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SM Energy (SM) Q4 2020 Earnings Call Transcript

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SM Energy (NYSE: SM)
Q4 2020 Earnings Call
Feb 18, 2021, 10:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:


Jennifer Samuels

Welcome to SM Energy's fourth-quarter and full-year 2020 results webcast. Before we get started on our prepared remarks, I will direct you to Slide 2 and remind you that we will be making forward-looking statements about our plans, expectations and assumptions regarding future performance, and our discussion of results will include non-GAAP financial measures that we believe are useful in evaluating our performance. We will be providing strategic objectives and guidance for 2021, as well as certain measures beyond 2021. 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 today's earnings release, the related presentation posted to our website and the Risk Factors section of our most recently filed Form 10-K and Form 10-Q. Non-GAAP measures discussed in conjunction with our results are reconciled to the most directly comparable GAAP measures. Reconciliations, as well as other information about non-GAAP measures are provided in our earnings release and the investor presentation referenced during this webcast. We will also reference forward-looking non-GAAP measures that we believe are useful to the investment community in understanding the long-term sustainability of our business, such as net debt to an adjusted EBITDAX and free cash flow.

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These metrics are not reconciled to the most directly comparable GAAP measure as projecting components of future earnings, the timing of changes in working capital and unknown events cannot be done with precision, which would have a significant effect on the accuracy of a reconciliation. Today's prepared remarks will be given by our president and CEO, Herb Vogel; and CFO, Wade Pursell. I will now turn the call over to Herb.

Herb Vogel -- President and Chief Executive Officer

Thank you, Jennifer. Good afternoon, and thanks for your interest in SM Energy. As customary with year-end reporting, we have a lot to cover here today. As we review the results and plan, I hope you'll see why we believe that we are a premier operator of top-tier assets.

I'll start with Slide 3 and the highlights of 2020. Our focus on free cash flow involved a companywide effort to reduce costs and increase efficiencies. Generating $240 million in free cash flow exceeded probably all estimates and is a testament to the SM team, achieving that during a very challenging 2020. Debt reduction of nearly $500 million was also a significant achievement.

Not only did we apply free cash flow funds to debt reduction, but the total reflects the outcome of the exchange offer launched in April, as well as market purchases of our bonds throughout the year, buying them back at a discount. Turning to Slide 4. Exceptional results in 2020 were supported by a number of factors. Capital efficiency tops the list with faster drill times, faster completions, rebidding and deflation across nearly all service lines and generally a focused effort to improve in all areas within our control.

Well performance was particularly strong with Midland Basin wells outperforming early year expectations and Austin Chalk delineation wells exceeding expectations. Compared with the original February 2020 plan, we reduced capital by nearly 30%, while delivering production in 2020 within the original guidance range. Year-end inventory and reserves, which I will speak to later, reflect the exceptional quality of our assets and the success of our delineation work in the Austin Chalk. With respect to ESG, we notably increased our disclosure, publishing both SASB and CDP/TCFD to our website, but more importantly, establish the oversight of a board ESG committee, a management ESG committee and put processes in place to collaborate and engage relevant functional areas to ensure ESG priorities are actionable throughout the organization.

Our safety metrics continue to improve and are outstanding, top quartile among our peers and notably not a single recordable incident in South Texas in 2020, and that includes employees and contractors. Midland Basin flaring was reduced 75% compared with the prior year, which is in part attributable to the construction of interconnections that enable gas production to be redirected in the event an individual third-party processor cannot receive it. Now turning to Slide 5. A better balance sheet is another successful outcome of 2020.

We both reduced debt and manage the maturity schedule. On top of the nearly $500 million overall debt reduction, we reduced near-term maturities through 2024 by more than $600 million and ended the year with nearly $1 billion in liquidity and reduced our leverage, net debt to adjusted EBITDAX from 2.8 to 2.3 times. I'll now turn the call to Wade to talk about our five-year outlook, 2021 guidance and cover 4Q results. Wade?

Wade Pursell -- Chief Financial Officer

Thank you, Herb, and good afternoon. I'm going to start on Slide 7. So despite the macro challenges, 2020 was an exciting time for the company as our multiyear portfolio transition to top-tier assets turns from high oil growth to free cash flow positive, setting the foundation for sustainable free cash flow going forward. As we put together our five-year plan, the core objectives were to set activity levels appropriate to optimize free cash flow over the plan period, which should enable us to reduce leverage significantly and move the company into a very sustainable reinvestment rate going forward.

This optimal plan involves a returning activity in 2021 after the severely contracted level in 2020. In addition to these financial objectives, we believe inventory depth and ESG stewardship are key components of our sustainable long-term plan. So now moving to Slide 8. Here we graphically present the five-year plan and the financial priorities, which are: first, to maximize free cash flow over this five-year period; second, continue strengthening the balance sheet by applying free cash flow to debt reduction, which targets less than two times leverage by the end of next year 2022 and close to one time leverage by the end of the five-year period; and third, achieve a consistent, sustainable reinvestment rate south of 75% in the years 2022 through 2025.

These priorities also deliver free cash flows that exceed all debt maturities due through 2024. Now on Slide 9. Specifics of the 2021 plan include delivering positive free cash flow, which we estimate will approach $100 million at current strip, capital expenditures of $650 million to $675 million consistent with preliminary discussion last fall. Again, this is a return to what we view as the optimal activity level for achieving those five-year plan objectives, mainly maximizing free cash flow generation and leverage reduction.

Total production of approximately 47 million to 50 million BOE or 129,000 to 137,000 BOE per day, with oil volumes at 52% to 53% of total production. I believe the other line items are self-explanatory and includes slightly higher LOE with increased oil in the production mix and decreased transportation due to the favorable change in terms for South Texas gas that go into effect in the second half of 2021, as well as lower South Texas gas production volumes. So regarding the current quarter, we are estimating capital of about $180 million. However, as of the time we're recording this call, the very frigid Texas weather and snow storm are causing extensive power outages, road closures, shut in facilities and other effects to normal operations.

Therefore, it's premature to provide first-quarter production guidance until we can assist and quantify the extent of the impact over the next few days. Slide 10 includes a little more detail on 2021 capital allocation, which we expect to be 90% DC&E and allocated roughly 70% to the Midland Basin. We've increased the allocation to South Texas Austin Chalk given the excellent results we're seeing to date. The plan includes drilling net 55 wells in Midland and 39 in South Texas and completing net 72 wells in Midland and 21 wells in South Texas.

So comparing that with preliminary guidance, our drill pace is now about 17% faster, which results in more wells drilled as we optimize efficiency under our drilling contracts, also compared with preliminary guidance, fewer completions are largely the result of timing differences. A few Midland Basin wells were accelerating in 2020. We entered into the South Texas JV and modified the timing of several 2021 completions to turn in line in early 2022. Looking beyond 2021, the chart to the right indicates a flattening in total capital going forward corresponding to a low growth, sustainable reinvestment rate.

Now turning to Slide 11 and hedging. Our hedge strategy is to protect downside risk and is correlated to our leverage. We go into 2021 with about 75% to 80% of oil hedged and about 85% of gas. Looking ahead to 2022, as leverage metrics have improved, assuming no significant macro change, in general, you could anticipate a lower targeted hedge level as we approach next year, especially considering the risk that continued upward price movements could ultimately result in rising costs.

Before I turn the call back to Herb, I'd like to make a couple of comments relating to the fourth-quarter results. It was a great way to end a very challenging 2020. The details in the release and slide deck, generally self-explanatory. We had a nice production beat versus guidance, the higher production, higher oil production was due to better performance from our base production in the Midland Basin.

We simply have not brought our models up to fully reflect improved base well performance there. At the same time, capital expenditures were well below expectations. Capital expenditures reflected further capital efficiencies in Midland, where DC&E costs averaged less than $500 a foot for the quarter. As noted last quarter, while we were seeing improved D&C costs, the fourth-quarter plan included testing significantly larger completions at certain Midland wells.

The larger proppant loadings were included in the less than $500 per lateral foot average for the quarter as we realized further cost efficiencies on completions. In addition, we deferred the completions of five Austin Chalk wells in South Texas due to casing problems identified in the vertical sections of certain wells. We're currently working to better understand and rectify the issues. Those wells were planned to turn in line in 2021, the plan now assumes those wells will turn in line in 2022.

So with that, I'll turn the call back to Herb to elaborate on the plan more specifically by region. Herb?

Herb Vogel -- President and Chief Executive Officer

Thank you, Wade. I'm now on Slide 13. The majority of our activity in 2021 is directed at the Midland Basin, where the drilling program has very robust economics with an average 10% IRR breakeven flat price of $16 to $31 per barrel. Costs are now expected to average $520 per lateral foot, and we expect to drill an average lateral length of around 11,300 feet.

We've increased our completion intensity this year, and that cost is reflected in this estimate. Turning to Slide 14, which shows our drilling and completion efficiencies. This is just such a great slide. Each year, I think it will be hard to beat our past performance, and yet we do it again and again.

We continue to get faster drilling and completing, thanks to the SM team, as well as our industry partners, both working the details together. Speaking of that, we have an outstanding drilling team, and they just set a new record. Just in the past month, they drilled and cased the longest lateral in Texas at about 20,900 feet or almost four miles, and did it in 20 days. That is almost 3,000 feet longer than the previous record also in Howard County.

As you all know well by now, longer lateral lengths translate to improved capital efficiency and returns. It shouldn't surprise you then that we have drilled 25 of the 50 longest laterals in the Midland Basin. Not mentioned in the slide, but in 2020, we also implemented dual fuel on some of our rigs partly for cost efficiency gains but also for emissions reduction. And we are now pumping an average of about 10 stages a day per frack spread in the Midland Basin with our primary pumping service provider.

Moving to Slide 15 in South Texas. Approximately 30% of our capital is allocated to South Texas in 2021, and it will primarily target the Austin Chalk. Projected well costs are down to $520 per lateral foot, with an average lateral length of around 12,000 feet. From our delineation program over the past couple of years, we believe that our Austin Chalk wells have competitive returns with co-development in the Midland Basin.

In 2021, we have designed a program that is partly delineation and partly development. The plan includes 21 South Texas net completions, of which 18 are Austin Chalk. Also in South Texas, we have been testing an electric frack fleet and during the second quarter, plan to increase the number of stage pumped fully electric. Slide 16 provides an update on the performance of our Austin Chalk wells to date.

Our newer wells target a better landing zone than some of our earlier wells. We have some older DUCs that landed in the original landing zone that will be completed this year, along with several new wells that are in the new landing zone. It is worth emphasizing that the economics of Austin Chalk wells are superior compared to legacy Eagle Ford wells. The Austin Chalk has substantially higher revenue per BOE due to the liquids content.

They also have a favorable cost structure, about 35% to 40% lower per BOE produced. We have added a slide in the appendix that compares new Austin shot cost per BOE with our historical Eagle Ford averages so that you can see the breakdown there. Slide 17 puts SM's Austin Chalk well performance into context versus the historical Austin chalk wells some of you may remember. Just for perspective, we also showed a comparison to the historical average Delaware Basin horizontal well performance.

On Slide 19, let's turn to year-end reserves. The waterfall here is generally self-explanatory but let me point out a few important takeaways. As you know, this year, SEC reserves were run at very low commodity prices, sub $40 oil and sub $2 gas. Because of the robust economics of our wells, the negative proved reserves impact of price revisions totaled only 33 million barrels equivalent, and this was predominantly from Eagle Ford gas wells.

Reserve revisions due to the SEC five-year rule are a result of scaling back activity in our five-year plan, corresponding to the lower reinvestment rate that Wade just talked about. These are absolutely economic wells but are now moved away from the proved category in our development plan. The wells underpinning these reserves that were moved are robust with an estimated average IRR of nearly 70% at $50 per barrel oil and $2.50 per Mcf gas. Scaled back activity over the five-year plan period provides for a longer duration inventory of high-quality wells.

You may wonder by how much we scaled back activity, for the planned period 2021 to 2025, we reduced the number of turn-in-lines by 29% compared to last year's plan. The reserve additions and performance revisions originate from the Midland Basin, the Austin Chalk and Eagle Ford. Turning now to Slide 20, regarding inventory. We have over 13 years of total company inventory and nine years in the Midland Basin.

It's important to highlight this inventory has an average IRR of more than 50% when run at a price deck of $50 per barrel and $2.50 per Mcf gas and current costs. This is very high-quality inventory and is not necessarily comparable to other companies' inventory reports, which may use higher price decks, lower return thresholds, shorter lateral lengths or include all contingent resources. We do have additional potential inventory on our existing acreage in the contingent resources category from potential additional intervals and/or spacing changes at various price points. And these are not reflected in the years of inventory I just talked about.

The chart on this slide reflects Enverus data published last week indicating about eight years of inventory at sub $40 and $2.25 gas, underscoring the quality of our inventory base. We include this to simply make the point about quality, meaning robust inventory even at that very low price deck, $40 and $2.25 gas. We put forth a few years ago that our objective was to be a premier operator of top-tier assets and I believe others can concur that we have solidly achieved that as we show in Slide 21. Before closing, I will reiterate the strategic priorities of our five-year plan, which are to: optimize free cash flow; reduce absolute debt and improve leverage metrics; achieve a sustainable reinvestment rate 2022 and beyond; and demonstrate measurable top-tier ESG stewardship.

With that, we look forward to our live Q&A call on Thursday.

Questions & Answers:


Operator

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.

Jennifer Samuels -- Wade Pursell

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?

Herb Vogel -- President and Chief Executive Officer

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

Thank you. [Operator instructions] Your first question will come from Scott Hanold from RBC Capital Markets. Please go ahead. Your line is open.

Scott Hanold -- RBC Capital Markets -- Analyst

Thanks. Good 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 has this happened before in either the Eagle Ford or the Austin Chalk before?

Herb Vogel -- President and Chief Executive Officer

Yeah. Scott, this is Herb. Yeah, I'll get to that here. 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 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 three out of the five wells and possibly five out of the five 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. 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.

Scott Hanold -- RBC Capital Markets -- Analyst

OK. 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?

Herb Vogel -- President and Chief Executive Officer

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.

Wade Pursell -- Wade Pursell

Not geology.

Herb Vogel -- President and Chief Executive Officer

That's not geology.

Scott Hanold -- RBC Capital Markets -- Analyst

Not geology, got it. OK, 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?

Herb Vogel -- President and Chief Executive Officer

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.

Scott Hanold -- RBC Capital Markets -- Analyst

Understood. Thanks.

Operator

Your next question comes from Leo Mariani from KeyBanc. Please go ahead. Your line is open.

Leo Mariani -- KeyBanc Capital Markets -- Analyst

Yeah. Hey, guys, 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?

Herb Vogel -- President and Chief Executive Officer

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 frack 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?

Leo Mariani -- KeyBanc Capital Markets -- Analyst

Yeah, 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.

Herb Vogel -- President and Chief Executive Officer

No, there's some problems in South Texas. The impacts don't seem as severe, but we are 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.

Leo Mariani -- KeyBanc Capital Markets -- Analyst

Right. OK. 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?

Herb Vogel -- President and Chief Executive Officer

Yeah, Leo, 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 frack 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.

Leo Mariani -- KeyBanc Capital Markets -- Analyst

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?

Herb Vogel -- President and Chief Executive Officer

Yeah. 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.

Leo Mariani -- KeyBanc Capital Markets -- Analyst

OK, thank you.

Operator

Your next question comes from Arun Jayaram from J.P. Morgan. Please go ahead. Your line is open.

Arun Jayaram -- J.P. Morgan -- Analyst

Yeah, 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'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.

Herb Vogel -- President and Chief Executive Officer

Yeah, 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 three to four years.

Arun Jayaram -- J.P. Morgan -- Analyst

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

Herb Vogel -- President and Chief Executive Officer

Exactly.

Arun Jayaram -- J.P. Morgan -- Analyst

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.

Herb Vogel -- President and Chief Executive Officer

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 two and get to the same end results is kind of the bottom line. And so we have one scenario here that we are using for this plan.

And the only variation will be somewhat in the oil percentage, one case to the other.

Arun Jayaram -- J.P. Morgan -- Analyst

Got it. OK, all right. Thanks a lot, Herb.

Herb Vogel -- President and Chief Executive Officer

You bet.

Operator

Your next question comes from Karl Blunden from Goldman Sachs. Please go ahead. Your line is open.

Karl Blunden -- Goldman Sachs -- Analyst

Hey, 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 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?

Wade Pursell -- Wade Pursell

Hey, Karl, 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 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 two times at the end of next year, approaching one time end of 2025 and then -- and free cash flow paying down maturities from here through '24, I think, is the main idea.

Karl Blunden -- Goldman Sachs -- Analyst

Gotcha. 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?

Wade Pursell -- Wade Pursell

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 five 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.

Herb Vogel -- President and Chief Executive Officer

Yeah, 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 are 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.

Karl Blunden -- Goldman Sachs -- Analyst

That's helpful. Thanks very much for the comments. Certainly, when you look at the bond level, it's pricing in a whole lot of options that you have available to yourselves. So thank you.

Operator

Your next question comes from Gail Nicholson from Stephens. Please go ahead. Your line is open.

Gail Nicholson -- Stephens Inc. -- Analyst

Good morning, everybody. 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?

Herb Vogel -- President and Chief Executive Officer

So Gail, this is Herb. Yeah, 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.

Gail Nicholson -- Stephens Inc. -- Analyst

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?

Herb Vogel -- President and Chief Executive Officer

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.

Gail Nicholson -- Stephens Inc. -- Analyst

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

Herb Vogel -- President and Chief Executive Officer

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

Gail Nicholson -- Stephens Inc. -- Analyst

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?

Wade Pursell -- Wade Pursell

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 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 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.

Gail Nicholson -- Stephens Inc. -- Analyst

Great. Thank you.

Wade Pursell -- Wade Pursell

You bet.

Operator

Your next question comes from Tom Hughes from Wells Fargo. Please go ahead. Your line is open.

Tom Hughes -- Wells Fargo Securities -- Analyst

Yeah, thanks. Hey, guys, 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.

Herb Vogel -- President and Chief Executive Officer

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.

Tom Hughes -- Wells Fargo Securities -- Analyst

OK, thanks. 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?

Herb Vogel -- President and Chief Executive Officer

So Tom, it's that year-end issue that always comes up. So we got wells, so -- that we are 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.

Tom Hughes -- Wells Fargo Securities -- Analyst

OK, thank you.

Operator

[Operator instructions] Your next question comes from Michael Scialla from Stifel. Please go ahead. Your line is open.

Mike Scialla -- Stifel Nicolaus

Hey, good morning, guys.

Herb Vogel -- President and Chief Executive Officer

Good morning, Mike.

Mike Scialla -- Stifel Nicolaus

Want to get a little detail on your five-year plan or a sense of what would maybe cause you to deviate from that five-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?

Herb Vogel -- President and Chief Executive Officer

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 five-year and 10-year plan. And we say, OK, 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.

Wade Pursell -- Wade Pursell

And Mike, on the hedging, just to be clear, when we say 50% is more of a target, that's one year at a time. We're not going out and hedging 50% of all of the commodity for the next five 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.

Mike Scialla -- Stifel Nicolaus

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?

Herb Vogel -- President and Chief Executive Officer

Well, they'll be coming in throughout the year, those 21 completions. Those 21 do not include those five in the -- where -- the three that had the issue. So we'll be getting those through the year. Probably 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.

Mike Scialla -- Stifel Nicolaus

OK. And then, just want 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?

Herb Vogel -- President and Chief Executive Officer

OK. Yeah, 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 are co-developing practically all those areas.

Mike Scialla -- Stifel Nicolaus

Very good. Thank you.

Herb Vogel -- President and Chief Executive Officer

Thank you.

Operator

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.

Herb Vogel -- President and Chief Executive Officer

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.

Operator

[Operator signoff]

Duration: 26 minutes

Call participants:

Jennifer Samuels -- Wade Pursell

Herb Vogel -- President and Chief Executive Officer

Wade Pursell -- Chief Financial Officer

Scott Hanold -- RBC Capital Markets -- Analyst

Leo Mariani -- KeyBanc Capital Markets -- Analyst

Arun Jayaram -- J.P. Morgan -- Analyst

Karl Blunden -- Goldman Sachs -- Analyst

Gail Nicholson -- Stephens Inc. -- Analyst

Tom Hughes -- Wells Fargo Securities -- Analyst

Mike Scialla -- Stifel Nicolaus

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