Q4 2019 Earnings Call
And fourth quarter and year end 2019 earnings call and webcast all participants will be in listen only mode should you need assistance. Please signal a conference specialist by pressing the Starkey followed by zero.
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I would now let's turn the conference over to Dan Dinges, Chairman President and CEO. Please go ahead.
Thank you Gary and good morning, all thanks for joining us today for Cabot's fourth quarter full year 2019 earnings call I do have the management team here with me today.
I'd 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, we'll refer to non-GAAP financial measures forward looking statements and other disclaimers as well as reconciliations to the most directly comparable GAAP financial measures were provided.
And yesterday's earning 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 and adjusted earnings per share 90% growth in free cash flow a return on capital employed.
22%, a return of $665 million of capital to shareholders through a combination of share repurchases and to 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 and 18% increase in production and a 11% increase in year end proved reserves.
And an 18% reduction and all in operating expenses per unit to $1.44 per thousand cubic foot equivalent and a reduction in net debt 2.7 times EBITDAX.
By all standards.
A very good year.
Specific to the fourth quarter of 19, despite declining natural gas prices, we still generated $121 million of adjusted net income or 30 cents per share and $110 million of free cash flow, while returning over 190% of our free cash flow for the quarter to.
To shareholders, we ended the fourth quarter with $200 million of cash on the balance sheet, which coupled with our expectations for a fifth consecutive year.
Free cash flow and 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 Yesterdays release, we provided the results of our upper Marcellus test from the last two years, which delivered an average you are.
Per thousand of approximately 2.7 Bcf. We believe these results highlight that our upper Marcellus as a distinct incremental anibal generates returns 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.
Or optimize lateral placement and completion designs. However, our recent results are relatively in line with the average EU our of 2.9 Bcf per thousand foot across all of our upper Marcellus drilled to date, which is a much larger sample size of over 50 wells.
And the release, we also made reference to over two decades or remaining inventory life, which is consistent with our measure.
Measuring over the past few years regarding our ability to continue to primarily focus on development plans on the lower Marcellus through the lateral latter part of this decade before moving to the full development of the upper Marcellus, which provides inventory life into.
To the 2040 decade. This assumes I returned a modest levels of growth in the future if the price environment warrants it.
In addition to the lower and upper Marcellus, we've 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 three results. We have seen to date are very encouraging.
Moving onto our plans for 2020.
Earlier this month, we announced our official 2020 plan, which included the adoption of previously disclosed maintenance capital program 575 million, representing a 27% reduction in capital spending year over year, our corporate strategy has always been centered around the.
Cute 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 net production rate of 2.4 Bcf.
Cubic foot per day up for the full year based on the current Nymex futures 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 million to $300 million of free cash flow, while delivering a return on capital employed.
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, and 2021 and a repair.
Fair to discuss capital spending reductions further if market conditions warranted guidance for 2020 includes modest sequential production declines in the first and second quarter, which we believe is prudent given the weakness in pricing we have experienced during the first quarter and expect to experience in the spring.
Under 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 futures curve has 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 pricing environment. We believe that current activity levels across the country are not sustainable at these prices and ultimately market for.
This is 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.
Giving our free cash flow outlook, and our strong balance sheet, we remain fully committed to continuing to return capital shareholders through a combination of dividend and opportunistic share repurchases. While also planning to pay down our current debt maturity later this year, while it is impossible.
To predict when the prices may improve even at the current strip prices for 21, and 22, we expect to expand our free cash flow yield and return on capital to levels that exceed and medium the S&P 500.
Larry with that more than happy to answer questions.
We will now begin the question and answer session.
To ask a question you May Press Star then one on your Touchtone phone.
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If at any time. Your question has been addressed and you would like to withdraw your question. Please press Star then too.
At this time, we will pause momentarily to assemble our roster.
Our first question comes from Charles Meade with Johnson Rice. Please go ahead.
Dan to you and you're seeing there.
Josh.
Hi.
Two questions both on on the inventory, but first starting with the lower Marcellus is I guess more housekeeping question can you talk about nine years of inventory is that on the.
2018, 2019 run rate of of just under 100 wells a year or is that on the go forward 20 rate of more like 65.
That it's an average of those two Charles.
Okay. Okay. That's helpful. And then a question on the on the upper Marcellus in it.
Appreciate which you would you offered in your release in their comments, but just wondering if you could take a little bit of time it did.
Characterize for us.
The the relative maturity or how far are long you are on the.
On the path of optimization of your of your completions, there and we look back at your history.
Several years ago now, but you guys moved the war per thousand feet of the lower Marcellus up.
The number of times to two to arrive at the point, where you are now and.
Wondering how much but were optimization you think there might be left whether you mentioned.
Lateral placement and and completion optimization, but footwear.
Obviously, no promises where could you see that 30.9 going perhaps in the upper parcels.
Well just them first set of facts on the upper Marcellus one.
As we referenced we've drilled.
Only 50 wells in the upper Marcellus compared to 700 or so in the in the lower Marcellus and the lower Marcellus.
We still look at.
Efforts and test on.
Where we're placing the lateral and how we Kuwait tweet 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.
These gathering the data with with the completion 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 with.
What weve used in the lower and trying to determine whether or not it's applicable in the upper rock.
The upper as as a point of reference is anywhere from.
No that the thickness is anywhere from say a 142.
Almost 300 feet in just the upper so lateral placement is going to be important and that.
Dennis of ice pack, we have looked at the.
Laying laying wells in various different sections.
That thick interval.
One one test we referenced was too to look at that deck, a banner Boland and asked we asked the question do we do we need to stagger and put.
Well in a higher.
Part of the upper and 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 a wells and we're not that good.
Wells, because we in 2020 hindsight.
Play 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 when you couple that with with.
A new legislative process it that the Pennsylvania legislator have approved in the fourth quarter.
2019.
It's allowing us to look at the development of the upper a little bit different than we're looking at the end that we had to implement in the lower.
In the lower.
Little bit long winded here, but maybe cover other questions that others might have by the answer in the lower we had unit designation sizes that.
That had us at certain lateral lengths, we can only go so far with unit designations with the certain lateral links in the in the lower and therefore, our for example, this last year. Our average lateral length was over eight 8000 feet in the lower but but never.
Unless.
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.
Very thick section like I mentioned.
There are only in a 170000 something acres. There is only 50 take points in that upper.
Upper section so when you look at that area.
Entirely in the upper its undeveloped section when we're looking at and what we're trying to do now by gathering information and trying to tweak landing laterals in all its going to help us lay out our development plan.
And with a new P.A. 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.
10, 12000 foot lateral that we're going to lay out in the in the upper is going to create its own efficiencies more.
More so than we realized in the 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 EU our per well that we see in the upper as opposed to what we realize and the lower.
Dan I appreciated the the long you call long winded, but I'll call. It is up there's a lot of a lot of useful details. So thank you for that.
Thanks Charles.
The next question is from Bryan singer with Goldman Sachs. Please go ahead.
Thank you good morning.
I'll Grant you wanted to start on the reserve report and to see if you could comment on the drivers of reserve revisions and any color that you can provide on the reserve adds in the impact that upper wells that may have had or you can try to kind of isolate the at the year on year effective drilling and adding lower.
Lower well.
Okay I'll make a.
Kind of a 5000 foot comment, Brian and I'll turn it to to stay lindemann, but.
And the our reserve revisions this year.
We had our learning curve and the proximal drilling with some of our our wells out there on the parent child kind of in the latter part of 18, beginning of 19 and we have.
When we when we.
Solve the impacts of that drilling and we've lost some wells not temporarily lose some wells or knocks them off with some of the Frac hits.
We take that learning curve and we see how we can mitigated in the future and that affect affected some of our our.
PDP revisions down by by these Frac hits, one of the things that we've been able to do.
With our learning curve through this period of time.
As as look at the results of now proximal drilling and all are all our future guidance and and our program is laid out taking in consideration that it's all going to be proximal drilling to existing wells.
And and and the mitigating factors that have.
Helped improve now are our expectations versus our initial learning curve is looking at our completion designs.
We have.
Looked at the reduce reduction in our fluid levels.
That has helped considerably we've also looked at the increase in clusters per stage is that has helped significantly on the offset affects.
We are also as I mentioned in the upper but in the lower also we're looking at lateral placements to see.
The impact and benefits of lateral placement when we're taking in proximal development.
We have also been using.
Retrieval bridge plugs that has mitigated the impact.
On offset wells, we've also tested.
Perforation hole sizes.
To accommodate our fluid levels of pumping and how we're laying out the clusters. So all of this has helped mitigate.
The impacts going forward, we did experience through to your point about revisions a particularly on the PD.
PDP side, some revisions on some wells, which.
Which.
We took our reserves off on some of those PDP, but some of those wells that we've taken reserve off we really havent gone back and on 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 handle some of our reserve bookings, Okay, Brian just to divide the revision into categories. We had 420 Bcf of positive revisions associated with our our Puds, that's a combination of drilling longer laterals and.
An increase in what our average booking would be for for Puds.
Per lateral length, and then we had a 350 bcf negative revision associated with some of the.
The data that Dan's discussed parent child relationships a lot of those occurred and wells that were stimulated in 2018 that we didnt realize the effect or see the effect into into 19, 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.
It 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 line pressure levels how.
Great. Thank you that's really really helpful color my follow up is that going back to the at the upper.
Upper Marcellus versus the lower Marcellus.
You mentioned, the lower Marcellus has that nine years of inventory, but based on some of your comment earlier.
Ultimately the lower in the upper going to be going to be co developed once you fully delineate the upper Marcellus then how do you think about that playing out from a percentage waiting perspective, as you guys contemplate a medium or longer term plans.
Yes, I'll let.
Phil kind of answer as he as a.
Plans, the future development, but I will I would say at this stage with the development, we have right now and 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.
Gas that comes from a a full develop pad in the in the lower.
Is is.
And we'll maximize the that local area.
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 a way from that particular area.
We've mentioned in the past we have multiple options to move gas around you will allocate away.
From that whereas we bring on those.
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 develop.
Thats correct in that being the plan is like Dan said is the go forward is primarily focus on the lower and get it developed out we will have some upper test again.
Tenure to try to optimize or upper upper as much as possible, but the plan is really to focus on the lower and then move up to the.
Thank you.
Thanks, Brian.
The next question is from Jeffrey Campbell with Tuohy Brothers. Please go ahead.
Hi, good morning, Dan.
Good morning Jeffrey.
My first question is kind of more of a thought exercise, but I'll explain why im asking it.
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.
Is the efficiency loss, such that maintaining a steady state at whatever level is preferable and and I ask this because.
Listening to all the calls most every in pesos, if theyre activity can respond to lower prices with lower activity, but the same reticent to increase activity.
Should there be increasing prices.
Well, let me answer it this way Jeffrey.
When.
Phil is.
Say looking at ahead for our future programs.
Today, we need to get out and you too Jeff and Bill can correct me on this but.
We need to be out and had about three 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 be delivering gas it 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 out ahead on designing these pad sites along with fills guys trying to do the logistics on the ground.
Roads pad site construction.
The permitting side looking at at a course, the equipment and personnel necessary. So.
I would say the ramp up it yes, it's a hell of a lot easier to cut off.
Purse strings, and and head down.
It is a little bit more challenging to ramp up.
Less than except if you had.
Maybe stranded capital and you had.
No.
Say, a frac crew or two teed up but you weren't going to pull the string on those until.
You know a year from now, but you, but you are paying some kind of rate to have them ready and available.
At that just in the next time.
But.
Ramping up is more difficult bottom line.
No that was really thorough answer I appreciate that.
And just going back to the.
Our 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 at the upper Marcellus development.
Maybe particularly on existing pads will eventually provide returns commensurate.
With the Carl lower Marcellus development.
If not why exhaust all the lower Marcellus inventory first.
Rather than blending them and trying to extend the inventory life for the lower Marcellus in that way.
Well, the well count that we have right now and need in the.
Lower Marcellus is.
It's it's prudent to develop the deeper as appose first prior to the upper as as you might suspect.
Take our 2020 program its maintenance program at 60 to 70 wells, we have a mix of upper wells in that.
In that program.
And.
How many paths do we have in our and our program for 22014 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 as we get deeper again, we have.
At this current drilling right about nine years remaining in the lower that's a pretty darn good runway when you when you think about it.
And as we get further out in that nine years to your point Jeffery.
We might develop ways.
Augmenting more of the upper into the pads that we can that we utilize to drill the longer.
Uppers.
And and use that as a tool to baby fully developed a pad here or there and our program.
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.
More lowers than than numbers.
Okay, well I appreciate that color. Thanks for entertaining the question Yeah, you bet.
The next question is from Holly Stewart with Scotia, Howard Weil. Please go ahead.
Good morning, gentlemen.
Alex.
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.
Commodity time.
Yes, all the above again.
Thanks for the question. We obviously, we remain very committed to returning at least 50% of our free cash flow to shareholders the level.
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 two small maturities in the next two years and our plan is to use part of that free cash flow.
Two.
Just pay that debt off which would further reduce our leverage about another $250 million, 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 bad and Dan's ban to port a little cash if it makes sense, because who knows where the strip is going to end up going.
Yep Yep.
That's helpful. And then Dan maybe then you mentioned the legislative change in your response to to Charles' question. It will allow you to drill.
More longer laterals in a lower I know you mentioned it in reference to the upper but will that help.
In terms of drilling more longer.
On the lower.
Yes, it will and and.
When you look at.
When you look at the lower development case, right now and where we have pads, where we have wells.
The opportunity because we have laid it out.
By virtue of the.
The confines we had in the past when we've laid out the lower that opportunity to drill longer laterals in the lower is certainly not as as readily available to us as it it it will be in the upper with the limited development Thats taken place so far in the us.
But yes, we're it every opportunity that fill in his guys has a have a chance to drill a longer lower we are doing so in fact.
One of these pads recently, we drilled what was the.
The length of the long.
This last year, we drilled we could add a total measured depth 25800 feet. So that was I was a record well for us that we just recently have have drilled yeah.
That's that's the exception because of what I, just mentioned, but where we had the opportunity to do that we are.
We are making that effort.
Okay, well, maybe just to follow up on that you mentioned and sort of an 8000 foot.
Average I guess for for 2019, it will it be.
Much longer than that on the lowers and Tony Tony.
No it will be.
Let's see Matt what will be Matt.
Our turn in lines for 20 is one of your expected average somewhere north of 85 underwriting.
Okay, so modestly I'm, a little bit longer okay, great. Thanks, guys.
Thanks.
The next question is from Josh Silver stream, So excuse me Silverstein with Wolfe Research. Please go ahead.
Thanks, Good morning, guys.
Just on the potential morning, just.
A couple of questions on the maintenance levels and Capex, you mentioned that you could put capex further.
Depending on where where prices are how does that work if you're currently at maintenance mode. Right. Now are you willing to go into declined due just reset the maintenance bar lower and how much capex would you be willing to cut.
Yes.
Our history in the past Josh as you might be aware, particularly in I think this was during the 16 period when.
When gas prices were extremely low, particularly in the shoulder months, we took a lot of gas off the market.
We curtailed over half a bcf a day and we're just not going to add to deliver gas at at a.
Below our our return profile that we would expect and what we'd need to see to be sustainable.
So our own our maintenance level and looking at rolling forward, we have an hour.
At our planned for 2020.
Excuse me.
We started out with.
Three rigs and we currently have three rigs.
At this point in time.
One of the rigs that and we and we've guided that we're going to go down to two rigs one of the rigs has been on a large pad and it's working its way off of that large pad and that'll that'll be lay down sometime in March.
But.
We're we're looking at all of our contracts or 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 we would absolutely do that if if need be.
Got it.
And then just given the price declines that we've had recently has this changed your corporate strategy of at all about saying.
Single piece and single asset focused company or would you want to add some other exposure.
Or Conversely, what 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 two part question I'll answer the second.
The first we 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 add thorough discussions about the question that you ask how do we enhance shareholder value and all all every meeting we've discussed.
The market the M&A the activities that are going on in the macro space the expectation of commodity pricing in the future both all that versus gas, we look at the oil gas and how they're dealing with with.
The issues that they deal with we look at the gas.
As on how they're dealing with their programs and the in the northeast we look at the the area around us is having some very very good.
Good wells.
Chesapeake has drilled some really good wells beside us.
And.
We could drill those wells, we would and we do also.
But.
To have an M&A transaction, it's just cumbersome, it's difficult up there there.
Where our area Theres about 100% operated and the areas that are west of us.
Yes, they are not 100% operated there's multiple partners that are in those those wells and and that creates its own uniqueness to to what you might.
What you might do if you had those assets or if you were the operator.
Those assets in southwest part of the state you have a lot of production going on in the southwest part of the state.
But the the balance sheets on some of those companies are.
Admittedly stressed at at this point in time, and they have maturities coming up that they're trying to deal with or their programs and and having that type of M&A conversation and all just.
Is extremely difficult.
When you look at a dual dual commodity split.
That there's there's circumstances that it would make sense.
But you also have to understand the area that you might go into the the the the capital allocation you'd have in the future neither accretion or dilution that you might have on that capital allocation and quite frankly, the you know when you look at the strip price for all right now.
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 to two environments to work in and operate in and also to commodities to dial levers.
And also but trying to make that come together get all the stars lineup all at one time, if a difficult proposition that's why it's not done every day.
Got it thanks guys.
Thanks, Jeff.
Next question is from Michael Hall, with Heikkinen Energy Advisors. Please go ahead.
Thanks I appreciate it.
Yes, I was just curious kind of more broadly on the 2020 program if there's any any particularly.
Substantial changes and just the character of the program as it relates to.
Compared to 2019 program completion design.
Access to surface infrastructure location in a field.
Any other variables now.
Maybe make program a little different.
Yep.
And I'm, all that either matter fill kind of get their thoughts together on it but when you look at our our program and you if you're comparing 19 to 20, you look at our program.
By design, our 19 program.
As a result of late innings drilling in 18.
We had to answer some of the questions, which I've already talked about about how we.
How we implement.
Technique changes on completions drilling laterals things like that to mitigate.
Proximal drilling so our 19 program was designed to answer some of those questions and and you know we had our learning curve and that showed up in some of our numbers we mitigate.
The numbers that that we presented at 19, even though a record year for Cabot, we've mitigated some of the concerns about proximal drilling.
By what we did when you when you look at our differences and a 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 the daylight that the PPA legislation created by the P.A. decision and now the longer laterals and then working into the the opportunity that Josh to ask a while ago. How we can maybe develop the upper in concert with the low.
Before we had a lot of wells and we were gathering a lot of data in the upper purposely far that program in 2020 compared to 19, we only have five wells design for the effort.
And the placement of some of our wells in our in our field are also going to be slightly different because in the queue of things.
When we when we have pads ready and they jump all over the field 2020 program is going to have a.
Less uppers and the locations of the the well the pads that we're going to drill and the 2020 is is going to be slightly enhanced in the geographic area that will drill compared to 19.
So we do anticipate.
2020 in a lot of areas is going to be and enhance program to 19.
Thats helpful color I appreciate and just be clear that 25, and the up for what were those all in 19 or with some of that and in 18, and just kind of the product productions tail gap.
Drilling drilling for the most part started in 18 and then it's both 18 and 19 almost 25.
Okay.
It's helpful. I appreciate it and then just kind of housekeeping on.
The timing of completions.
Obviously, you talked about the.
The sequential decline here in the first half what what are the kind of turned in line counts looked like as we start the year any color you can try there.
Yes.
In the end the first quarter.
We anticipate turning in approximately 13% of our total years total.
Well count and first quarter.
And the second quarter, where we'll have an incremental.
35, or so percent turned in at various months.
The fourth quarter April May June and then as we referenced and that's the reason why we're forecasting our our.
Reduction in.
First quarter second quarter, and then as those wells that we bring in in the second quarter majority impact is going to start in the third quarter.
We will bring on another 30 something percent in the in the third quarter and then fourth quarter were kind of schedule for about 15% or so of our turned inline wells.
That is super helpful. Thanks for the color. Thanks, 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 on well performance.
So as you think about the 2020 program should we expect that 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 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 add development as being drilling a well that is.
Unbounded or bounded by wells offsetting and our 2020 program is going to have more wells that have the offsets than our 2016 program. So on average yield you will see a say 2016 to 20.
20, you will see a basketball just any our basis.
Okay and assignment of maybe 10% to 12% less in 2020 now we might ahead in 2016 in the lower.
Got it Okay. That's helpful and then as my 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 Appalachian 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.
We don't repeat a 2025 years from now.
You know I ER scratch my head often and we have discussions in our boardroom often about the.
The macro environment.
The supply demand dynamics.
Both in oil and gas.
Hi, everybody has their own opinion and everybody looks at what's going on in the market in the reasons for it.
Everybody has the reasons why they might.
Grow any into a market that that we live in today and looking at the.
Realizations that are.
That are out there today, and and I think that financial numbers.
By the majority would dictate that.
If you if he had a vision that.
The current strip is going to be what it will be perpetually into the future to your point about five years six years from now I don't know why anybody would be drilling wells into as a as a growth measure into this market.
I am I.
I think it is a.
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 as Theres been changes and and.
Volume minimum volume commitments and different things that are affecting decisions out there.
We look at it.
As is.
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 two dollar Nymex, we still generate free cash.
Flow.
Will generate an earnings profile, and so and even us and there is 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 and push it out.
Not at a losing proposition we don't think is 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 as Scott has mentioned.
We're going to manage our debt towers as as we have two and will also reduce farther.
Maintenance capital and reduce as opposed to have the growth out there and what we see in the current environment in the foreseeable future. So I have a hard time rationalizing lie industry is growing into a market today.
Got it.
Helpful and hopefully some of the restart to see some of these rigs come off.
On a weekly.
This concludes our question and answer session I would like to turn the conference back over to advantages for any closing remarks.
Thanks, Gary good questions great questions I know our 19.
Had had some noise and our 19.
We're confident.
About our program and I hope this as answered all the questions that.
That I know that Matt has been building 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 in 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.
Our possession 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 has now concluded. Thank you for attending today's presentation you may now disconnect.
Okay.
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