Good morning, and welcome to the Cabot Oil and Gas Corporation 4th Quarter and Year End 2019 Earnings Call and Webcast. All participants will be in listen only mode. Please note this event is being recorded. I would now like to turn the conference over to Dan Dinges, Chairman, President and CEO. Please go ahead.
Thank you, Gary, and good morning, all. Thank you for joining us today for Cabot's 4th quarter full year 2019 earnings call. I do have the management team here with me today. I would first like to remind everyone that on this call, this morning, we will make forward looking statements based on our current expectations. Additionally, some of our comments will refer to non GAAP financial measures.
Forward looking statements and other disclaimers as well reconciliations to the most directly comparable GAAP financial measures were provided in yesterday's earnings release. For 2019, Cabot reported its best year in company history, while posting record levels of net income, operating cash flow, free cash flow, production, proved reserves and operating expense per unit. Some of the key highlights for the year include 41% growth in adjusted earnings per share, 90% growth in free cash flow, a return on capital employed of 22%, a return of $665,000,000 of capital to shareholders through a combination of share repurchases and 2 increases in our quarterly dividend per share. This represented a return of 118% of our free cash flow far exceeding our target of returning at least 50% of our annual cash flow, an 18% increase in production and a 11% increase in year end proved reserves and an 18% reduction in all in operating expenses per Unit 2, dollars 1.44 per 1,000 cubic foot equivalent and a reduction in net debt to 0.7x EBITDAX. I think by all standards, a very good year.
Specific to the Q4 of 2019, despite declining natural gas prices, we still generated $121,000,000 of adjusted net income or $0.30 per share and $110,000,000 of free cash flow, while returning over 190 percent of our free cash flow for the quarter to shareholders. We ended the 4th quarter with $200,000,000 of cash on the balance sheet, which coupled with our expectations for a 5th consecutive year of free cash flow in 2020 will allow us to continue to return a meaningful amount of capital to shareholders while also providing financial strength in a challenging market. On the operational front, in yesterday's release, we provided the results of our Upper Marcellus test from the last 2 years, which delivered an average EUR per 1,000 of approximately 2.7 Bcf. We believe these results highlight that our Upper Marcellus has a distinct incremental interval and it generates return that exceed the majority of assets across the basin. We plan to continue to test a limited number of Upper Marcellus wells annually to further optimize lateral placement and completion designs.
However, our recent results are relatively in line with the average EUR of 2.9 Bcf per 1,000 foot across all of our Upper Marcellus drill to date, which is a much larger sample size of over 50 wells. In the release, we also made reference to over 2 decades of remaining inventory life, which is consistent with our measuring over the past few years regarding our ability to continue to primarily focus on development plans on the Lower Marcellus through the latter part of this decade before moving to the full development of the Upper Marcellus, which provides inventory life into the 2,040 decade. This assumes a return to modest levels of growth in the future if the price environment warrants it. In addition to the lower and upper Marcellus, we have tested other concepts across our acreage position that would be incremental to our multi decade inventory life. While the testing of these concepts is still in the early phase, the results we have seen to date are very encouraging.
Moving on to our plans for 2020. Earlier this month, we announced our official 2020 plan, which included the adoption of previously disclosed maintenance capital program $575,000,000 representing a 27% reduction in capital spending year over year. Our corporate strategy has always been centered around the acute focus on disciplined capital allocation and we believe this reduction in capital further demonstrates our commitment to that philosophy. Our 2020 program is projected to deliver an average production rate of 2.4 Bcf cubic foot per day for the full year. Based on the current NYMEX future curve, this plan is expected to generate enough free cash flow to cover our dividend, while also providing a modest amount of excess free cash flow for further returns of capital to shareholders or debt repayment.
At a $2.25 average NYMEX price, the plan is expected to generate $275,000,000 to $300,000,000 of free cash flow while delivering a return on capital employed of 11% to 12%. Not too many programs can represent that. We believe our current plan is the appropriate level of capital investment in this market environment. However, we will continue to assess the outlook for the natural gas market in 2020 2021 and are prepared to discuss capital spending reductions further if market conditions warrant it. Our guidance for 2020 includes modest sequential production declines in the 1st and second quarter, which we believe is prudent given the weakness in pricing we've experienced during the Q1 and expect to experience in the spring shoulder season.
We are currently forecasting an increase in production beginning in the second half of the year, which corresponds with improvement in prices across the NYMEX future curve. As we look to 2021, while it's too premature to issue any formal guidance given the likelihood of continued volatility and commodity prices throughout the year, I would expect us to adopt a similar program next year if natural gas prices were to remain lower for the foreseeable future. I would also add that while we are fully prepared for a continuation in this lower natural gas price environment, we believe that current activity levels across the country are not sustainable at these prices and ultimately market forces should move natural gas supply and demonstrate a more sustainable balance in the future. 2020 could prove to be one of the most challenging natural gas markets in recent history. However, we continue to believe our business model is uniquely positioned to navigate through the market environment, giving our combination of low cost assets and low leverage position.
Given our free cash flow outlook and our strong balance sheet, we remain fully committed to continuing to return capital to shareholders through a combination of dividend and opportunistic share repurchases, while also planning to pay down our current debt at maturity later this year. While it is impossible to predict when the prices may improve, even at the current strip prices for 'twenty one and 'twenty two, we expect to expand our free cash flow yield and return on capital to levels that exceed the medium of the S and P 500. Gary, with that, I'm more than happy to answer questions.
We will now begin the question and answer session. Our first question comes from Charles Meade with Johnson Rice. Please go ahead.
Good morning, Dan, to you and your team there.
Hello, Charles.
Dan, I have two questions, both on inventory. But first, starting with the Lower Marcellus, this is, I guess, more of a housekeeping question. When you talk about 9 years of inventory, is that on the 2018, 2019 run rate of just under 100 wells a year? Or is that on the go forward 'twenty rate of more like 65?
It's an average of those 2, Charles.
Okay. Okay. That's helpful. And then a question on the Upper Marcellus. And I appreciate what you offered in your release and your prepared comments.
But I was wondering if you could take a little bit of time and characterize for us the relative maturity or how far along you are on the completions there? And if we look back at your history, it's several years ago now, but you guys moved the EUR per 1,000 feet of the Lower Marcellus up a number of times to arrive at the point where you are now. And I'm just wondering how much more optimization you think there might be left, whether you mentioned lateral placement and completion optimization, but where obviously no promises, but where could you see that 2.9 going perhaps in the Upper Marcellus?
Well, just a first set of facts on the Upper Marcellus. 1, as we referenced, we've drilled only 50 wells in the Upper Marcellus compared to 700 or so in the Lower Marcellus. And in the Lower Marcellus, we still look at efforts and tests on where we're placing the lateral and how we tweak completions. With the Upper Marcellus, we drilled some early stage Upper Marcellus wells that are in that 50 count. With those early stage completions, we were just gathering the data with generation completions we had at that particular time.
As we have moved forward with trying to utilize what we've learned in the lower and apply it to the upper, we continue to tweak the results we've seen in some of the upper wells with what we've used in the lower and trying to determine whether or not it's applicable in the upper rock. The upper as a point of reference is anywhere from the thickness is anywhere from, say, 140 to almost 300 feet in just the upper. So lateral placement is going to be important in that thickness of ice pack. We have looked at the laying wells in various different sections of that thick interval. One test we referenced was to look at that thick of interval and we asked the question, do we need to stagger and put a well in the higher part of the upper and the lower part of the upper and see if we can maximize drainage effectiveness of return and so forth by doing so.
Couple of the wells that we laid got a little bit too low in the Upper Marcellus and those were not that effective wells and were not that good of wells because we in 2020 hindsight laid the laterals a little bit too low. But that learning curve Charles to your point is going to continue for an extended period of time. And when you couple that with a new legislative process that the Pennsylvania legislature have approved in the Q4 of 2019, it's allowing us to look at the development of the upper a little bit different than we're looking at the and that we had to implement in the lower. In the lower, and I'm a little bit long winded here, but I'll maybe cover other questions that others might have by the answer. In the lower, we had unit designation sizes that had us at certain lateral lengths.
We could only go so far with the unit designations with these certain lateral lengths in the lower. And therefore, for example, this last year, our average lateral length was over 8,000 feet in the lower, but nevertheless, we have drilled some where we could that extended that laterally, gain of efficiencies, a little bit lower cost per foot and things like that. In the upper, it's our expectation that when you look at the entire upper section, a very thick section like I mentioned, there are only in 170,000 something acres, there's only 50 take points in that upper section. So when you look at that area entirely in the upper, it's an undeveloped section. When we're looking at what we're trying to do now by gathering the information and trying to tweak landing laterals and all, it's going to help us lay out our development plan.
And with the new PAA that the legislation approved up there, it's going to allow us to lay out the upper in a way that will facilitate probably plus or minus over 40% longer laterals than the laterals we drilled this year in the lower. So that 10000, 12000 foot lateral that we're going to lay out in the upper is going to create its own efficiencies more so than we realized in the lower. And with that development layout, it is our anticipation that we're going to narrow the gap on the return profile on the delta between the EUR per well that we see in the upper as opposed to what we realize in the lower.
Dan, I appreciated the long you call it long winded, but I'll call it as a lot of useful details. So thank you for that.
Thanks, Charles.
The next question is from Brian Singer with Goldman Sachs. Please go ahead.
Thank you. Good morning. Hi, Brian. I wanted to start on the reserve report and just see if you could comment on the drivers of reserve revisions and any color that you can provide on the reserve adds and the impact that upper wells that may have had or you could try to kind of isolate the year on year effect of drilling and adding lower well?
Okay. I'll make a kind of a 5,000 foot comment, Brian, and I'll turn it to Steve Lineman. But in the our reserve revisions this year, we had our learning curve in the proximal drilling with some of our wells out there on the parent child kind of in the latter part of 2018, beginning of 2019. And we have when we saw the impacts of that drilling and we lost some wells, not temporarily lose some wells or knock some off with some of the frac hits, hits. We take that learning curve and we see how we can mitigate it in the future and that affected some of our PDP revisions down by these frac hits.
One of the things that we've been able to do with our learning curve through this period of time is look at the results of now proximal drilling and all our future guidance and our program is laid out taking in consideration that it's all going to be a proximal drilling to existing wells. And the mitigating factors that have helped improve now our expectations versus our initial learning curve is looking at our completion designs. We have looked at the reduction in our fluid levels that has helped considerably. We've also looked at the increase in clusters per stages that has helped significantly on the offset effects. We are also, as I mentioned, in the upper, but in the lower also, we are looking at lateral placements to see the impact and benefits of lateral placements when we're taking in proximal development.
We have also been using retrievable bridge plugs that has mitigated the impacts on offset wells. We have also tested perforation hole sizes to accommodate our fluid levels of pumping and how we are laying out the cluster. So all of this has helped mitigate the impacts going forward. We did experience through to your point about revisions and particularly on the PDP side, some revisions on some wells, which we took reserves off on some of those PDP, but some of those wells that we've taken reserve off, we really haven't gone back and done the workover on say a handful of those wells. So that's kind of a higher level and I'll let Steve add to how you handled some of our reserve bookings.
Okay. Brian, just to divide the revision into categories, We had 4.20 Bcf of positive revisions associated with our PUDs. That's a combination of drilling longer laterals and an increase in what our average booking would be for PUDs per lateral length. And then we had a 3 50 Bcf negative revision associated with some of the data that Dan's discussed, parent child relationships. A lot of those occurred in wells that were stimulated in 2018 that we didn't realize the effect or see the effect into 2019.
But as Dan indicated, we've taken a number of remediation steps to improve and to mitigate some of this parent child relationship. And then there was roughly about 30 Bcf or 10% that was impacted negatively to short term line pressure gains in the field from turning offset pads on. And like Dan indicated, that should come back in future bookings as the line pressure levels out.
Great. Thank you. That's really helpful color. My follow-up is going back to the Upper Marcellus versus the Lower Marcellus. You mentioned the Lower Marcellus has that 9 years of inventory.
But based on some of your comments earlier, is ultimately the lower and the upper going to be co developed once you fully delineate the upper Marcellus? And how do you think about that playing out from a percentage weighting perspective as you guys contemplate a medium or longer term plan?
Yes. I'll let Phil kind of answer as he plans the future development. But I would say at this stage with the development we have right now on say the 700 or so lowers and where we're going back on a pad, one of the things you have to keep in mind is when we go back into an area, the amount of volume of gas that comes from a full developed pad in the lower is and will maximize that local area of gas going into our header system, our gathering system. So the marketing group, Jeff, is always allocating when we're going to bring on a large pad is always allocating away from that particular area. As we've mentioned in the past, we have multiple options to move gas around.
You'll allocate away from that as we bring on those lower wells. But the majority of the future, I think, is going to be developed from the lower and moving up with some mixed in there, uppers mixed in there to gather additional data points. But I believe that's how it's going to be developed. Phil?
Yes, that's correct, Dan. I mean, the plan is, like Dan said, is to go forward is primarily focused on the lower and get it developed out. We will have some upper test again, continue to try to optimize our upper as much as possible, but the plan is really to focus on the lower and then move up to the upper.
Thank you.
Thanks, Brian.
The next question is from Jeffrey Campbell with Tuohy Brothers. Please go ahead.
Good morning, Dan.
Good morning, Jeffery.
My first question is kind of more of a thought exercise, but I'll explain why I'm asking it. The question is, if the nat gas market continues to be volatile for years, is it possible to design a contingency program to ramp activity up or down in response? Or is the efficiency loss such that maintaining a steady state at whatever level is preferable? And I ask this because listening to all the calls, most every E and P says that their activity can respond to lower prices with lower activity. But they seem reticent to increase activity should there be increasing prices?
Well, let me answer it this way, Jeffrey. When Phil is, say, looking out ahead for our future programs, we today, we need to get out and you too, Jeff and Phil can correct me on this, but we need to be out ahead about 3 years, if you will, in order to coordinate the marketing side of our program to allow Williams to have the appropriate lines, to evaluate the amount of gas that we're going to be bringing and I'm talking about a growth program and building up that's going to be delivering gas at certain areas, certain compressor sites to be able to move the gas without having negative effects of higher line pressure and knocking wells off. So they are way ahead on designing these pad sites along with Phil's guys trying to do the logistics on the ground of roads, pad site construction, the permitting side, looking at, of course, the equipment and personnel necessary. So I would say the ramp up, yes, it's a hell of a lot easier to cut off the purse strings and head down. It is a little bit more challenging to ramp up, less and except if you had maybe stranded capital and you had, say, a frac crew or 2 teed up, but you weren't going to pull the string on those until a year from now, but you were paying some kind of rate to have them ready and available at that just in the neck of time.
But ramping up is more difficult, bottom line.
Yes. Well, no, that was a really thorough answer. I appreciate that. And just going back to the Upper Marcellus briefly, just kind of a conceptual question here, particularly with the longer laterals that you talked about, the ability to drill longer ones. Is the expectation that the Upper Marcellus development, maybe particularly on existing pads, will eventually provide returns commensurate with the current Lower Marcellus development?
And if not, why exhaust all the Lower Marcellus inventory first rather than blending them and trying to extend the inventory life of the Lower Marcellus in that way?
Well, the well count that we have right now in the Lower Marcellus is it's prudent to develop the deeper as opposed first prior to the upper as you might suspect. Take our 2020 program, it's a maintenance program, it's 60 to 70 wells. We have a mix of upper wells in that program. And how many pads do we have in our program for 2020, 14 or plus or minus 14, 15 pads in our 2020 program. And going back to my comment about how we handle the efficiency of development, bringing on the gas, providing the best opportunity for our rate of return.
We try to move things through fairly rapidly. And the development of the lower is it's more efficient to develop the deeper. I understand your concept and as we get deeper, again, we have at this current drilling rate about 9 years remaining in the lower. That's a pretty darn good runway when you think about it. And as we get further out in that 9 years, to your point, Jeffrey, we might develop ways of augmenting more of the upper into the pads that we can that we utilize to drill the longer uppers and use that as a tool to maybe fully develop a pad here or there in our program of all the zones as opposed to just the lower and having to come back.
That's entirely plausible in the future. Kind of right now, our program, certainly for 2020, is designed for more lowers than buffers.
Okay. Well, I appreciate that color. Thanks for entertaining the question.
Yes, you bet. The next
question is from Holly Stewart with Scotia Howard Weil. Please go ahead.
Good morning, gentlemen. Maybe first, Scott, can we just talk about some updated thoughts around returning capital to shareholders, just balancing the buyback, the dividend, as well as maybe hoarding some cash given we're in pretty unique commodity times?
Yes, all of the above. Again, thanks for the question. We obviously remain very committed to returning at least 50% of our free cash flow to shareholders. The level how much is covered by the dividend is going to be obviously a function of what the NYMEX strip is going forward. But we're looking at it exactly like you said.
The other thing I would add in there, which I thought you were going to ask is, we have 2 small maturities in the next 2 years and our plan is to use part of that free cash flow to just pay that debt off, which would further reduce our leverage about another $250,000,000 which in this environment makes a lot of sense. But we'll be opportunistic on buybacks when appropriate. But at the same time, I'm not opposed with my bent and Dan's bent to hoard a little cash if it makes sense because who knows where the strip is going to end up going.
Yes. Yes. That's helpful. And then, Dan, maybe the you mentioned this legislative change in your response to Charles' question. Will it allow you to drill more longer laterals in the lower?
I know you mentioned it in reference to the upper, but will that help in terms of drilling more longers on the lower?
Yes, it will. And when you look at the lower development case right now, where we have pads, where we have wells, the opportunity because we have laid it out by virtue of the confines we had in the past when we've laid out the lower that the opportunity to drill longer laterals in the lower is certainly not as readily available to us as it will be in the upper with the limited development that's taken place so far in the upper. But yes, every opportunity at Phil and his guys have a chance to drill a longer lower, we are doing so. In fact, one of these pads recently we drilled what was the length of the long this
last year we drilled? We just had a total measured depth of 25,800 feet. So that was a record well for us that we just recently have drilled.
Yes. That's the exception because of what I just mentioned. But where we have the opportunity to do that, we are making that effort.
Okay. Well, maybe just to follow-up on that, you mentioned sort of an 8,000 foot average, I guess, for 2019. Will it be much longer than that on the lowers in 2020?
No, it'll be let's see, Matt, what will it be, Matt?
Our turbine lines for 2020 are expected to average somewhere north of 8,500,
think. Okay. So modestly, a little bit longer. Okay, great. Thanks guys.
Thanks, Hollis.
The next question is from Josh Silverstein with Wolfe Research. Please go ahead.
Thanks. Good morning, guys. Just on the potential good morning. Just to ask a couple of questions on the maintenance levels and CapEx. You mentioned that you could cut CapEx further depending on where prices are.
How does that work if you're currently at maintenance mode right now? Are you willing to go into decline? Do you just reset the maintenance bar lower? And how much CapEx would you be willing to cut?
Our history in the past, Josh, as you might be aware, particularly and I think this was during the 'sixteen period when gas prices were extremely low, particularly in the shoulder months, we took a lot of gas off the market. We curtailed over 0.5 Bcf a day and we're just not going to deliver gas at a below our return profile that we would expect and what we'd need to see to be sustainable. So, on our maintenance level and looking at rolling forward, we have in our plan for 2020, we started out with 3 rigs and we currently have 3 rigs at this point in time. One of the rigs that and we've guided that we're going to go down to 2 rigs. One of the rigs has been on a large pad and it's working its way off of that large pad and that will be laid down sometime in March.
But we're looking at all of our contracts, our service contracts that would provide the coverage that our service providers need, but also provide us the flexibility that we need to amend our plan if in fact the macro environment dictates. And we would absolutely do that if need be.
Got it. And then just given the price decline that we've had recently, has this changed your corporate strategy at all about staying a single basin, single asset focused company? Or would you want to add some other exposure? Or conversely with the basin feeling pain right now, is there opportunity for you guys to add some flowing volume in inventory right around where you are?
Well, a 2 part question. I'll answer the second the first. We have always had strategic in Boardroom discussions on how we maximize shareholder value. That will continue. We just had our Board meeting this week.
We had thorough discussions about the question that you asked, how do we enhance shareholder value? And all every meeting we've discussed the market, the M and A, the activities that are going on in the macro space, the expectation of commodity pricing in the future both oil versus gas. We look at the oil guys and how they're dealing with the issues that they deal with. We look at the gas guys on how they're dealing with their programs. And in the Northeast, we look at the area around us as having some very, very good wells.
Chesapeake has drilled some really good wells beside us. And if we could drill those wells, we would and we do also. But to have an M and A transaction, it's just cumbersome. It's difficult. Up there, there where our area up there is about 100% operated and the areas that are west of us, they're not 100% operated.
There's multiple partners that are in those wells and that creates its own uniqueness to what you might do if you had those assets or if you were the operator of those assets. In the Southwest part of the state, you have a lot of production going on in the Southwest part of the state, but the balance sheets on some of those companies are admittedly stressed at this point in time and they have maturities coming up that they're trying to deal with through their programs and having that type of M and A conversation and all just is extremely difficult. When you look at a dual commodity split, that there's circumstances that it would make sense, but you also have to understand the area that you might go into, the capital allocation you'd have in the future, the either accretion or dilution that you might have on that capital allocation. And quite frankly, the when you look at the strip price for oil right now and you look at the strip price for natural gas right now, Cabot delivers a very, very good return profile compared to all the wells that are being drilled out there and all the programs that are being drilled out there.
So do I think at times it would have a benefit? Absolutely, it would if we had 2 environments to work in and operate in and also 2 commodities to dial levers in also. But trying to make that come together, get all the stars lineup all at one time, it's a difficult proposition. That's why it's not done every day.
Got it. Thanks guys.
Thanks Josh.
The next question is from Michael Hall with Heikkinen Energy Advisors. Please go ahead.
Thanks. I appreciate it.
I guess I was just curious kind
of more broadly on the 2020 program, if there's any particularly substantial changes in just the character of the program as it relates to how it compared to the 2019 program, be it completion design, access to surface infrastructure, location in the field, any other variables now that would maybe make the program a little different?
Yes. And I'm going to let either Matt or Bill kind of get their thoughts together on it. But when you look at our program and if you're comparing 2019 to 2020, you look at our program by design our 2019 program as a result of late innings drilling in 2018, we had to answer some of the questions, which I've already talked about, about how we implement technique changes on completions, drilling, laterals, things like that to mitigate proximal drilling. So our 2019 program was designed to answer some of those questions and we had our learning curve and that showed up in some of our numbers. We've mitigate the numbers that we presented in 2019, even though a record year for Cabot, we've mitigated some of the concerns about proximal drilling by what we did.
But when you look at our differences in the 60 or 70 wells, we had 25 wells that we designed specifically for the upper to try to get ahead of our program and learn about how we now because we had the daylight that the PA legislation created by the PAA decision and now the longer laterals and then working into the opportunity that Josh asked a while ago, how we can maybe develop the upper in concert with the lower. We had a lot of wells and we were gathering a lot of data in the upper purposely for that program. In 2020 compared to 2019, we only have 5 wells designed for the upper. And the placement of some of our wells in our field are also going to be slightly different because in the queue of things, when we have pads ready and they jump all over the field, 2020 program is going to have less uppers and the locations of the well of the pads that we're going to drill in the 2020 is going to be slightly enhanced in the geographic area that we'll drill compared to 2019. So we do anticipate 2020 in a lot of areas is going to be an enhanced program to 2019.
That's helpful color. I appreciate it. And just
to be clear, the 25 in
the upper, were those all in 2019 or was some of that in 2018 and just kind of the production is tailing to?
Yes. Drilling for the most part started in 2018 and then it's both 2018 and 2019, almost 25. Okay. That's almost 25.
Okay. That's helpful. I appreciate it. And then just kind of housekeeping on just the timing of completions. Obviously, you talked about the sequential decline here in the first half.
What are the kind of turn in line counts look like as we start the year here? Any color you can provide there?
Yes. In the Q1, we anticipate turning in approximately 13% of our total year's total well count in Q1. And in the Q2, we'll have an incremental 35% or so turned in at various months of the Q4 April, May, June. And then as we referenced and that's the reason why we're forecasting our reduction in Q1, Q2. And then as those wells that we bring in the 2nd quarter, majority impact is going to start in the 3rd quarter.
We'll bring on another 30 something percent in the Q3. And then the Q4, we're kind of scheduled for about 15% or so of our turn in line wells.
That is super helpful. Thanks for the color. Thanks
guys. You bet.
The next question is from Kashy Harrison with Simmons Energy. Please go ahead.
Good morning. So just a quick follow-up to the earlier discussions on well performance. So as you think about the 2020 program, should we expect the longer term well performance to be maybe more similar to 2016, 2017 levels on a lateral adjusted basis?
It depends on where the wells are going to be located. If for example, if you and keep in mind, we have forecast our program to take into account the proximal development, which you can look at development as being drilling a well that is unbounded or bounded by wells offsetting you. And our 2020 program is going to have more wells that have the offsets than our 2016 program. So on average, you will see a say 2016 to 20 20, you'll see about just an EOR basis, an assignment of maybe 10% to 12% less in 2020 than we might have had in 2016 in the lower.
Got it. Okay. That's helpful. And then as my second question, Dan, excuse me, sorry. As you think about just the various forces at work in the natural gas market, Once you move beyond 2020, how do you think about the appropriate medium term gas growth rate in Appalachia and Haynesville necessary to meet incoming demand?
Do you think operators need to be growing by 1%, 2%, 3%, just to make sure that the market doesn't get out of whack so that we don't repeat a 20, 25 years from now?
I scratch my head often and we have discussions in our macro environment, the supply demand dynamics both in oil and gas. Everybody has an opinion and everybody looks at what's going on in the market and the reasons for it. Everybody has the reasons why they might grow any into a market that we live in today and looking at the realizations that are out there today. And I think the financial numbers by the majority would dictate that if you had a vision that the current strip is going to be what it will be perpetually into the future to your point about 5 years, 6 years from now, I don't know why anybody would be drilling wells into as a growth measure into this market. I think it is a difficult to for me to sit in every chair out there and the reasons behind it.
I do know there's reasons that are attached to debt positions and balance sheet concerns. I know there's reasons why maybe firm transportation arrangements might be dictating how you allocate capital. There has been midstream negotiations and separations upstream from midstream. There's been changes in volume minimum volume and commitments in different things that are affecting decisions out there. We look at it as how we can manage the shareholder value in a way that is going to yield a return.
We've been able to point to the fact that at a $2 NYMEX, we still generate free cash flow. We'll generate an earnings profile. And so and even us, and there's nobody else that can make that statement, we are at a maintenance level capital because we don't think it is prudent to drill up all your core inventory and push it out at a losing proposition. We don't think it's prudent to drill even at a marginal return profile and use it all up in this particular environment. So we're going to keep our balance sheet strong.
We're going to manage our dividend. As Scott has mentioned, we're going to manage our debt towers as we have to. And we'll also reduce further maintenance capital and reduce as opposed to have the growth out there in what we see in the current environment in the foreseeable future. So, I have a hard time rationalizing why industry is growing into a market today.
Got it. That's very helpful. And hopefully, some of the we start to see some of these rigs come off on a weekly basis.
This concludes our question and answer session. I would like to turn the conference back over to Dan Dinges for any closing remarks.
Thanks, Gary. Good questions, great questions. I know our 2019 had some noise in our 2019. We're confident about our program and I hope this has answered all the questions that I know that Matt has been fielding all the way into the early mornings. But again, our macro outlook for gas is cautious at this point in time.
I do think just like the last question and answer demonstrated, rationalization is going to have to prevail in this market that's not sustainable and the balance sheets are not sustainable out there trying to push this market and grow into this market. And we think we are the best position in our space to navigate. We're going to be the last man standing and we're going to take advantage of our position, maintain our balance sheet, serve our shareholders hopefully in a way that the long term shareholders would appreciate and be good stewards of our capital. So thanks again for your patience for 2019. I hope you all are looking forward to 2020.
The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.