Coterra Energy Inc

NYSE:CTRA

Earnings Call Transcript 2021-Q1

[Operator]

Good morning and welcome to the Cabot Oil & Gas Corporation First Quarter 2021 Earnings Conference Call and Webcast. [Operator Instructions] I'd now like to turn the call over to Dan Dinges, Chairman President and Chief Executive Officer. Please go ahead, sir.

[Dan Dinges, executive]

Thank you, Andrea, and good morning. Thank you for joining us today for Cabot's first quarter of 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 earning release.

Our results for the first quarter demonstrate Cabot's ability to deliver significant growth and 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 with 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 onetime charge associated with our recent early retirement program.

Our balance sheet remains as strong it has ever been, with less than $900 million of net debt as of quarter end, resulting in a net leverage ratio of approximately 1x 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 pump, profit concentration, cluster spacing and the treating rate for each section along the wellbore. This concept was utilized on each of the 4 pads and 21 wells that were placed on production in the first quarter with 2 to 4 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. Our customized completion design in conjunction with offset mitigation measures to protect parent wells yielded very positive results.

Collectively, our new wells on these 4 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 3 of the 33 parent wells having a combined impact of only 2 million cubic foot per day. We are 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 6 of our pads. The pad compression -- compressors are to achieve a 10% to 15% pressure reduction at each of our installations, resulting in increased production rates and an EUR uplift of 5 to 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 5 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 the shoulder months. And as pipeline maintenance programs kick in, we expect to experience a much more bullish summer of 2021 and winter of 2021/'22 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 continued 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 half -- roughly flat year-over-year and about 2.5 Bcf per day lower than the peak levels from fall of 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 5-year average. More importantly, the Northeast and Midwest, 2 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 the Cabot gas 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 above capital. The recent widening was 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 foot 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 to $540 million. We also provided a second quarter 2021 production guidance range of 2.225 to 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.

And with that, Angie, I'll be more than happy to open the floor up for questions.

[Operator]

[Operator Instructions] Your first question comes from the line of Josh Silverstein with Wolfe Research.

[Joshua Silverstein, analyst]

You guys probably know where I'm going with this, but Dan, 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 need a spark to get it going outside of gas prices going higher. So just wanted to get some thoughts there as to what we've outlined recently for you guys.

[Dan Dinges, executive]

Yes. We don't disagree with you, 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 our -- 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. So along the lines that you're discussing, we are focusing on it, and we appreciate your comment and agree with your comment.

[Joshua Silverstein, analyst]

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.

[Dan Dinges, executive]

Yes, 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.

[Joshua Silverstein, analyst]

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 assets in the gas markets these days for 3 to 4x EBITDA that are currently producing free cash flow.

What would be your thoughts around that? Or whether you might want to -- and whether you would look outside the basin to go and do that?

[Dan Dinges, executive]

Yes. When you look at the M&A space, and it's been active, of course, the pandemic put a lull on some of that from the standpoint of how trades might be able to make up with a 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. So when you talk about the M&A space and 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 in our -- 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 6 months. And it's been a stark contrast once you had support in the commodity price, you got out of the window of concern about overleveraged 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 cash flow for 17 out of 20 quarters, was -- that was yesterday. And 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 have discussion in our boardroom. We had discussions in our boardroom this week about this topic. In fact, it was the majority of the conversation.

So we're fully aware of kind 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 be sitting on my laurels, and the team's not. And we plan on looking for that best avenue to enhance shareholder value.

[Operator]

Your next question comes from the line of Leo Mariani with KeyBanc.

[Leo Mariani, analyst]

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 were 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 can be kind of a game changer and set up for just much better local pricing in December and into 2022? You obviously talked a lot about stock performance, but it seems as though maybe some of the basis issues here have kind of been what's caused some of the poor stock price performance.

[Dan Dinges, executive]

Yes, Leo. I agree with you, your sentiment on that. And I'll turn this over to Jeff in one second, but we are excited about new takeaway capacity. Anytime you have greater than 0.5 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. And I'll turn it over to Jeff for comments also, Leo.

[Jeffrey Hutton, executive]

Yes, Leidy South is a major project basin, and we're excited to get it in service for us. It's incremental 250,000 a day from [indiscernible] the 330,000 a day [ expansion ] piece come from the West, and that's over in the more -- the cheap Seneca area.

But 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 6-mile replacement pipe that -- have to install this month, kind of a one-shot and then that piece of the puzzle will be fixed. But overall, you've 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, it's out on the website today, you'll see a pie chart or at least a table that kind of outlines 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. And 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 to get priced off of differentials in basis, locations, not in-basin locations, sort of like that.

And then you add our cash piece then, which is completely different than local basis, for first of the month sales of roughly 10%. You really whittle down our basis exposure and local basis exposure to roughly 15% or maybe 15% to 18% depending on the time of the year.

So yes, we're disappointed about the May differential blowout, if you will, due to a pipeline project that everyone knew was going to take place. But then again, that project also prohibits any gas going into the Leidy storage fields for the month of May.

So we won't have a pickup on gas sales per storage in June and the rest of the summer up there. And with the -- no supply increases and all the other factors that we mentioned were, our expectations are a strong summer and a strong winter on price.

[Leo Mariani, analyst]

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 bonds side come September.

Just wanted to kind of see like 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 returns strategy such as a larger supplemental dividend or to maybe kind of start the buyback program? And then just additionally, can you just maybe remind us kind of 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?

[Dan Dinges, executive]

Yes, Leo, good questions. And 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. And we have been, in the last few years, fairly generous on -- and rightfully so, generous on returning a large portion in much greater than 50% of our free cash flow back to shareholders.

We have -- and I'll let Scott talk about our program a little bit, but we have our dividend and the variable piece, supplemental. And 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.

So in looking at how we would manage the available cash, we're already talking about it. And 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...

[Scott Schroeder, executive]

Yes. Leo, I think 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 out -- been generous, outsized what that historically has been the buyback.

The supplemental dividend, the plan as -- from a 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. So we'll have a pretty good idea on our revenue stream for the full year. We're not that complicated.

So we'll be able to -- and 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 12 months. So 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 we -- 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. And I think if I was a betting man, I would make sure that -- well, I'd make sure I would kind of lean towards the fact that you should probably expect something in excess of 50%. The 50% is our minimum commitment, as we've said. And when you look back at the history, as Dan alluded to, we far exceeded that.

[Leo Mariani, analyst]

Okay, that's helpful color for sure, guys. I guess what I was trying to get at is just above that 50%, obviously, you have the fixed dividend already in place here. And then I guess you're going to just kind of toggle between whatever you guys want to do on the buyback versus variable dividend.

So let's just make up some numbers. If you had $500 million of free cash flow this year and call it $170 million committed to the dividend, I guess that will 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?

[Scott Schroeder, executive]

So you're saying the free cash flow is $500 million, right?

[Leo Mariani, analyst]

Just saying roughly speaking, just in a random [ way ].

[Scott Schroeder, executive]

Yes, if it's $500 million, again, our commitment is $250. And then above the $250 million is the $180 million of debt, leaving a wedge of about $100 million. And we'll -- depending on market conditions will dictate -- once we get to the $250 million already delivered, and 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?

Again, we're trying to make -- I'm not trying to be coy, Leo. We're trying to maintain flexibility in terms of -- again, in your example, if the stock was at $15, -- let's say 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.

[Operator]

Your next question comes from the line of Charles Meade with Johnson Rice.

[Charles Meade, analyst]

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. So I guess kind of a 2-part question. One, it seems like you've substantially or maybe completely solved that issue.

And then the second part of it is there was one part that may be missing. So you have just the 2 million -- the impact is just down to 2 million cubic feet a day. But did it cost you anything on the completion side of those 21 wells, having to change your completion design?

[Dan Dinges, executive]

Yes, that's a good question, Charles. And what we've seen so far, no, it hasn't cost us anything on our recipe on completion. We have -- the early results on our new wells, the early results have certainly met our expectation of what we would have anticipated seeing. And on the 2 million a day on the parent wells, that is basically no effect. We would anticipate possible just -- that to clean up and not be a rounding error as we move forward.

So again, yes, we are excited and pleased that 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.

The -- at 4 wells -- 4 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 effected completions in the child well also. We don't think we're compromising our completion standard.

[Charles Meade, analyst]

Got it. That's helpful detail, Dan. And then I had another question to see if I could maybe look ahead a bit at 2022 and the effects of your cadence in '21.

It looks like your '21 capital spending plan is not going to be exactly the same, but it looks similar to your plan in '20 in that the peak of spending is -- it comes in Q2. And there's -- the low for the year is in Q4. And if you look at the effect that '20 appeared to have on '21, it's -- you declined sequentially in 1Q and 2Q based on that '20 pattern.

So is it a fair inference that, that's what we're going to be looking at in '22 based on the '21 spending pattern? Or is that too simplistic?

[Dan Dinges, executive]

Well, one of the things that you need to take away, Charles, and I know you know this, you followed Cabot for a long time, but I think it's worth repeating, Cabot is the lowest capital intensity company out there. 2 rigs -- we have 3 running right now, but we're going to lay one of those rigs down as we've already messaged. And we'll be between 1.5 and 2 frac crews.

So anytime 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 8-well pad, and that pad whether it's for weather or for whatever reason, if it's delayed, say, 200 million a day, it's delayed for a week. 200 million a day delayed for a week and say that occurred at the very end of the 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. But if that 8-well pad comes on the last week of the quarter, it's reflected as a quarter completion. But 8 wells coming on at the end of a quarter have, in essence, very little impact on production in that quarter. So you're looking at -- a week delay is, at a 200 million a day pad, is 1.4 Bcf.

So that is how 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 5 or 6 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, but when we report and 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 have through the first quarter, and we're going to start ramping up.

So that's -- 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. And 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 a month to be able to have a better tie.

[Charles Meade, analyst]

Right. It's hard to know how much information is too much, but I appreciate your points and they're well taken.

[Operator]

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

[Arun Jayaram, analyst]

A 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 enters service? I know it's early, but I'm just wondering about the potential production trajectory in '22. And any thoughts on holding that, call it, that higher 4Q exit rate flat? And thoughts on what kind of CapEx would that require to keep 4Q flat.

[Dan Dinges, executive]

Yes, you're right. It is a little bit early for disclosing 2022. We are working on 2022 program. We take in consideration, just like we do on our capital, 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, but I appreciate the question.

[Arun Jayaram, analyst]

Okay. And just -- I mean maybe a follow-up to Charles' question. I know you addressed this. But one of the questions that came in, Dan, 80 wells for this year, you [ TIL-ed ] '21. And so 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 would be a little bit more flatter in terms of sequential, just given the number of tied in lines in 1Q.

[Dan Dinges, executive]

Yes, it's just the -- again, the other element that needs to be focused on would be not only the timing, the number, but also keep in mind that our -- we're not in a geographically in a perfect squares sectional drilling. Our units set us up there, our various configurations by nature of Pennsylvania.

And our lateral lengths, number of stages, when you tie it to a well count, it's not as systematic as it would be if you had, and 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 drilled 10,000-foot laterals and we'll have consistent number of stages in 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.

So -- and I'm trying to answer the question on expectation and some of the variables that go into that expectation. 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 '19 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 '19 and latter part of '20, that did affect our forecasting and how we would look at the measurement of the results and to tie back 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 a more immediate impact and uplift and similar production return to the parent wells after our completion of the child. So we're hoping that we are mitigating that concern.

[Operator]

Your next question comes from the line of Umang Choudhary with Goldman Sachs.

[Umang Choudhary, analyst]

Appreciate the comments around differentials improving with the start-up 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 are working on right now to stimulate that or capture that demand for Cabot.

[Dan Dinges, executive]

Yes. I'll -- I think Jeff is the perfect one to answer this question.

[Jeffrey Hutton, executive]

Yes. The Leidy South project is -- it takes our production down from Northeast PA into the Washington, D.C. area now to a location called River Road. It's very important that -- that's a central location on both north and south depending on the season for gas demand. And so 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 on regarding it and their Supreme Court case on eminent domain. And then I'm sure you're aware that Transco also announced regional energy access, which is a close to 1 Bcf a day of pipeline that's basically a brownfield project to existing right of ways.

That project also would be connected to Cabot's supply area in several different spots. So we're excited for that project and actually PennEast as well to become in service over the next couple of years.

[Operator]

Our final question comes from the line of David Deckelbaum with Cowen.

[David Deckelbaum, analyst]

Dan, you gave some really good information around the surgical completions and how they [ became ] 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 heard, at least [indiscernible] current [ job ]. And before, you said there's no incremental cost. I have 2 questions.

One would be, is there an incremental cost that's just being offset by the location where you're placing these wells and sort of the amortization of previous costs on existing pads? And then 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? And it wouldn't be something where we would see improvements in your capital efficiency metrics?

[Dan Dinges, executive]

Well, there's a couple of things. I'll answer the second question first. And I'm going to have you repeat the first question, David. You were breaking up on me a little bit.

But we feel good about what we've seen and our expectation about replication. The 4 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 and as I've already indicated, the variables we're using on the completion.

So 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 '19 and some of our wells on 20. We saw -- not only was it difficult to bring some of those wells back on, and we took revisions on some of those wells.

And keep in mind, some of those wells that we took provisions 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. But we do and have seen some of the wells continue to improve back from the frac impact that we received.

So 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. And David, I'm going to have to ask you for the -- repeating the first question.

[David Deckelbaum, analyst]

Thanks, Dan. Happy to. I'm sorry for the noise. But the first question was just you talked earlier that the surgical completions don't add any incremental cost. But I guess in isolation, are they adding costs that's just being offset by savings of existing pads or existing infrastructure that's in place?

[Dan Dinges, executive]

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. In fact...

[David Deckelbaum, analyst]

Okay, that effectively answers it now.

[Dan Dinges, executive]

Yes. And in fact, I would have to get Phil Stalnaker kind of to answer the question more directly. But you might have incremental savings, if you would, if you have maybe less fluid or less proppant in a particular frac, but I don't think it'd be consequential enough on the savings side to try to dissect it.

[David Deckelbaum, analyst]

I appreciate that. If I could just [ drop in ] one quickly to Scott. Maybe it's not quick, but you mentioned earlier the span of buybacks. And 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%.

And one, I just want to understand, like as you think about that, that's really a 2021 reality with the free cash that's coming forward. And then along those lines, you guys are approaching 0 net debt. You have the bullet payments that come in this year. Revolver is pretty clean here and there's a lot of capacity there.

So do you think that -- do you have a goal of being at 0x? Or might you lean on that capacity a bit more to stabilize shares?

[Dan Dinges, executive]

Yes, I'll make a quick comment, turn it to Scott. But 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 0 net debt position. We have flexibility.

I know Scott talks about it. Scott and Matt visit -- about kind of what capacity we have, how we might utilize that to enhance shareholder value.

And we're going to continue to do that. And 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. And I'll turn that to Scott.

[Scott Schroeder, executive]

There's nothing to add. There's really not. I mean at the end of the day, David, again, there's no intent to be 0 debt, even net debt. The plan we have - we have nothing maturing next year. We have a $62 million tranche in 2023 at -- you probably -- at 6% money, you probably pay that off, again, if the cash flow profile stays.

But for the remaining $800 million, we'll look to refinance those biggest tranches in 2024, and then there's another tranche in 2026. So those would -- there would be $800 million to $1 billion of kind of permanent financing in a status quo case in the balance sheet. But as Dan said, we have lots of flexibility.

Again, you know we're also more -- we're very judicious with shareholder money. We'd 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're putting a defensive posture. So I don't mean to say trust us, but I think we have a good track record of returning and being very disciplined.

But quite honestly, I'll be -- the buyback program of old, I think Matt and I had this debate. I think every share I bought or instructed him to buy back has been bought at a higher price than we've recently been at. So that kind of hits a 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 0 debt." That's not our path. And I think the market has quickly reverted as people were able to extend out their maturities, repay debt, as Dan said in the script.

And 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 Cabot.

[David Deckelbaum, analyst]

Looking forward to seeing how well you guys get.

[Operator]

This concludes our question-and-answer session. I would now like to turn the conference back over to Dan Dinges for closing remarks.

[Dan Dinges, executive]

Thank you, Angie. And 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. And I can assure you that my optimism going into the season, we're going into and the setup that we have at -- in front of us is significantly better than it has been. And I'm optimistic that we're going to be able to start enhancing shareholder value.

So thanks again, and thank you for the questions. I look forward to the next visit.

[Operator]

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