Coterra Energy Inc

NYSE:CTRA

Earnings Call Transcript 2019-Q2

[Operator]

Good day, and welcome to the Cabot Oil & Gas Corporation's Second Quarter 2019 Earnings Conference Call and Webcast. [Operator Instructions] Please note that this event is being recorded.

I would now like to turn the conference over to Mr. Dan Dinges, Chairman, President and CEO. Please go ahead.

[Dan Dinges, executive]

Thank you, Chuck, and good morning to all. Thank you for joining us today for Cabot's Second Quarter 2019 Earnings Call.

As usual, joining me today on the call are several members of Cabot's management team. I'd first like to remind everyone that this -- on this call this morning, we will make forward-looking statements based on our current expectations. Additionally, some of our comments will reflect and refer to non-GAAP financial measures, forward-looking statements and other disclaimers, as well as reconciliations to the most directly comparable GAAP financial measures, are provided in this morning's earnings release.

During the second quarter, we continued to successfully execute on our strategic goals of, and I'll list them: Generating positive free cash flow, returning capital to shareholders, improving return on capital employed, delivering growth per debt adjusted share and maintaining low leverage.

All of this was achieved despite lower NYMEX prices during the quarter, which retreated to levels the industry has not experienced since the second quarter of 2016.

Second quarter net income was $181 million or $0.43 per share and adjusted net income, excluding selected items, was $151 million or $0.36 per share. This represents 177% increase on adjusted earnings per share relative to the prior year comparable quarter.

Free cash flow for the second quarter was $73 million compared to free cash flow deficit of $62 million in the prior year comparable quarter. We have now delivered positive free cash flow for 12 of the last 13 quarters.

Year-to-date, we have generated $381 million of positive free cash flow, and we are on track to deliver between $500 million and $625 million of positive free cash flow for the full year based on an average NYMEX price assumption range of $2.60 to $2.80. For the trailing 12 months, we generated a return on average capital employed of 23.5% compared to 8.5% for the trailing 12 months as of the end of prior year comparable quarter, representing an increase of approximately 1,500 basis points.

The improvement in our financial metrics relative to prior year comparable quarter was driven by higher production levels, improved realized prices and lower operating expenses.

Production for the quarter of 2.35 Bcf per day was at the high end of our guidance range and represented an increase of 24% relative to prior year comparable quarter. Natural gas price realizations were $2.27 per Mcf, an increase of 6% when compared to the second quarter of '18. And price realizations before hedges, were $0.44 below NYMEX, an improvement of $0.24 compared to the prior year comparable quarter.

Operating expenses decreased to $1.41 per Mcf, a 24% improvement relative to the second quarter of 2018, which was primarily driven by lower exploration expenses resulting from our decision to cease capital allocation to exploration projects at the end of 2018.

As of the end of the second quarter, our balance sheet remained one of the best in the industry with over $241 million of cash on hand and a net debt-to-EBITDAX ratio of 0.6x.

During the second quarter, we repurchased 5.1 million shares at a weighted average share price of $24.63, reducing our shares outstanding to $418.4 million. This represents a 10% reduction in shares outstanding since we reactivated our share repurchase program in the second quarter of 2017.

This morning, we announced that our Board of Directors have authorized an increase in the shares repurchase program by 25 million shares, bringing the current remaining authorization to 31.5 million shares or approximately 8% of our outstanding shares.

Our year-to-date share repurchases, coupled with our anticipated dividend payments for the full year, already implies a return of 50% of our anticipated free cash flow for the year at the midpoint of our NYMEX price assumption range. However, given the continued share price weakness we experienced during the second quarter trading blackout period, we expect to continue to be active on opportunistic share repurchases in the second half of the year, while still preserving some cash on the balance sheet to support future return of capital to shareholders.

For the full year, we have adjusted our 2019 production growth guidance to a range of 16% to 18% or 24% to 26% growth on a debt adjusted per share basis.

For the most part, this small guidance adjustment is simply a change in our operating plan that will increase the average lateral length on an 8-well pad we began drilling in the second quarter from 8,950 feet laterals to 12,450 feet, resulting in an additional 140 completed stages for the year. Frankly, this decision was not too difficult. I was asked, and you can put yourself in my shoes, do you want to purchase this offset acreage, slightly delay our turn-in-line date and add over 100 Bcf plus to these 8 wells or do we remain on our schedule? I took the slight delay and the 100 Bcf.

Our update -- actually additionally, as it relates to absolute third quarter growth figures, we further risk these volumes for potential market conditions. Specifically, the last couple of years, the third quarter has been softest period for realizations and it could happen again. So we have decided to maintain maximum flexibility to manage the pace and cadence of our turn-in-line. On our 2019 capital program, the range of $800 million to $820 million reflects the incremental drilling and completion activity from the long laterals of this 8-well pad. In addition, we plan to drill an additional 4 net wells resulting from continued efficiency gains that are generating faster drilling times year-to-date than originally forecasted.

We're firmly committed to disciplined capital spending; however, our rigs are fully contracted through the end of the year so we made the decision to drill 4 additional wells as opposed to incurring day rates on idle rigs at the end of the year.

Given we now have 7 months of actual NYMEX settlements year-to-date, we tightened our NYMEX price assumption range for the full year to $2.60 to $2.80. Based on this range of NYMEX prices, we expect to deliver $500 million to $625 million of positive free cash flow, 20% to 24% return on capital employed and a 38% to 56% growth in adjusted earnings per share.

Given the amount of questions we have received over the past few months regarding our plans for 2020, we decided to issue preliminary 2020 guidance earlier than usual. There are still a number of variables that will become better understood as we get closer to year-end and may impact our 2020 plans, including storage levels, NYMEX futures at year-end and the results of our annual service cost negotiations. However, based on our current outlook for the year, we believe this preliminary plan provides the best combination of free cash flow, return on capital employed and growth per share metrics in a lower natural gas price environment.

Our 2020 operating plan is expected to deliver 5% production growth or 7% to 8% growth on a debt adjusted per share basis from a preliminary capital budget range of $720 million (sic) [ $700 million ] to $725 million. This does include a 5% exit-to-exit growth rate in 2020.

At our budgeted NYMEX price of $2.50, this program is expected to deliver $375 million to $400 million of free cash flow, a return on capital employed of approximately 15%. At $2.75 NYMEX, these metrics increase to $525 million to $550 million of free cash flow and a ROCE of approximately 20%.

Under both NYMEX price assumptions, we expect to continue to deliver annual dividend growth and opportunistic buyback of stock while maintaining a debt-to-EBITDA ratio below 1 turn.

Not only do we believe this more moderate growth program is the appropriate strategy for maximizing shareholder value in 2020, but we also believe this is the best strategy for the company longer term, given the current outlook for supply growth over the coming years.

Our plan for single -- mid-single-digit growth of top line production can result in high single digit growth in metrics per debt adjusted share as a result of improving cost structure, a reduction in shares outstanding resulting from an active share repurchase program and a reduction in our absolute debt levels at -- as maturities come due over the next couple of years.

At the risk of stating the obvious, we're all aware of the materials and presentation opining on the state of the macro environment across the sector. We believe that investors, industry analysts are correct and that we need to continue to be laser-focused on free cash flow generation rather than production growth for its own sake, particularly given the outlook for future supply growth for both oil and gas. Going forward, we see absolutely no rationale for continuing to chase double digit production growth when supply growth could outpace expected demand growth at this time.

We can guarantee that Cabot will continue to deliver on its track record of disciplined capital allocation, focused on generating positive free cash flow, improving results on and of capital, delivering economic per share growth and maintaining an ironclad balance sheet.

Chuck, with that, I'll be more than happy to answer any questions.

[Operator]

[Operator Instructions] Our first question comes from Leo Mariani of KeyBanc.

[Leo Mariani, analyst]

I was hoping you could provide maybe a little bit more color on 2020. I know it's a preliminary budget, but just kind of based on the CapEx levels, can you maybe talk a little about some of the changes in activity? Would you guys expect to potentially drop a rig at some point next year or all those rigs under contract potentially next year or would you be kind of fracking fewer wells? Just trying to get my arms around the reduction on CapEx there.

[Dan Dinges, executive]

On the '20 CapEx, as we've referenced the -- it's a little bit early in the guidance release, earlier than we normally lay it out. I would like to get more granular and not trying to dance your question. I'd like to get more granular on our October call, as we usually do. The market is dynamic at best. We saw this morning, near 3 months on the Strip price is below $2.20. A lot of moving parts. We're trying to find the best solution to continue what we do and that's to deliver free cash flow and efficient program. So as far as being granular on the 2020 program at this time, I think it's a little premature because it's a -- it's in -- really moving a lot as you can appreciate.

[Leo Mariani, analyst]

Yes. No, that certainly makes sense. Or perhaps, maybe you could just give us an update on sort of what you're seeing out there on in-basin demand projects? And kind of maybe a little bit more specific commentary just around how you see supply-demand dynamics unfolding in specific Northeast PA market over the next couple of years?

[Dan Dinges, executive]

Good question. And we had our Board meeting yesterday. We had discussions of our in-basin demand process, and I'll let Jeff opine a little bit on it.

[Jeffrey Hutton, executive]

Leo, yes, the in-basin demand is high priority here. We have been successful adding a few smaller projects since the last call. They are smaller projects, but in aggregate, they're starting to add up. I think currently we have a little over 0.5 Bcf of gas that does not get into the interstate market. So that's a really good thing. We continue to evaluate projects. We're being somewhat selective in that arena. It's also a very competitive market. There's a lot of producers that would like to have good demand projects tied to their gathering systems. So we're being a little bit quiet on how we explain our business model up there.

I will say that we're also evaluating a number of opportunities in the interstate capacity markets. We've gotten -- it's getting better and better from that regard. We're still not where we want to be to take over some positions on the long haul side. We think the market will continue to improve, but we're definitely seeing opportunities out there, that we can pick up some capacity sooner rather than later. And we're -- we'll watch that very closely.

[Operator]

The next question comes from Brian Singer of Goldman Sachs.

[Brian Singer, analyst]

The opportunity that you guys had here to add acreage that would support longer laterals, can you talk about whether that -- you see that as a one-off? Or whether there -- that is something that you could do more of? And then following up on that, if we think about more in or out-of-basin consolidation, what is your latest on the -- on your outlook for the role Cabot should or could play?

[Dan Dinges, executive]

On the additional acreage and wherever we might have a pad offset to either open or others acreage, it's a little bit unique, Brian, but certainly we have continued to start our beginning expectations of our program with shorter laterals than we actually end up at the end of the year. And that process has been ongoing each of the last handful of years. We anticipate shorter laterals. We, through Phil and his team up there in Pittsburgh, are able to extend laterals as we're discussing in various different ways. Some of it's other acreage, some of it's our own acreage and some of it's unleased acreage. So I would say there's the occasion in the future, and we would expect to continue to do some of that. Your other question, Brian, I'm sorry?

[Brian Singer, analyst]

It was more of a larger in-basin or out-of-basin consolidation and your latest thoughts on the role Cabot should or should not play?

[Dan Dinges, executive]

Yes. You know, consolidation has got to be real unique to be able to fit a long-term strategy and we continue to evaluate opportunities, as we've mentioned in the past. And you look at where our acreage lies and the offset acreage that would be available and you look at the, say, the 6-county area up in the Northeast. There's a few areas that we have and would have an interest in. There's other areas that we would not have an interest in. So should the industry as a whole -- let's back up a little bit, as a whole consolidate, just -- it should consolidate in a lot of ways to be able to rationalize some of the return profiles that are being experienced, particularly in the slow commodity strip. This commodity strip, if it's persistent, is going to be a challenge for a number of companies. We have -- and we are the lowest cost producer across the space in the natural gas. We've given our numbers at a $2.50 NYMEX price and what we can deliver with that, free cash flow, buying back shares, a good double-digit return on capital employed, dividend. So we're in good shape. But overall, the industry is not healthy right now in this space, in this price, projections on the strip, and something is going to have to change.

[Brian Singer, analyst]

Great. Great. And if I could just ask one other follow-up. As it relates to the 2020 preliminary guidance, seems like there's a lot of moving pieces there. Could you talk a little bit about what you see your maintenance capital and underlying corporate decline rate? And then how that kind of juxtaposes with your expectations for well performance, upper Eagle Ford versus lower Eagle Ford, et cetera?

[Unknown Executive]

Eagle Ford?

[Brian Singer, analyst]

I'm Sorry. I'm sorry, did I say Eagle Ford, oh my gosh. Upper Marcellus versus Lower Marcellus. Wow, that's the second time I missed that one.

[Dan Dinges, executive]

That's a blast from the past.

[Unknown Executive]

You're on the wrong call.

[Brian Singer, analyst]

Yes, exactly. Upper Marcellus versus Lower Marcellus. Sorry about that.

[Dan Dinges, executive]

Well, our current decline is the mid- to upper 20% decline and a maintenance capital with that assumption is $550 million to $575 million. And as we balance in our upper wells with the drilling of our lower wells, you might see a slight tweak in the difference as we represented the differences between the upper and the lower wells. But we don't see any dramatic changes from what that maintenance capital is on a go-forward basis.

[Operator]

The next question comes from Jeffrey Campbell with Tuohy Brothers.

[Jeffrey Campbell, analyst]

Even though the free cash was modest this quarter, it still provided approximately 1.9x dividend coverage. I was wondering if and how you factor in dividend coverage from cash when you contemplate any dividend increases?

[Dan Dinges, executive]

Well, we look at the entire macro environment, Jeffrey, and look at what our best guess, our crystal ball is of the price and realization environment and also what the strip -- actual strip is doing. We also look at the hedge deck that we have and just see what kind of protection that we might have there. We're not looking at the dividend coverage specifically as you've addressed, but we are committed to delivering that dividend where it exists today. And I do think with our ongoing expectations of continuing to push our cost structure down, gaining efficiencies in our operation, that we will have the opportunity to manage an increase in the dividend at the appropriate time. We haven't outlined a specific timetable to do that, but it is our intent to continue to manage the dividend in a way that delivers more back to the shareholders. Keep in mind, our balance sheet is really clean. We -- our maturities are not -- are entirely manageable over the next few years. So it kind of depends on what our anticipation is of the near-term realizations that we will see.

[Jeffrey Campbell, analyst]

Okay. And I guess to ask another balance sheet question. Is there a minimum amount of cash that you want to leave on the balance sheet or do you intend to use most or all of it for the share buybacks or acquisitions or whatever else you might use it for?

[Dan Dinges, executive]

Yes. Our leverage position, we're -- we don't take on a lot of risk. We've managed that way for -- always managed that way, quite frankly. Looking at a 1 turn, is we're entirely comfortable in that range. How much we want to leave there, we're 0.6 at this stage. We have $241 million of cash there now undrawn, $1.7 billion facility. And so we're comfortable in this range. And I don't anticipate us to deviate a great deal. And quite frankly, as we move forward, we'll probably work that down a little bit. But we like the range we're in.

[Operator]

The next question comes from Charles Meade of Johnson Rice.

[Charles Meade, analyst]

I was wondering if you could give us a little more detail perhaps on the scale of that acquisition that you did that extended the laterals. I think you gave us some parameters about how much the extended laterals. But how many acres are we talking? Is it something where it's meaningful? If you could talk about the acquisition price that you put out there for it?

[Dan Dinges, executive]

It was just like -- I don't have an exact -- it was $2.5 million, plus or minus, is what that was. It was enough acreage to be able to extend the laterals. We can develop most of that acreage with this extension. And it was just an opportune time to be able to create a win-win. And that win-win allowed the acreage to be developed and -- but also allowed a more timely cash return to the owners that might have been developed further out in their program. So it was just a good win-win circumstance.

[Charles Meade, analyst]

Got it. Got it. And then if I could go back to -- and I think you -- Brian Singer was kind of touching on some of these same points. But can you -- as far as -- I recognize it's early to talk about what's baked in the 2020 plan. But can you talk about what kind of assumptions you're using both for the service cost environment that you'll be living in, in '20, and then maybe also your well productivity. Because I think one of the things that people might see from the outside looking in, is it looks like you might be getting less bang for your buck in '20 than you have in the past. And so anything you can add to that would be helpful.

[Dan Dinges, executive]

Yes. Great question. And we're probably getting beat up because we added a little bit of capital. We moved some of these turn-in-line wells out and production might not be where it is on a near-term basis. But it's difficult, particularly on a company that is producing approaching 3 Bcf a day and we're managing that cadence, if you will, that growth with 3 rigs and 2 frac crews. So as you bring on a pad or 2, you look at the lumpiness that might occur on any given quarter or any 2 quarters for that matter. You add into that a soft price out there that we're seeing and the timing of bringing on a pad is a conscious decision for us. And also the cadence of how we'd bring on a pad i.e., do we bring it on as we typically might with more flush production or do we just slowly, much, much slowly -- slower bring it on? And that has an effect.

Particularly if you have a pad that you maybe forecast back when and that pad was forecast to be 200 million, 250 million cubic feet a day, it doesn't take a lot of days or a slide in the schedule to affect how it affects your program. As an example, say we decided to delay this program -- bringing on a pad that had that expectation in our forecast for 4 days. All right? Well, that doesn't seem like a lot, but that's a Bcf of production. So it shows up, particularly if you look at it so granularly in a quarterly perspective. So the numbers that are out there right now, I would caution that you got to -- and our program you got to take it with a grain of salt. We're very comfortable with the efficiency of our program, the results of our wells. We haven't seen fall-off on any of our averages that we anticipate. So we're comfortable there. As far as a budgeting process, we always add an expectation of service cost increases into our projections.

We always do that just as a matter of course and that gives us a little bit of room. This is no exception. If -- and that's what you see. However, I would make this statement that in light of where the current strip price is, the macro environment is, I would be -- we're going to be looking at that service cost very diligently to see what it's going to take for our annual service providers to join Cabot's team.

We're -- and I'll add that we're very pleased with every provider we have out there to date, efficient operations and they are part of the team. But we have, again, arrived, as I mentioned, into a pricing environment on prices that we haven't seen going back to 2016. So it's a difficult pricing environment than -- and we're going to have those negotiations ongoing here between now and the end of the year.

[Operator]

The next question comes from David Deckelbaum with Cowen.

[David Deckelbaum, analyst]

Dan, I was just curious that as you think about managing your production in the back half of this year, just given where the curve is, are you leaving in some ability there, I guess, to -- would you be curtailing production if, like, the curve is flirting with $2 here?

[Dan Dinges, executive]

We have curtailed in the past our production back in -- what was it '15?

[Unknown Executive]

'16.

[Dan Dinges, executive]

'16. I know we -- and that was kind of the second quarter of '16 for a period of time. We took a half -- curtailed 0.5 Bcf a day for a period of time because of the realizations. We're not afraid to do it again. When we forecast and we make projections, we do have -- and particularly in this environment, we do lean towards the conservative side of our forecast. We do look at the timing of bringing on wells and managing our production between now and the end of the year. I looked at the screen this morning. The -- like I said, the first 3 months -- the next 3 months are below $2.20. Well, if it directionally keeps going that way, we will have a response. And how you balance our response operationally, what we think our product is worth and trying to stay within the fairway of guidance is always a balancing act. But we're in difficult times. And we're going to do what's right for the long term. And we'll take the hits on the short term, but we're going to do what's right on the long term.

[David Deckelbaum, analyst]

I appreciate that. If I could just ask on the free cash outlook for next year, at $2.50 gas, what are you assuming in terms of, I guess, unit cash cost savings next year, either on just like a total percentage basis? And where is most of that stuff coming from?

[Dan Dinges, executive]

Yes. We are -- we look at '19 a little over $1.40 as our cash cost, which includes financing, and -- so DD&A and all. The '20 forecast has us kind of right at -- it's reduction, but kind of right at $1.40 is where we are and we expect. And rolling forward, that will continue to reduce the numbers from there.

[David Deckelbaum, analyst]

Got it. And if I could just lob in one more. Just -- you talked about, I think, the maintenance capital assumption of $550 million to $575 million. Is that D&C or is that total corporate level? And I guess do you see that improving going into '21 just given the slowdown in '20?

[Dan Dinges, executive]

David, a good question. And Matt has been granular in this. So Matt, do you want to?

[Matthew Kerin, executive]

Yes. Yes. David, this is Matt. That does conclude about $50 million of annual non-D&C capital. So I think that's something that everyone needs to take into consideration when they're looking at our $700 million to $725 million guide for next year, that there's about $50 million there that goes into certain projects we're working on, whether it's some compression, whether it's buying new water trucks for our service subsidiary, whether it's some lease acquisition as we start having some land exploration. So obviously, the D&C capital is going to be significantly lower than that $700 million to $725 million that we've talked about. And yes, I do expect to see a moderation in base declines as we move into 2020 and 2021, which would presumably result in lower maintenance capital in the out years.

[Operator]

The next question comes from Michael Hall of Heikkinen Energy Advisors.

[Michael Hall, analyst]

A lot of mine have been addressed. On the maintenance capital front, just a follow-up there on that question. I think you previously disclosed around $500 million of maintenance capital versus this $550 million to $575 million. I was just curious as to kind of what changed or is it accounted for in that $50 million of annual non-D&C?

[Matthew Kerin, executive]

Yes. So Michael, that number that we put out there, that was really from 2 or 3 years ago and we were assuming at that time, 2016, service cost prices, which obviously, we've seen a little bit of upward pressure since the troughs of the service price environment since then. Additionally, we do have some incremental non-D&C capital like I alluded to. I mean we're spending $10 million this year on water trucks for our service subsidiary. We're looking at some pad level, well level compression projects that ultimately are 100% plus type IRR projects because they allow us to see production uplifts.

But ultimately, 11 years into the program, when you're producing out of $650 million to $700 million wells -- 650 to 700 producing wells, you're just going to have ongoing capital that's outside of your drilling and completion program. So it's a little bit different. It's really an apples and oranges relative to that number from 2016.

[Michael Hall, analyst]

Okay. Understood. And then...

[Matthew Kerin, executive]

But let me be really clear. We're not seeing any type of degradation in well productivity or capital efficiency or anything. This is just the nature of running a program that's close to 3 Bcf a day of production now. And so this is just the reality of having this big of an operation.

[Michael Hall, analyst]

Different animal. Yes. I hear you. And then, I guess, yes, you alluded to the changing service cost environment versus that last disclosure. What is the latest kind of well cost for a given lateral length for you guys? And how do you guys play that through in that 2020 guide?

[Dan Dinges, executive]

Well, we have -- it's kind of referenced on the 2020 -- I mean this year's guide on the -- the capital with this 8-well program was an example of incremental 140 stages. But we are seeing efficiencies in our drilling and completion program and have captured, if you will, time enough through those efficiencies to add 4 incremental wells to our program at the end of the year. So you can kind of measure the efficiency gains in that way.

[Michael Hall, analyst]

Okay. Yes, I guess specifically, I was just curious on like cost per well for a given lateral length. Do you have that...?

[Matthew Kerin, executive]

It's still -- our leading edge costs right now are about $1,000 per lateral foot. That's generally been the average for this year. Again, we're assuming a little bit of cost inflation as we go into 2020, but we have the next 2 quarters to figure out. And frankly, some of the softness we see in the market, we wouldn't be surprised to see those numbers go down. But as Dan alluded to in the prepared remarks, we're just assuming that for the time being and a lot can transpire between now and year-end as we start to ramp up those negotiations.

[Dan Dinges, executive]

And I'll add to that. On the lateral length, there's some material out there regarding lateral lengths and efficiencies and gains out there. I have all the confidence in the world in our team to be able to work with the technologies that are available and efficiencies that are available on completions to see the efficiency gains that may be out there. So we look forward to continue to monitor any new technologies or efficiency gains that might be out there in the industry.

[Michael Hall, analyst]

And yes, you kind of -- you're hinting at toward what I was kind of getting at. And that $1,000 per foot is a good bit higher than, I think, some of the peers down in the southwest. Is there anything structural that would drive that higher level? Meaning like is it depth or is there some apples and oranges involved here do you think?

[Matthew Kerin, executive]

I think you're hitting on that. It's apples and oranges. I mean I think what -- and we're -- as Matt alluded to, we're -- in the next 6 months because we did see those presentations, we're doing a deeper dive. But as you know from Cabot's DNA and where we've been forever, ours is all in. We're not cherry picking and excluding some aspects of what's going on, on the pad. Ours has everything in it. And that's probably the biggest difference. If you broke out every single piece, you will find things missing in other areas by some and Cabot's will have everything in it.

[Dan Dinges, executive]

Michael, there will be a -- we don't see numbers out there and don't think that -- I don't react when I see numbers out there that would be different than Cabot. So I can assure you with the detail of the spreadsheet I will receive that has every single item and every nut and bolt and a number will be furnished to me. And so we'll be able to manage.

[Matthew Kerin, executive]

And at the end of the day, the report card is in the 10-K, the total cost incurred and what the ultimate finding cost is for what they booked. That, regardless of what the headline IR deck number is, there it is.

[Operator]

The next question comes from Paul Grigel with Macquarie.

[Paul Grigel, analyst]

Following up on the maintenance CapEx item there. There was the comment that as the organization grows, maintenance CapEx may go up over time just as well as age. If growth were to continue at some nominal rate, should we expect that maintenance CapEx is relatively flat to that? Is that offset by the kind of declines within the underlying corporate decline? Just trying to understand maybe on a time plus 2 or 3 years out where we should be thinking maintenance CapEx heads?

[Dan Dinges, executive]

Yes. Paul, again, Matt digs on these numbers regularly and I'll let him give you the color.

[Matthew Kerin, executive]

Yes. So perhaps, I misspoke or maybe it was just a misunderstanding but what I was trying to say is that if we wanted to hold the Q4 exit rate from '19 flat into 2020, that was the $550 million to $575 million, Dan's kind of alluded to. If we wanted to continue to hold that level flat going into 2021, our expectation would be that maintenance capital would probably be $40 million to $50 million, even lighter than the 2020 levels because you are going to have a more moderated base decline. Now obviously our plan would hopefully be if we can get a little bit of support from the macro environment to not just hold levels flat and obviously our plan for the year already assumes a 5% exit-to-exit growth rate and so presumably if you are growing over time to 3 Bcf, 3.5 Bcf, whatever the number is, ultimately, at that level, yes, we'll have a higher maintenance capital amount but it will be off of a much higher base of production and obviously will result in much higher free cash flow levels.

[Paul Grigel, analyst]

Okay. No, that color is helpful. And then I guess maybe one for Dan here at a high level. If you guys are thinking maintenance CapEx is about $550 million to $575 million range. And doing a back of the envelope kind of exit-to-exit rate growth it looks like it's low single digits just as you kind of lap some of the growth from this year a trade-off of $125 million to $150 million for some nominal growth. I guess how did you arrive at this kind of current one, realizing its initial as opposed to maybe even a lower growth or true absolute maintenance CapEx program and another $100 million, $125 million plus to buy back stock or other uses for free cash flow?

[Dan Dinges, executive]

Yes. Paul, it sounds like you were sitting in our room talking about it. We have many sensitivities on how we would guide on our growth. The supply-side has grown rapidly. There is all kinds of discussions every single day out there about what the industry ought to do in regard to the supply-demand match. And as I've stated in my notes, I fully support the comments that I'm hearing out there that we have enough supply today. And that Cabot is going to do what is necessary to deliver the best return to its shareholders and part of that equation is to land in a production spot whether it's just flat production or if it is a small growth with the commodity price we're using in 2020 case, the $2.50. We're trying to thread the needle on what is the best landing spot in this environment. We think it is absolutely wrong for Cabot to go out and be double digits or grow into this market. And with the 3 rigs and 2 frac crews, we're kind of throttled back about as far as we can get, and it's kind of that 5% number. If we go to a straight maintenance then maybe we don't have 3 frac crew -- I mean, 3 rigs the entire year. Maybe the 2 frac crews are too many for the entire year, but that's the balance and the tweaking that we tried to -- trying to manage. And the reset for Cabot and what we look at, what's good for our shareholders is that we're not going to grow as much as we could.

[Paul Grigel, analyst]

No. That's right. Maybe one just real fast follow-up. Was there any discussion within that idea of if you went to a true maintenance CapEx that it preserves inventory at kind of sub-$2.50 prices and save that for a better day?

[Dan Dinges, executive]

Yes. There is that discussion. And we're -- again, we're -- I don't know exactly what's right or what's wrong, but as we sat around the table and putting a reduced production profile out and kind of looking at our numbers prudently and trying to layer in into our budget a little bit of cost inflation and being conservative like we do, the over and under for what the reaction was going to be was, yes, we'll probably see the under. But for the long term, we think what we're doing is right for our long-term shareholders.

[Matthew Kerin, executive]

Yes. And Paul, this is Matt. I'd add, I understand your logic, but we're really only talking about 15 to 20 extra wells off of an inventory base of 2,900 locations. So we're not really -- we're splitting hairs over that type of number. I think when we're looking at threading the needle here, we have the luxury of doing both. We can invest in the long-term value-creation of the business by continuing to grow production in a modest way and especially on a per share basis in a responsible way, but still generate free cash flow at $2.50, which obviously most others cannot do. So we think it's about balancing both long-term value-creation through continuing to invest in the business but also making sure that we have ample amounts of free cash flow to continue to return to shareholders. Keep in mind, we also have cash on the balance sheet that could go back to shareholders and we still have a noncore asset in a pipeline interest that we could monetize and also incrementally return to shareholders. So we think there'll be plenty of opportunities to return cash to shareholders over the coming months and years.

[Operator]

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

[Dan Dinges, executive]

Thanks, Chuck, and thank you all for the questions, the forward look. The questions certainly centered around the same focus that we had in the boardroom on how we're going to manage through a low commodity strip. And I appreciate the opportunity to give additional color. We look forward to another update in October. Thank you.

[Operator]

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.