing that there's no need to replenish inventory during that period, because we have very high return inventory that that is one of the slideshows as well beyond that period.
So, certainly, during the years that we're talking about, no need to add inventory, but I'll let her talk strategically. Carl, 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 stack pay. Who'd 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. Thanks very much for the comments. And certainly when you look at the bond levels, it's pricing a whole lot of options that you have available to yourself. Thank you.
Your next question comes from Gail Nicholson from Stevens. Please go ahead, your line is open.
Good morning everybody. You guys made really good improvement on your DC&E costs in South Texas versus where you guys were previously modeling? Can you just talk about the drivers there?
So, Gail, this is Herb. The drivers are really just across the board reductions from the cost of our rigs, or cost of services associated with rigs, the sand costs are down, pumping services costs are down. That is key to this. And then that minute-by-minute efficiency again, so basically less runtime on each well, by pumping more stages per day, but it's really a combination of sector deflation and efficiencies.
Great. And then can you guys get some higher profit loading in the middle in this quarter? Can you talk about what you saw there, and also the fact that the higher profit loading even allowed even, you were even able to get your wall cost photo what you were previously anticipated with the higher profit loading.
So, I -- Gail on the profit loading, what we did is we tested some higher profit loading in fourth quarter, but that wasn't a real material amount. And then, based on our results and others results with high profit loading, we increased the profit loading assumption for 2021.
And so we paid some additional costs in there. So, we were running below $500 per lateral foot in the fourth quarter. And as you can see, we said I've 24 2021 and that does integrate that higher profit loading.
What type of well uplift you anticipate seeing with the higher profit 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 2021 to 2025 timeframe, you talked about a kind of a lower hedge level really in the 2024 for outlook. Can you just talk about what is the appropriate target hedges level you guys would like to be in 2022?
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 three times area, we've kind of done some math that is kind of driven to us 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 two times 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 two times, 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.
Great. Thank you.
You bet.
Your next question comes from Tom Hughes from Wells Fargo. Please go ahead, your line is open.
Yes. Thanks. And hey guys, congrats on the quarter. 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'd line up that program, I think we show on the slide where we are drilling the Austin Chalk wells in 2021. So, are completing the 21 wells in 2021 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 product production standpoint. So, as you slow activity into 2022, is it fair to assume you 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've got well, so the work 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 2021 at the start of 2022.
So, it's real hard to lock down exactly what your drawdowns will be year-in year-out. Overall, we're pretty flat in 2021. In 2022, overall, it'll be the same sort of thing where we're either going to be flat, or it'll just depend what happens right near the end of the year or the start of the year.
Okay. Thank you.
[Operator Instructions]
Your next question comes from Michael Scialla from Stifel. Please go ahead, your line is open.
Yes, good morning guys.
Good morning Michael.
I want to get a little detail on your five-year plan or a sense of what would maybe cause you to deviate from the five-year plan, particularly in terms of prices, if you said you're going to hedge 50% of production from 2022 and beyond? What kind of price range would cause you to do anything differently than what you've laid out there?
Well, Mike, at pointing to the risk factors in the slides, so that's a really hard question to really pin down. We look at things and we constantly relook at our five-year and 10-year plan. And we say okay, given the circumstances there's things around gas relative to oil, or NGL, they're trading that can affect the 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 edging, just to be clear, when we say 50% is more of a target, that that's a one year at a time that. We're not going out and hedging 50% of all of the commodity for the next five years right now, certainly not. This 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 cost 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 the with investors?
Well, they'll be coming in throughout the year, those 21 completions; those 21 do not include those five in the -- that were -- the three that had the issue. So, we'll be getting those through the year. But we'll wait a couple -- three 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 -- you mentioned the higher profit loading in the Midland Basin, are we experimenting with the both the Wolfcamp and Spraberry?
And just looking at the state data the Spraberry, it looks like your 2020 vintage was really doing better than prior wells. I don’t know that's consistent with what you're seeing in the state data with Texas, always a little bit suspect, but want to see if that was the case at you -- was that a result of higher profit loading there or something else?
Okay. Yes, that's a great question, Michael. That is not related to the profit loading. That is detailed optimization of other completion factors, a little bit of spacing that all rolled into that. But yes, we do see improvement from 2017 to 2018 to 2019 to 2020. And our teams are focused on that. So, that's -- they're really motivated to keep those -- the well performance going up even when we're co-developing practically all those areas.
Very good. Thank you.
Thank you.
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 number shown in the deck.
This concludes today's conference call. You may now disconnect.