Yahoo Finance Cabot Oil & Gas Corp (COG) Q2 2019 Earnings Call Transcript
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Cabot Oil & Gas Corp (NYSE: COG)
Q2 2019 Earnings Call
Jul. 26, 2019, 9:30 a.m. ET
Contents:
Prepared Remarks
Questions and Answers
Call Participants
Prepared Remarks:
Operator
Good day and welcome to the Cabot Oil & Gas Corporation 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 O. Dinges -- Chairman, President and Chief Executive Officer
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 continue to successfully execute on our strategic goals 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 a 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 a 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 their trailing 12 months, we generated a return on average capital employed of 23.5% compared to 8.5% for the 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 the 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 the prior year comparable quarter. Natural gas price realizations were $2.27 per Mcf, an increase of 6% when compared to the second quarter of 2018. 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 0.6 times. 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 has 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, the 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 turned in-line date and add over 100 Bcf plus to these eight wells or do we remain on our schedule.
I took the slight delay in 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 of realizations and it could happen again. So we have decided to maintain maximum flexibility to manage the pace and cadence of our turned 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 are 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 $7.20 to $7.25. 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 increased to $525 million to $550 million of free cash flow and proceed [Phonetic] of approximately 20%. Under both NYMEX price assumptions, we expect to continue to deliver annual dividend growth and opportunistic buyback stock, while maintaining a debt to EBITDA ratio below one-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 your current outlook for supply growth over the coming years. Our plan for single -- mid-single-digit growth of topline 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 as maturities come due over the next couple of years. At the risk of stating the obvious, we are all aware of the materials and presentation opining on the state of the macro environment across the sector. We believe that investors, industry analyst are correct, and that we need to continue to be laser focused on free cash flow generation rather than production growth for it's 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 it's 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.
Questions And Answers
Questions and Answers:
Operator
[Operator Instructions] Our first question comes from Leo Mariani of KeyBanc. Please go ahead.
Leo Mariani -- KeyBanc -- 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 could 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; all those rigs under contract; potentially next year would you be kind of fracking fewer wells just trying to get my arms around the reduction in capex there.
Dan O. Dinges -- Chairman, President and Chief Executive Officer
Well, on the '20 capex as we've referenced, it's a little bit early and the guidance released earlier than we normally lay it out. I would like to get more granular 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 three 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 deliver free cash flow, an 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 been really moving a lot as you can appreciate.
Leo Mariani -- KeyBanc -- Analyst
Yes, that certainly makes sense. Well, perhaps maybe you could just give us an update on sort of what you're seeing out there and 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 O. Dinges -- Chairman, President and Chief Executive Officer
Good question. And we had our Board meeting yesterday, we had discussions of our in basin demand process, and I'll let Jeff opine [Phonetic] a little bit on it.
Jeffrey W. Hutton -- Senior Vice President, Marketing
Good morning, Leo. Yes, the in-basin demand is higher priority here. We've had been successful in the few smaller projects since the last call, they are smaller projects but in the aggregate they are starting to add up. I think currently we have low over 0.5 Bcf of gas that does not get into the interstate markets, 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 is a lot of producers that would like to have good demand projects tied to the gathering system. 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 no sooner rather than later, and we're watch that very closely.
Leo Mariani -- KeyBanc -- Analyst
Okay, thank you for the color.
Operator
The next question comes from Brian Singer of Goldman Sachs. Please go ahead.
Brian Singer -- Goldman Sachs -- Analyst
Thank you. Good morning. 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 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 Royal Cabot should or could play?
Dan O. Dinges -- Chairman, President and Chief Executive Officer
On the additional acreage in wherever we might have a pad, offset to either open or others acreage. It's a little bit unique Brian but certainly we have continue 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 way, some of it's other acreage, some of it's our own acreage, and some of it's on leased acreage.
So I would say there is 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 -- Goldman Sachs -- 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 O. Dinges -- Chairman, President and Chief Executive Officer
Consolidation is -- it's got to be real unique, to be able to fit a long-term strategy and we continue to evaluate opportunities as we 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 six-county area up in the Northeast. There is a few areas that we have and would have an interest in, there is other areas that we would not have an interest in. So should the industry as a whole, it's back up a little bit as a whole consolidate just -- it should -- it should consolidate in a lot of ways to be able to rationalize some of the return profiles that or being experienced it particularly in this low 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 $2.50 NYMEX price and what we can deliver with that; free cash flow, buying back shares, 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, and this price projections on the strip; and something is going to have to change.
Brian Singer -- Goldman Sachs -- Analyst
Great, thank you. And if I could just ask one other follow-up. As it relates to the 2020 preliminary guidance, it seems like there is 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 etc.
Dan O. Dinges -- Chairman, President and Chief Executive Officer
Eagle Ford?
Brian Singer -- Goldman Sachs -- Analyst
I'm sorry, I'm sorry -- the Eagle Ford, my gosh, upper Marcellus versus lower Marcellus, not well, that's the second time I have used that one.
Dan O. Dinges -- Chairman, President and Chief Executive Officer
That's a blast from the past.
Jeffrey W. Hutton -- Senior Vice President, Marketing
You're on the wrong call.
Brian Singer -- Goldman Sachs -- Analyst
Yes, exactly. Upper Marcellus versus lower Marcellus; sorry about that.
Dan O. Dinges -- Chairman, President and Chief Executive Officer
Well, you know, our --our current decline you know 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 difference is 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.
Brian Singer -- Goldman Sachs -- Analyst
Great, thank you.
Dan O. Dinges -- Chairman, President and Chief Executive Officer
Thanks , Brian.
Operator
The next question comes from Jeffrey Campbell with Tuohy Brothers. Please go ahead.
Jeffrey Campbell -- Tuohy Brothers -- Analyst
Good morning, Dan.
Dan O. Dinges -- Chairman, President and Chief Executive Officer
Good morning, Jeffrey.
Jeffrey Campbell -- Tuohy Brothers -- Analyst
Even though the free cash was modest this quarter, it still provided approximately 1.9 times dividend coverage. I was wondering if, and how you factor in dividend coverage from cash when you contemplate any dividend increases?
Dan O. Dinges -- Chairman, President and Chief Executive Officer
Well, you know, we look at the entire macro-environment, Jeffrey and look at what our best guess, our crystal ball is, the price and realization environment and also with the strip -- actual strip is doing. We also look at the hedge that -- that we have and just see what kind of protection that we might have there. We -- you know, 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 -- maturities are not or 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 -- Tuohy Brothers -- Analyst
Okay, thank you. 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 O. Dinges -- Chairman, President and Chief Executive Officer
Yes. You know our leverage position. We are -- we don't take on a lot of risks. We manage that way for -- always manage that way quite frankly. Looking at a one-turn is we are 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 -- yes, 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.
Jeffrey Campbell -- Tuohy Brothers -- Analyst
Okay, great. I appreciate the color. We look forward to seeing you in New York in a couple of weeks.
Dan O. Dinges -- Chairman, President and Chief Executive Officer
Right, Jeffrey. Thank you. Look forward to seeing you also.
Operator
The next question comes from Charles Meade of Johnson Rice. Please go ahead.
Charles Meade -- Johnson Rice -- Analyst
Good morning, Dan to you and your team there. I was wondering if you could give us a little more detail, perhaps on the scale of that -- of that acquisition that you -- that you did, that extended the laterals? I think you gave us some parameters about how much you extended laterals but how many acres are we talking? Is it -- is it something where it's meaningful? You can talk about the -- the acquisition price that you put out there for it.
Dan O. Dinges -- Chairman, President and Chief Executive Officer
It was just like -- I don't have an exact. It's $2.5 million plus or minus is what there, 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 a 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 -- Johnson Rice -- Analyst
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 -- you know I recognized 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 will be living in 2020? And then maybe also you're 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 bank for your buck in 2020 than you have in the past. And so...
Dan O. Dinges -- Chairman, President and Chief Executive Officer
Yes. It's a great question and you know we're probably get beat up because we added a little bit of capital. We moved 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 three Bcf a day and we're managing that cadence if you will, that growth with three rigs and two frac crews. So as you bring on a pad or two, you look at the lumpiness that might occur on any given quarter, any two 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 would bring on a pad, ie, do we bring it on as we typically mind 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 may be forecast that win and that pad was forecast to be 200 million to 250 million cubics feet a day. You know it didn't take a lot of days or a slide in the schedule to affect how it affects your program, as an example. So we decided to delay this program, bringing on a pad that had that expectation in our forecast for four days.
All right, well that don'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 up and our program -- you all will take it with a grain of salt. That we are 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 a expectation 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 prices, the macro environment is I would be -- we are going to be looking at that service costs very diligently to see what it's going to take for annual service providers to join Cabot's team. We are -- and I'll add that we're very pleased with every provider we have out there today. 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 and we're going to have those negotiations ongoing here between now and the end of the year.
Charles Meade -- Johnson Rice -- Analyst
Dan, that's a helpful expansion on that theme. I appreciate it.
Operator
The next question comes from David Deckelbaum with Cowen. Please go ahead.
David Deckelbaum -- Cowen -- Analyst
Good morning, Dan and everyone, thanks for the time. I was just curious 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 like the curve is? Floating was $2 here.
Dan O. Dinges -- Chairman, President and Chief Executive Officer
You know, we have curtailed in the past our production. Back in -- what was it, 2015-2016? I know we -- and that was kind of the second quarter of 2016 for a period of time. We took a half -- curtailed half of BCF a day for a period of time because of the realizations. We're not afraid to do it again when we forecast that we make projections. We do have, and particularly in this environment. We do lean toward 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'll look at the screen this morning they -- I can say the first three months, the next three months are below $2.20. Well, if it directionally keeps going that way. We will have a response. And you know how you balance our response operationally, what we think our product is worth and trying to stay within the fair of way 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 will take the hits on the short term, but we're going to do what's right on the long-term.
David Deckelbaum -- Cowen -- Analyst
I appreciate that. If I could just ask on the free cash outlook for next year at 250 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 O. Dinges -- Chairman, President and Chief Executive Officer
Yes, we are -- you know we look at 2019, about -- a little over about 40 as our cash cost which includes financing. And so DD&A and all the 2020 forecast has -- is kind of right at it's a reduction, but kind of right at about 40. Is where we are and we expect in rolling forward that we'll continue to reduce the numbers from there.
David Deckelbaum -- Cowen -- Analyst
Got it. If I could just have one more. Just you talked about I think the maintenance capital assumption of $550 million to $575 million. Is that DNC or is that total corporate level? And I guess, do you see that improving going into 2021, just given the slowdown in 2020?
Dan O. Dinges -- Chairman, President and Chief Executive Officer
That's a good question. And Matt has been granular in this. So, Matt, you want to?
Unidentified Speaker --
Yes, David, this is Matt. That does include about $50 million of annual non-DNC capital but I think that's something that everyone needs to take into consideration when they're looking at our $725 million guide for next year. That was about $50 million there that goes into certain projects we're working on whether is 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 DNC capital is going to be significantly lower than that $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.
David Deckelbaum -- Cowen -- Analyst
Thank you, guys, I appreciate the color. Thanks, Matt.
Operator
The next question comes from Michael Hall of Heikkinen Energy Advisors. Please go ahead.
Michael Hall -- Heikkinen Energy Advisors -- Analyst
Thanks. A lot might have been addressed. On the maintenance capital front, just to follow up there on that question. I think you previously disclosed around $500 million of maintenance capital versus the $550 million to $575 million. I was just curious as to kind of what changed or is it accounted for in that? Then $50 million of annual non-DNC?
Dan O. Dinges -- Chairman, President and Chief Executive Officer
Yes. So, Michael, that number that we put out there that was really from two or three years ago and we were assuming at the time 2016 service cost prices which obviously we've seen a little bit of upward pressure since the -- the troughs of the service price environment since then. Additionally, we do have some incremental non-DNC capital like I alluded to. I mean we're spending $10 million this year on water trucks for our subsidiary. We're looking at some pad level, well level of compression projects that ultimately are 100% plus type IRR projects because they allow us to see production uplift, but ultimately 11 years into the program when you're producing at a $650 million and $700 million wells, 650 to 700 producing wells you just going to have ongoing capital that's outside of your drilling and completion program. So it's a little bit different as it's really an apples and oranges relative to that number from 2016.
Michael Hall -- Heikkinen Energy Advisors -- Analyst
Okay, understood.
Dan O. Dinges -- Chairman, President and Chief Executive Officer
Let me be really clear. We're not seeing any type of degradation and well productivity or capital efficiency or anything. This is just the nature of running a program that's close to three Bcf a day of production now and so this is just the reality of having this big of an operation
Michael Hall -- Heikkinen Energy Advisors -- Analyst
Different -- yes. I hear you and then I guess 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 guidance?
Dan O. Dinges -- Chairman, President and Chief Executive Officer
Well, we have as kind of referenced on the 2020. I mean, this year's guide on the capital with this eight-well program was an example of the 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 four incremental wells to our program at the -- at the end of the year. So you can kind of measure the efficiency gains in that way.
Michael Hall -- Heikkinen Energy Advisors -- Analyst
Okay. Yes, I guess specifically, I was just curious on like cost per well for a given lateral length. Do you have that?
Dan O. Dinges -- Chairman, President and Chief Executive Officer
It's still [Indecipherable] it's costs right now 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 few 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 lock-in transpire between now and year-end, as we start to ramp-up those negotiations.
Michael Hall -- Heikkinen Energy Advisors -- Analyst
Okay.
Dan O. Dinges -- Chairman, President and Chief Executive Officer
So the numbers that are out there right now, I would caution that you got up and our program -- you all will take it with a grain of salt. That we are 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 a expectation 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 prices, the macro environment is I would be -- we are going to be looking at that service costs very diligently to see what it's going to take for annual service providers to join Cabot's team. We are -- and I'll add that we're very pleased with every provider we have out there today. 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 and we're going to have those negotiations ongoing here between now and the end of the year.
Charles Meade -- Johnson Rice -- Analyst
Dan, that's a helpful expansion on that theme. I appreciate it.
Dan O. Dinges -- Chairman, President and Chief Executive Officer
Thanks, Charles.
Operator
The next question comes from David Deckelbaum with Cowen. Please go ahead.
David Deckelbaum -- Cowen -- Analyst
Good morning, Dan and everyone, thanks for the time. I was just curious 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 like the curve is? Floating was $2 here.
Dan O. Dinges -- Chairman, President and Chief Executive Officer
You know, we have curtailed in the past our production. Back in -- what was it, 2015-2016? I know we -- and that was kind of the second quarter of 2016 for a period of time. We took a half -- curtailed half of Bcf a day for a period of time because of the realizations. We're not afraid to do it again when we forecast that we make projections. We do have, and particularly in this environment. We do lean toward 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'll look at the screen this morning they -- I can say the first three months, the next three months are below $2.20. Well, if it directionally keeps going that way. We will have a response. And you know how you balance our response operationally, what we think our product is worth and trying to stay within the fair of way 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 will take the hits on the short term, but we're going to do what's right on the long-term.
David Deckelbaum -- Cowen -- Analyst
I appreciate that. If I could just ask on the free cash outlook for next year at 250 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 O. Dinges -- Chairman, President and Chief Executive Officer
Yes, we are -- you know we look at 2019, about -- a little over about 40 as our cash cost which includes financing. And so DD&A and all the 2020 forecast has -- is kind of right at it's a reduction, but kind of right at about 40. Is where we are and we expect in rolling forward that we'll continue to reduce the numbers from there.
David Deckelbaum -- Cowen -- Analyst
Got it. If I could just have one more. Just you talked about I think the maintenance capital assumption of $550 million to $575 million. Is that DNC or is that total corporate level? And I guess, do you see that improving going into 2021, just given the slowdown in 2020?
Dan O. Dinges -- Chairman, President and Chief Executive Officer
That's a good question. And Matt has been granular in this. So, Matt, you want to?
Unidentified Speaker --
Yes, David, this is Matt. That does include about $50 million of annual non-DNC capital but I think that's something that everyone needs to take into consideration when they're looking at our $725 million guide for next year. That was about $50 million there that goes into certain projects we're working on whether is 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 DNC capital is going to be significantly lower than that $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.
David Deckelbaum -- Cowen -- Analyst
Thank you, guys, I appreciate the color. Thanks, Matt.
Operator
The next question comes from Michael Hall of Heikkinen Energy Advisors. Please go ahead.
Michael Hall -- Heikkinen Energy Advisors -- Analyst
Thanks. A lot might have been addressed. On the maintenance capital front, just to follow up there on that question. I think you previously disclosed around $500 million of maintenance capital versus the $550 million to $575 million. I was just curious as to kind of what changed or is it accounted for in that? Then $50 million of annual non-DNC?
Dan O. Dinges -- Chairman, President and Chief Executive Officer
Yes. So, Michael, that number that we put out there that was really from two or three years ago and we were assuming at the time 2016 service cost prices which obviously we've seen a little bit of upward pressure since the -- the troughs of the service price environment since then. Additionally, we do have some incremental non-DNC capital like I alluded to. I mean we're spending $10 million this year on water trucks for our subsidiary. We're looking at some pad level, well level of compression projects that ultimately are 100% plus type IRR projects because they allow us to see production uplift, but ultimately 11 years into the program when you're producing at a $650 million and $700 million wells, 650 to 700 producing wells you just going to have ongoing capital that's outside of your drilling and completion program. So it's a little bit different as it's really an apples and oranges relative to that number from 2016.
Michael Hall -- Heikkinen Energy Advisors -- Analyst
Okay, understood.
Dan O. Dinges -- Chairman, President and Chief Executive Officer
Let me be really clear. We're not seeing any type of degradation and well productivity or capital efficiency or anything. This is just the nature of running a program that's close to three Bcf a day of production now and so this is just the reality of having this big of an operation
Michael Hall -- Heikkinen Energy Advisors -- Analyst
Different animal [Phonetic]. Yes. I hear you. And then I guess 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 guidance?
Dan O. Dinges -- Chairman, President and Chief Executive Officer
Well, we have as kind of referenced on the 2020. I mean, this year's guide on the capital with this eight-well program was an example of the 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 four incremental wells to our program at the -- at the end of the year. So you can kind of measure the efficiency gains in that way.
Michael Hall -- Heikkinen Energy Advisors -- Analyst
Okay. Yes, I guess specifically, I was just curious on like cost per well for a given lateral length. Do you have that?
Dan O. Dinges -- Chairman, President and Chief Executive Officer
It's still [Indecipherable] it's costs right now 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 few 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 lock-in transpire between now and year-end, as we start to ramp-up those negotiations.
Michael Hall -- Heikkinen Energy Advisors -- Analyst
Okay.
Dan O. Dinges -- Chairman, President and Chief Executive Officer
Yes, and I'll add to that on the lateral length. There is 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 -- Heikkinen Energy Advisors -- Analyst
And yes. You kind of -- you're hinting that toward -- what I was kind of getting there that thousand per foot is a good bit higher laying some of the peers down in the Southwest. Is there anything structural that would drive that higher level. Meaning like, the depth -- or is there some apples and oranges involved here do you think?
Jeffrey W. Hutton -- Senior Vice President, Marketing
I think you're hitting on that, it's apples and oranges. I mean I think what -- and where -- as Matt alluded to, we're in the next six 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 are not cherry-picking and excluding some aspects of what's going on the pad, ours has everything in it. And now that's probably the biggest difference, if you broke out every single piece you will find thing's piece missing in other areas by some and Cabot's will have everything in it.
Dan O. Dinges -- Chairman, President and Chief Executive Officer
Michael, there will be -- we don't see numbers out there, and I don't think that I don't react when I see numbers out there, that would be different in 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 in a number will be furnished to me. And we'll be able to manage.
Unidentified Speaker --
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've booked, that regardless of what the headline IR deck number is -- there it is.
Michael Hall -- Heikkinen Energy Advisors -- Analyst
Yes. And your recycle ratio is quite a bit better as well as you point out in your deck, so that's clear enough guys, I appreciate it. Thanks.
Operator
The next question comes from Paul Grigel with Macquarie. Please go ahead.
Paul Grigel -- Macquarie -- Analyst
Hi, good morning. Following up on the maintenance capex items; there was the comment that as the organization grows maintenance capex may go up overtime, 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 an offset by the kind of declines within the underlying corporate decline registered and I understand, maybe on a time-plus two or three years out where we should be thinking maintenance capex heads?
Dan O. Dinges -- Chairman, President and Chief Executive Officer
Paul, again -- Matt digs on these numbers, regularly but for home the color. So perhaps I missed 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 to 575 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 is 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 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 overtime 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 -- Macquarie -- Analyst
Okay. Now 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 in that $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 it's initial as opposed to maybe even a lower growth or true absolute maintenance capex program and another $100 million and $125 million plus to buyback stock or other uses for free cash flow?
Dan O. Dinges -- Chairman, President and Chief Executive Officer
Yes. Paul, it sounds like you are sitting in our room talking about it. We have many sensitivities on how we would guide on our group, 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 it's 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, that's $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 three rigs and two 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 straight maintenance then maybe we don't have three frac crews -- I mean, three rigs the entire year. Maybe the two 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 -- Macquarie -- 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 saves that for a better day?
Dan O. Dinges -- Chairman, President and Chief Executive Officer
Yes, there is that discussion and you know, 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, see the under. But for the long-term we think what we're doing is right for our long-term shareholders.
Unidentified Speaker --
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, and 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 non-core asset in a pipeline interest that we could monetize, also incrementally return to shareholders. So we think there will be plenty of opportunities to return cash to shareholders over the coming months and years.
Paul Grigel -- Macquarie -- Analyst
Okay. I appreciate all the color. Thanks, guys.
Dan O. Dinges -- Chairman, President and Chief Executive Officer
Thanks, Paul.
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 O. Dinges -- Chairman, President and Chief Executive Officer
Thanks, Chuck. And thank you all for the questions, forward-look, the question 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
[Operator Closing Remarks].
Duration: 51 minutes
Call participants:
Dan O. Dinges -- Chairman, President and Chief Executive Officer
Leo Mariani -- KeyBanc -- Analyst
Jeffrey W. Hutton -- Senior Vice President, Marketing
Brian Singer -- Goldman Sachs -- Analyst
Jeffrey Campbell -- Tuohy Brothers -- Analyst
Charles Meade -- Johnson Rice -- Analyst
David Deckelbaum -- Cowen -- Analyst
Unidentified Speaker --
Michael Hall -- Heikkinen Energy Advisors -- Analyst
Paul Grigel -- Macquarie -- Analyst
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