Good morning. Welcome to the Cabot Oil & Gas Corporation First Quarter 2021 Earnings Conference Call and Webcast. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star followed by the number one on your telephone keypad. If you would like to withdraw your question, press the pound key. I'd now like to turn the conference over to Dan Dinges, Chairman, President, and Chief Executive Officer. Please go ahead, sir.
Thank you, Angie, good morning. Thank you for joining us today for Cabot's First Quarter 2021 earnings call. As a reminder, on today's call, we will make forward-looking statements based on our current expectations. Additionally, some of our comments will reference non-GAAP financial measures. Forward-looking statements and other disclaimers as well as reconciliations to the most directly comparable GAAP financial measures were provided in yesterday's earnings release. Our results for the first quarter demonstrate Cabot's ability to deliver significant growth, profitability, and free cash flow in a more normalized natural gas price environment than what we experienced during 2020. Our adjusted net income and free cash flow increased by over 175% relative to the prior year period, driven in large part by a 34% increase in realized natural gas prices.
Our free cash flow of $138 million was our highest level since the first quarter of 2019 and represented Cabot's 17th quarter of positive free cash flow over the last 20 quarters, all while fully covering our quarterly base dividend and the repayment of $88 million of senior notes that matured during the quarter. While higher realized prices were the primary driver of our stronger financial metrics, we also delivered another exceptional quarter operationally with our production of 2.29 Bcf per day, exceeding the midpoint of our guidance range. Our CapEx coming in below expectations and our operating expenses per unit improving relative to the prior year period, despite higher G&A expenses related to a one-time charge associated with our recent early retirement program.
Our balance sheet remains as strong as it has ever been, with less than $900 million of net debt as of quarter end, resulting in a net leverage ratio of approximately one times trailing 12-month EBITDA. This leverage ratio is expected to further improve throughout the year due to an increasing cash flow profile resulting from a higher natural gas price environment this year compared to the 25-year NYMEX low we experienced in 2020. Our fortress balance sheet provides significant financial flexibility and will allow us to continue to return a significant amount of our free cash flow to shareholders this year and for years to come.
This uniquely differentiates us from so many in our industry today who are approaching the inflection of positive free cash flow generation, but will be forced to utilize that free cash flow for significant balance sheet repair in medium term as opposed to capital return to shareholders. On the topic of capital returns, yesterday we announced a 10% increase in our quarterly base dividend to $0.11 per share, which on an annualized basis represents a base dividend yield of 2.6%. As we highlighted on our year-end call, we are fully committed to a base plus supplemental dividend strategy, which incorporates a growing base dividend and an annual supplemental dividend to arrive at our minimum capital return target of at least 50% of our annual free cash flow.
Based on the current natural gas price outlook for this year, we expect to generate excessive free cash flow above our minimum capital return target and our debt repayment. This excess free cash flow is anticipated to be earmarked for additional capital returns, including opportunistic share repurchases, especially given the recent equity underperformance and/or incremental supplemental dividends as we have provided in the last few years. On the operations front, Cabot has implemented a focused stage-by-stage completion design along each newly drilled wellbore to maximize production and minimize potential impacts to adjacent parent wells. Based on an in-depth engineering and geologic analysis of each offset well, our team develops a customized segmented completion design for each new well lateral.
Design variables include the volume of fluid pumped, proppant concentration, cluster spacing, and the treating rate for each section along the wellbore. This concept was utilized on each of the four pads and 21 wells that were placed on production in the first quarter, with two to four different completion designs utilized in various sections of each lateral. Additional safeguards were also employed to protect the 33 parent wells, which partially or fully offset these 21 new wells. Safeguards included the use of deep set retrievable bridge plug, and the installation of tubing and capillary strings in parent wells when bringing them back online. A customized completion design, in conjunction with offset mitigation measures to protect parent wells, yielded very positive results. Collectively, our new wells on these four pads are meeting pre-drill expectations, while the offset group of parent wells are producing above pre-drill test rates.
We have seen very little impact to the parent wells, with only three of the 33 parent wells having a combined impact of only 2 million cubic feet per day. We're very pleased with these results. To remain on operations, Cabot has implemented another program enhancement operation. Cabot recently initiated a well pad compression program, which incorporates clean burn emission control systems. To date, we have installed compression on six of our pads. The pad compressors are to achieve a 10%-15% pressure reduction at each of our installations, resulting in increased production rates and an EUR uplift of 5 Bcf-15 Bcf per pad, all while delivering triple-digit rates of return and an average finding cost below $0.20 per Mcf for the incremental reserves. We currently have plans for five additional pad compression installations this year.
On the pricing front, we remain confident in our constructive outlook on natural gas pricing in both the short and midterm. While we anticipate some near term pressure on local basis differentials during shoulder months, and as pipeline maintenance programs kick in, we expect to experience a much more bullish summer of 2021 and winter of 2021-2022, than our outlook at this time last year. To begin, the global LNG supply and demand outlook this year is far more robust than what we experienced during the summer of 2020. U.S. LNG exports are currently averaging over 11 Bcf per day, an increase of 3 Bcf per day relative to the same period last year.
Additionally, exports to Mexico continue to improve and recently set a record of over 7 Bcf per day, an increase of approximately 2 Bcf per day year-over-year, resulting in strong tailwinds for natural gas demand as we move into the second half of the year. On the supply side, we continue to see capital discipline throughout most basins, including Appalachia, where production volumes are roughly flat year-over-year and about 2.5 Bcf per day lower than the peak levels from fall 2020. Despite higher natural gas prices, the rig count in Appalachia is down slightly relative to the same period last year, highlighting our belief that capital discipline across the basin remains intact.
More broadly, dry gas production across the Lower 48 remains about 1.5 Bcf per day below levels from the same period in 2020 and approximately 5 Bcf per day below pre-pandemic levels from late 2019. Currently, Lower 48 natural gas storage levels are 302 Bcf less than last year and 40 Bcf below the five-year average. More importantly, the Northeast and Midwest, two regions that materially affect Northeast pricing and summer demand, are collectively 162 Bcf below last year, and that deficit is expected to widen over the next couple of weeks. As we look towards the end of season in October, storage levels are forecast to be around 3.5 Tcf or approximately 400 Bcf below October 2020 levels, setting up a much stronger scenario for the winter of 2021-2022. The 2021 NYMEX futures currently sits around $0.80 higher than the 2020 level.
Though only a portion of Cabot is affected, a widening basis in the Northeast has created some near term headwinds for local prices. However, we are still expecting a material increase in our realized price year-over-year. This will result in a significant expansion of free cash flow and returns on and of capital. The recent widening is primarily due to a major pipeline replacement project scheduled for May on behalf of the Leidy South expansion project. However, we are optimistic that summer demand for LNG and storage will negate this project weakness in basis. Moreover, with the completion of the Leidy South expansion project, which includes 580 million cubic feet per day of new takeaway out of the basin, and this is scheduled for December 1 in service, our expectation is Northeast differentials should return to a more moderate level.
In yesterday's release, we reaffirmed our full year 2021 plan to deliver an average net production rate of 2.3 Bcf net per day from a capital program of $530 million- $540 million. We also provided a second quarter 2021 production guidance range of 2.225 Bcf - 2.227 Bcf per day. The second quarter production guidance implies a slight sequential decline relative to the first quarter, which is a result of lower activity levels and capital spending during the winter season. Activity levels are expected to increase in the second and third quarter, resulting in sequential growth during the second half of the year, primarily during the fourth quarter, in anticipation of higher natural gas prices in the winter and in service of the Leidy South expansion project.
While we all share the frustration regarding Cabot's recent underperformance, I firmly believe our expectations for outsized capital returns this year, which is underpinned by our disciplined capital program resulting in significant free cash flow expansion, will become more appreciated with time and continued execution. However, we remain fully committed to continuing our evaluation of all opportunities to further enhance shareholder value over time. With that, Angie, I'll be more than happy to open the floor up for questions.
Certainly. At this time, I would like to remind everyone, in order to ask a question, please press star one on your telephone keypad. We'll pause for just a moment to compile the Q&A roster. Your first question comes from the line of Joshua Silverstein with Wolfe Research. Your line is open.
Yeah, great. Thanks. Morning, guys. You guys probably know where I'm going with this, Dan, as it goes right to your last comment there. The stock has significantly underperformed peers and underperformed the commodity price. Why not get more aggressive now and look at doing some aggressive buybacks now or return to capital profile now ahead of what you just outlined as a bullish backdrop for natural gas prices? It seems like the stock really needs a spark to get it going outside of gas prices going higher. Just wanted to get some thoughts there as to what we've outlined recently for you guys.
Yeah. We don't disagree with Josh. The underperformance is a standout, and we're disappointed with those results. To your point, we are looking at what I discussed. We're looking at the buyback platform. We're also, in certainly our most recent board meeting we had this week, we've increased the dividend. It's obvious our balance sheet is in great shape. Along the lines that you're discussing, we are focusing on it, and we appreciate your comment and agree with your comment.
Would you guys be able to or would be willing to take on some leverage to go and do that now, knowing that you can hedge out the forward curve a bit and rebuild that cash flow back up?
Yeah. We've always been stewards of the balance sheet, and with as low as our leverage is today, we have ample capacity to do a number of things that would be, I think, constructive.
Got it. The other idea that we laid out was potentially using Cabot's premium multiple versus peers to go and make an acquisition, since you guys can probably buy an asset in the gas markets these days for 3x-4x EBITDA that are currently producing free cash flow. What would be your thoughts around that, and whether you would look outside the basin to go and do that?
Yeah. When you look at the M&A space, it had been active. Of course, pandemic put a lull on some of that from the standpoint of how trades might be able to make up with the significant volatility in the commodity price along with share prices. Every company has its own opinion about how they ought to trade and where they ought to trade. When you talk about the M&A space, you look at how you put together a transaction that can be a win-win transaction. It's not easy to find that point in time to be able to make it work. I can assure you that Cabot has not done anything. We've traded sideways while there's been significant volatility in our peers' stock from way below us to exceeding us in the, say, the last six months. It's been a stark contrast.
Once you've had support in the commodity price, you got out of the window of concern about over-leveraged companies and their outcome and their attention to their balance sheet. The beta plays and the torque in that investment by investors has carried the day, and it's been significant. Cabot with a clean balance sheet and free cash flow for 17 out of 20 quarters was yesterday. We recognize that there's opportunity out there in the market. We are conscious of it. We evaluate it. We are not sitting on our laurels. We had discussion in our board room. We had discussions in our board room this week about this topic. In fact, it was the majority of the conversation. We're fully aware of where we sit. We know the disappointment in Cabot's performance, share value performance. I happen to be a large shareholder also.
I'm hacked off about it, and I'm not going to sit on my laurels, and the team's not, and we plan on looking for that best avenue to enhance shareholder value.
Great. Thanks, Dan. Appreciate the comments there.
You bet.
Your next question comes from the line of Leo Mariani with KeyBanc. Your line is open.
Yeah, thank you. I was hoping that you could touch a little bit more on some of the issues with gas basis in Appalachia. It certainly sounded from your prepared comments that you're expecting to see some improvement as we get into the summer, but you also hinted that there could be a much larger improvement as we approach the Leidy South expansion start up in December here. Do you guys really think that Leidy South could be kind of a game changer and set up for just much better local pricing in December and into 2022? It seems as though maybe some of the basis issues here have kind of been what's caused some of the poorer stock price performance.
Leo, I agree with your sentiment on that, and I'll turn this over to Jeff in one second. We are excited about new takeaway capacity. Anytime you have greater than a half a Bcf a day, that's going to now be a new infrastructure to exit volumes directly out of the basin we sell a portion of our gas into. We think it is going to be constructive on differentials. We're very much looking forward to its positive effects. I'll turn it over to Jeff for comments also, Leo.
Great. Good morning, Leo. Yeah, Leidy South is a major project in the basin, and we're excited to get it in service. F or us, it's an incremental 250,000 a day out of the in-basin area . The 330,000 a day expansion piece comes from the west, and that's over in the more of the Tioga and Seneca area. The basis differential for May did get whacked a little bit because of the construction project that's required to build out that project. It's actually just a six-mile replacement pipe that Transco has to install this month, kind of a one-shot, and then that piece of the puzzle will be fixed. Overall, you got to keep in mind, too, that Cabot's exposure to local basis is really not as great as I think a lot of people believe.
In our investor guide that's out on the website today, you'll see a pie chart or at least a table that kind of highlights our distribution for our products. If you look closely at that, our volumes, there's over 50% of those volumes that's tied to NYMEX or fixed price. Then we have about 10% that's tied to power. That's roughly 70%. Then we have about 15% or so of our gas volumes that head out on the East Coast that get priced off of differentials and basis locations, not in-basin locations like that. Then you add our cash piece in, which is completely different than local basis for first-of-the-month sales of roughly 10%. You really whittle down our basis exposure in local basis exposure to roughly 15% or maybe 15%-18%, depending on the time of year. Yeah.
We're disappointed about the May differential blowout, if you will, due to a pipeline project that everyone knew was going to take place. That project also prohibits any gas going into the Leidy storage fields for the month of May. We want to have a pickup on gas sales for storage in June and the rest of the summer up there. With no supply increases and all the other factors that we mentioned, our expectations are a strong summer and a strong winter on pricing.
Okay. That's very good color for sure. I wanted to just move over to returns on capital for a second here. Obviously, it was really nice to see the bump in the base dividend here. Obviously, I think you have a plan to pay off another $100 million on the bond side come September. I just wanted to kind of see, as you guys think about these returns to shareholders, do you want to be in a position where we're a little bit closer to having everything ready to pay off these $100 million in bonds before you start to get a little bit more aggressive on some of these other return strategies, such as a larger supplemental dividend, or to maybe kind of start the buyback program?
Just additionally, can you just maybe remind us if there's a specific formula in terms of how you're going to pay the supplemental dividend by the end of the year here?
Yeah, Leo. Good questions. From our perspective, and looking at what we have out in front of us, and really just what Jeff was talking about, it's teed up very well for us moving forward into the rest of the year and into 2022. When you look at the expectations on free cash flow generation for Cabot, it's going to be a fairly robust number. You can look at our history. We have been, in the last few years, fairly generous on, and rightfully so, returning a large portion and much greater than 50% of our free cash flow back to shareholders. I'll let Scott talk about our program a little bit. We have our dividend and the variable piece, the supplemental.
We do expect that in light of the horizon and the picture we're painting, both from the demand, LNG, Mexico, the rationalization of capital allocated in the basin, we're going to expect favorable pricing. In looking at how we would manage the available cash, we're already talking about it. I think the shareholders should look forward to what we'll have out in front of us. I'll let Scott make a comment on that.
Yeah. Leo, as we see in this industry, there's lots of volatility. We do think it's teed up very positively. As Dan alluded to, we have been generous outside what that historically has been the buyback. The supplemental dividend. The plan from the formulaic perspective as you lay out or commented on, is designed that once we get through the third quarter call and we get into the fourth quarter, midway through the fourth quarter, and identify what that pricing is going to be. We'll know our pricing in early December. We'll have a pretty good idea on our revenue stream for the full year. We're not that complicated. That's why we targeted and telegraphed that December will be the time of the supplemental dividend payment, is because we'll have most of our ducks in a row.
Obviously, December won't be closed, but 11 of the 12 months will be closed, and we'll have pricing for the 12th month. That's kind of the timing and the thought process for that. In terms of the buybacks, and picking up on Josh's question also, again, we will be opportunistic as we were before. I think one thing is we've got the strongest balance sheet we've ever had. If the market were to move against us, it's not catastrophic for us because we're able to weather any storm that can be thrown at us. At the same time, we're going to be very methodical in our thought process around this return. I think if I was a betting man, I would make sure that. Well, not make sure. I would kind of lean towards the fact that you should probably expect something in excess of 50%.
50% is our minimum commitment, as we've said. When you look back at the history, as Dan alluded to, we've far exceeded that.
Okay. That's helpful color for sure, guys. W hat I was trying to get at is just above that 50%, obviously, you have the fixed dividend already in place here. I guess you're just going to toggle between whatever you guys want to do on the buyback versus variable dividend. Let's just make up some numbers. If you had $500 million of free cash flow this year and call it $170 committed to the dividend, that would leave $330 million or so or a little bit more, and management basically just decide how much they want to pay as variable and how much they want to use as buyback as the year progresses. Is that kind of the right formula?
You're saying the free cash flow is $500 million, right?
I'm just saying, roughly speaking, just in a random.
Yeah. If it's $500 million, again, our commitment is $250 million, and then above the $250 million is the $180 million of debt, leaving a wedge of about $100 million. Depending on market conditions, once we get to the $250 million already delivered, we will look at do we want to deliver more, or have we already bought in shares earlier in the year, taking the wedge above the $250 million.
Okay. Thank you.
Again, I'm not trying to be coy, Leo. We're trying to maintain flexibility. Again, in your example, if the stock was at $15, or let's say if the stock was at $12, we would lean more heavily on buybacks. If the stock was at $20, we probably wouldn't buy anything back, and it would all be delivered in the supplemental cash dividend bucket.
Okay. That's great color. Thank you.
Thanks, Leo.
Your next question comes from the line of Charles Meade with Johnson Rice. Your line is open.
Good morning, Dan, to you and everyone else there.
Hey, Charles.
Dan, I really appreciated all the comments you made in your prepared remarks about your new completion design and the success you had in mitigating those parent well effects. I have a two-part question. One, it seems like you've substantially or maybe completely solved that issue. The second part of it is there was one part that may be missing here. You have the impact's just down to 2 million cubic feet a day, but did it cost you anything on the completion side of those 21 wells, you having to change your completion design?
Yeah, that's a good question, Charles. What we've seen so far, no, it hasn't cost us anything on our CapEx on completion. The early results on our new wells have certainly met our expectation of what we would have anticipated seeing. On the 2 million a day on the parent wells, that is basically no effect. We would anticipate possibly that to clean up, and not be a rounding error as we move forward. Again, yes, we are excited and pleased. Some of the revisions that we had to look at this last year were a result of this phenomenon, i.e., parent-child. Every company in the industry is dealing with this.
At four pads and 21 wells, 33 offsets, we're getting a database now with the surgical completion we have that we think we are having a recipe that not only mitigates offset, but it also affected completions in the child well also. We don't think we're compromising our completion standard.
Got it. That's helpful detail, Dan. I had one other question just to see if I could maybe look ahead a bit at 2022 and the effects of your cadence in 2021. It looks like your 2021 capital spending plan is not going to be exactly the same, but it looks similar to your plan in 2020, in that the peak of spending comes in Q2, and the low for the year is in Q4. If you look at the effect that 2020 appeared to have on 2021, you decline sequentially in 1Q and 2Q based on that 2020 pattern. Is it a fair inference that that's what we're going to be looking at in 2022 based on the 2021 spending pattern, or is that too simplistic?
Well, one of the things that you need to take away, Charles, and I know you know this, you've followed Cabot for a long time, but I think it's worth repeating. Cabot is the lowest capital intensity company out there. Two rigs. We have three running right now, but we're going to lay one of those rigs down, as we've already messaged. We'll be between one and a half and two frac crews. Any time we are out there, and it takes so few wells and pads to be able to maintain our forecast levels of production. If we drill an eight-well pad, and that pad, whether it's for weather or for whatever reasons, if it's delayed, say 200 million a day is delayed for a week, and say that occurred at the very end of a quarter.
We report when we bring those wells on at the end of the quarter as new wells brought on, kind of like we did this quarter, bringing on 21 wells. If that eight-well pad comes on the last week of the quarter, it's reflected as a quarter completion, but eight wells coming on at the end of a quarter have, in essence, very little impact on production in that quarter. You're looking at a week delay on a 200 million a day pad is 1.4 BCF. To fine-tune it like that, it's not always easy for us to cover our cadence or to smooth out our cadence because we don't have 10 rigs running. We don't have five or six frac crews. We don't have that mix of pads where you can balance out a new pad coming on at various different times.
We're more lumpy just by the nature of being a very low capital intensity company. It's a good news that when we report and when we get granular on the cadence, it's kind of hard to use that metric with Cabot, just simply because just like we're going to see this year in the second quarter, third quarter, we're going to start bringing on a lot more stages than we had through the first quarter, and we're going to start ramping up. I understand where you're going with it, and I would love to be able to smooth it out, Charles, but that's some of what I deal with and the frustration I have on trying to report on a quarterly basis.
When I read the tie between the number of wells brought on and how inefficient or the lack of production tied to the number of wells brought on, I look up and say, "Well, maybe we need to put in there exactly when those wells came on in the month to be able to have a better tie.
Right. It's hard to know how much information is too much.
Yeah.
I appreciate your points, and they're well taken. Thank you, Dan.
Yeah. Thanks, Charles.
Your next question comes from the line of Arun Jayaram with JPMorgan Chase. Your line is open.
Good morning, Dan. Quick question. Is the updated messaging does include sequential production growth in the back half of the year, specifically in the fourth quarter as Leidy South enter service? I know it's early, but I'm just wondering about the potential production trajectory in 2022, and any thoughts on holding that higher 4Q exit rate flat, and thoughts on what kind of CapEx would that require to keep the 4Q flat?
Yeah. You're right. It is a little bit early for disclosing 2022. We're working on 2022 program. We take into consideration just like we do on our free cash flow management, how we're going to allocate and what we're going to do with that. The same holds true with our capital program for 2022. We're evaluating exactly how hot out of the box we might want to come and our design of our program, which would really answer that question, but it is early in the season to lay that out. I appreciate the question.
Okay. Just maybe a follow-up to Charles's question. I know you addressed this, but one of the questions that came in, Dan, 80 wells for this year, you TIL 21. Just one of the questions is, why did production in 2Q, why is it going down sequentially? It may be that timing answer that you just gave, but maybe a little bit more meat behind the bone there because we were thinking maybe it'll be a little bit more flatter in terms of sequential, just given the number of tied-in lines in 1Q.
Yeah, it's just again, the other element that needs to be focused on would be not only the timing, the number, but also keep in mind that we're not geographically in a perfect square sectional drilling. Our units set up there are various configurations by nature of Pennsylvania, and our lateral lengths, number of stages when you tie to well count is not as systematic as it would be. What I hope to be able to do in the upper Marcellus, which I think is going to be more systematic than the drilling that we now have in the lower Marcellus, where we drill 10,000-foot laterals, and we'll have consistent number of stages, and our clean map in the upper Marcellus, which will gain efficiencies for that project.
In the unit configurations and what we've drilled in the lower right now, as we come back through the field to fill in. The number of frac stages in each well is going to be more variable with our program right now until we get into the upper. That affects exactly the cadence and the type of pads that we bring on, along with the timing of those pads. I'm trying to answer the question on expectation and some of the variables that go into that expectations. To sum it up in a different way, we're not concerned about what we're seeing on results of our wells.
In fact, we're more pleased with what we're seeing now on the offset impacts that had affected what we had seen in the rearview mirror a little bit in 2020, latter part of 2019 and 2020, when we had more of an impact on the parent wells and being able to unload those parent wells and some of the impacts we had with frac hits on those parent wells in the latter part of 2019 and latter part of 2020. That did affect our forecasting and how we would look at the measurement of results and the tieback to the number of wells we brought on. Moving forward, assuming our results stay consistent as we have with our surgical completions, we don't expect now to have that impact as we bring on completions from the child wells.
We do expect now to get the more immediate impact and uplift, and similar production return to the parent wells after our completion of the child. We're hoping that we are mitigating that concern.
Great. Thanks a lot, Dan.
Thank you.
Your next question comes from the line of Umang Choudhary with Goldman Sachs. Your line is open.
Hi, good morning, and thank you for taking my questions.
Good morning.
Appreciate the comments around differentials improving with the startup of Leidy South later in the year. Wanted to get your latest thoughts around local demand and takeaway, more medium to long term, and any projects which you're working on right now to stimulate that or capture that demand for Cabot.
Yeah. I think Jeff is the perfect one to answer this question.
Yes, good morning. The Leidy South Project, it takes our production down from Northeast P.A. into the Washington, D.C. area, down to a location called River Road. It's very important that that's a central location going both north and south, depending on the season for gas demand. Enhancing our takeaway from Susquehanna County to that area, magnitude of 250,000 a day is a great project for us. However, I'll also say there are several projects in the works. I know you're familiar with PennEast and the recent news regarding it and their Supreme Court case on eminent domain. I'm sure you're aware that Transco also announced Regional Energy Access, which is close to 1 Bcf a day of pipeline that's basically a brownfield project through existing right of ways.
That project is also going to be connected to Cabot's supply area in several different spots. We're excited for that project, and actually PennEast as well to come in service over the next couple of years.
Great. Thank you so much.
Thank you.
Our final question comes from the line of David Deckelbaum with Cowen. Your line is open.
Morning, Dan, Scott. Thanks for squeezing me in this morning.
Yeah.
Dan, you gave some really good information around the surgical completions and how they came in better than expected, and you talked about if you can replicate those results moving forward, it mitigates a lot of the concerns that you would have had, at least the current shot. Before you said there's no incremental cost. I have two questions. One would be, is there an incremental cost that's just being offset by the location we're replacing these wells and sort of the amortization of previous costs on existing pads? Two, as you go forward, if you are able to replicate these results, does it change how you think about your maintenance program going forward? It would be something where we would see improvements in your capital efficiency metrics?
There's a couple of things. I'll answer the second question first, and then I'm going to have you repeat the first question, David. You were breaking up on me a little bit. We feel good about what we've seen and our expectation about replication. The four pads, 21 wells. Again, when we steer our wells on the child drilling, we know exactly what our landing points are, and we're trying to mitigate the impacts also with picking our landing zones on the parent wells. As I've already indicated, the variables we're using on the completion. We do anticipate positive results. We think that is going to certainly be a metric that will enhance our program simply by not having the impact that we saw in the latter part of 2019 and some of our wells on 2020.
We saw not only was it difficult to bring some of those wells back on, we took revisions on some of those wells. Keep in mind, some of those wells that we took revisions on, we think certainly have the ability to come back on. It's just when we see it, we report it as we see it. We do, and have seen some of the wells continue to improve back from the frack impact that we received. We're optimistic going forward. We do think that if we look back and look at that as a negative surprise in 2020, we hope we've mitigated that in 2021 reporting results. David, I'm going to have to ask you for repeating the first question.
Thanks, Dan. Happy to. I'm sorry for the noise. The first question was just, you talked earlier that the surgical completions don't add any incremental cost. I n isolation, are they adding cost that's just being offset by savings of existing pads or existing infrastructure that's in place?
Let me make sure I understand the question. For one, the completion design is not adding any incremental cost to what we would have done if we would have completed the entire lateral in a similar fashion.
Okay. That effectively answers it, yeah.
Yeah. In fact, I would have to get Phillip Stalnaker to answer the question more directly. You might have incremental savings, if you would, if you have maybe less fluid or less proppant in a particular frack. I don't think it'd be consequential enough on the savings side to try to dissect it.
I appreciate that. Thanks, Dan.
Yeah.
If I could just lob in one quickly to Scott. Maybe it's not quick. Scott, you mentioned earlier the stance of buybacks. I know that it was more explicit as it relates to the incremental 50% of excess free cash of buying back more shares and weighting that more heavily at 15 versus distributing more cash at 20. One, I just want to understand, as you think about that's really a 2021 reality with the free cash that's coming forward. Along those lines, you guys are approaching zero net debt. You have the bullet payments that come in this year. Revolver is pretty clean here. There's a lot of capacity there. Do you have a goal of being at zero times, or might you lean on that capacity a bit more to stabilize shares?
Yeah, I'll make a quick comment, turn it to Scott. What you're talking about, David, is and what a clean balance sheet does for us, it gives us all the optionalities that you've just defined. That we do have flexibility. I can assure you in this environment that we're not going to a zero net debt position. We have flexibility. I know Scott talks about it. Scott and Matt visit about what capacity we have, how we might utilize that to enhance shareholder value, and we're going to continue to do that. We're not so conservative. I'm not so conservative to where we're going to try to get to net debt and not utilize the opportunity with this available cash to enhance shareholder value. I'll turn that to Scott.
There's nothing to add. There's really not. At the end of the day, David, again, there's no intent to be zero debt. Even net debt. The plan, we have nothing maturing next year. We have a $62 million tranche in 2023. You probably hit 6% money, you probably pay that off. Again, if the cash flow profile stays. For the remaining $800 million, we'll look to refinance those. Biggest tranche is in 2024, there's another tranche in 2026. There would be $800 to $1 billion of permanent financing, in a status quo case, in the balance sheet. As Dan said, we have lots of flexibility. Again, we're very judicious with shareholder money. We like to tell you after the fact, after we've done it.
We don't like to get over our skis and make promises that if the conditions change, and it doesn't make sense that we'll put in a defensive posture. I don't mean to say trust us, but I think we have a good track record of returning and being very disciplined. Quite honestly, the buyback program of old, I think Matt and I had this debate, I think every share I've bought or instructed him to buy back has been bought at a higher price than we've recently been at. That kind of hits the little bit of the pause button going, okay, where does this settle in at? Because we are in a different dynamic.
In terms of your initial question, we had shareholders a year ago, again, in the thick of COVID, saying, "We want all E&P companies to be zero debt." That's not our path. I think the market has quickly reverted as people were able to extend out their maturities, repay debt, as Dan said in his script. We're on different footing as an industry, even with the ESG focus than we were and have been in a very long period of time. The discipline and everybody's focus on being judicious in their capital programs just makes for a better industry and better companies across the board, not just capital.
Well, looking forward to seeing how wild you guys get. Thank you. Appreciate it.
Thank you, David.
This concludes our question-and-answer session. I would now like to turn the conference back over to Dan Dinges for closing remarks.
Thank you, Angie. Great questions. I appreciate investors' patience. Again, I've mentioned I'm a shareholder. My frustration is equally as high as maybe some of yours. I can assure you that my optimism going into the season we're going into and the setup that we have out in front of us is significantly better than it has been. I'm optimistic that we're going to be able to start enhancing shareholder value. Thanks again, and thank you for the questions. Look forward to the next visit.
This concludes today's conference call. You may now disconnect.