Q3 2023 Callon Petroleum Co Earnings Call

November 2, 2023

After the prepared remarks, there will be a question and answer session. Please.

Please note that each caller will be limited to one question and one follow up question.

Just as a reminder, today's conference call is being recorded.

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I would now like to turn the call over to Collin CFO, Kevin Haggard. Please go ahead Sir.

Thanks, operator, and good morning, everyone apologies, we had a little hiccup with the link to the webcast I think we're now all in and there'll be a recording afterwards. So we appreciate your interest in Cowen with me today are our CEO, Joe Gatto and our CFO Russell Parker, we will happily take your questions at the end of our prepared remarks, we will run.

Our third quarter earnings release, and supplemental slides, which are available on our website under the investors tab on today's call will also include forward looking statements that refer to estimates and plans.

Results could differ materially due to risk factors noted in our presentation and SEC filings. We will also refer to some non-GAAP financial measures, which we believe help facilitate comparisons across periods and with our peers.

For any non-GAAP measures referenced we provide a reconciliation to the nearest corresponding GAAP measures in the appendix to our slide deck and our earnings press release, both of which are available on our website with that I will now turn the call over to Joe. Thank.

Thank you Kevin good morning, everyone.

<unk> posted solid results for the third quarter, marking our 14th consecutive quarter of adjusted free cash flow generation cash flow.

Are using to reduce debt and repurchase our shares.

Our corporate priorities are clear we are focused on maximizing free cash flow aggressively driving down our cost structure, reducing absolute debt and returning cash to owners through our share buyback program.

I'll divide today's call into three segments.

First I'll summarize third quarter financial and operating results overall, it was a good quarter with total production and key operating costs in line with expectations and capital investments below guidance.

However, we did experienced some headwinds related to our near term oil production, which I will address shortly.

Second I will cover our unrelenting focus on safely driving cost out of the system and creating sustainable operational efficiencies our focus on financial and operational cost controls was producing impressive gains.

Pay increasing dividends into 2024 in terms of both free cash flow generation and lower breakeven prices for our Permian inventory.

Next I want to spend a bit of time on the sustainable benefits of our life of field Codevelopment model. This is an ongoing and proven development process that maximizes long term value of inventory, where real time learnings are then applied to future capital investments, we continue to see well productivity of Cowen is moving counter to industry trends. However, we.

We need to continue to optimize that model over time with new information in order to properly balance near term returns with longer term opportunities lastly.

Lastly, I will conclude with some early thoughts on 2020 for a recent efficiency gains in both drilling and completions are expected to be sustainable and will allow us to maximize value in 2024 through the enhancement of two key financial metrics capital efficiency and free cash flow conversion of EBITDA.

Let's get started with third quarter results for the third quarter total production averaged 102000 Boe per day oil sales averaged about 58000 barrels per day.

The shortfall in oil volumes is related to two key factors first extreme temperatures and related power and midstream issues, we experienced in July which we discussed on the Q2 call continued into August and September in the Delaware basin, especially in our oil or areas like Delaware East.

Power outages impacted our electrical submersible pump program and reduced expected oil volumes due to downtime days as well as the time to ramp the ESP is back to normal operating levels.

Factors related to oil production from recent multi zone projects in the Delaware West are most gas weighted area.

About one half of our third quarter turned in lines or 15 of the 33 were in Delaware West.

While total production on a BOE basis from recent completions was relatively in line with expectations gas oil ratios were much higher than expected declining.

The commodity mix from these wells will also have an impact on our fourth quarter oil volumes.

As an additional note we recently accelerated change in our Delaware Basin artificial lift program that was previously slated to start in 2024 to improve uptime performance.

Program will incorporate an increasing proportion of gas lift installs relative to asps overtime to reduce production downtime from power and weather events, lower workover expense and enhanced longer term resource recovery.

In the fourth quarter, we do see some negative impacts production is compression related equipment is procured procured installed in areas where nearby gas lift installations don't exist.

With the program up and running this quarter and firmly incorporated into our planning process. We don't expect to see this timing issue going forward.

Overall, we expect fourth quarter oil production in a range of 56 to 59000 barrels per day with total production in the range of 100 to 103 Boe per day.

Comprised of approximately 79% liquids as part of our fourth quarter activity. We expect to turn 14 gross wells in line in the fourth quarter in our earlier areas, the Delaware and Midland Basin, which will benefit our 2020 for mix.

Our forecasted capital investments for both full year and fourth quarter 2023 remain unchanged.

An increase in drilling and completion activity driven by improving cycle times that I will hit upon in a minute.

This clearly demonstrates the cost efficiencies we are realizing today.

The corollary to the cost and capital efficiencies. We are experiencing is that we are improving our rate of conversion of EBITDAX to adjusted free cash flow in today's deck.

We show how this conversion has increased throughout the year.

A few additional points to highlight.

G&A costs are now lower as a result of the of focusing the business solely on the Permian and streamlining our organizational structure, we are creating sustainable sufficient efficiencies across the business that will lead to improved results in future periods.

We generated nearly $50 million and adjusted free cash flow this quarter.

This gave us the flexibility to kick off our share repurchase program and Opportunistically increased working interest in upcoming projects through several land initiatives.

We are laser focused on reducing absolute debt and strengthening our capital structure.

Quarter end total long term debt was approximately $1 9 billion down more than $300 million from the period prior period.

Our outlook for higher free cash flows in the fourth quarter will allow us to keep on pace with reducing debt and buying back additional stock through year end.

We benefited from recent acquisitions and our now our Permian focused oil and gas company with scale.

We added quality assets in the Permian and extended our runway of high return long lateral development locations in terms of our recent Delaware acquisition. Our first five oil project is currently coming online and we are encouraged by early time oil production rates in wellhead pressures, we will keep you updated on progress here.

We have materially strengthened our balance sheet and implemented a cash return program to shareholders.

Turning to use up to 40% of our adjusted free cash flow to repurchase shares in the fourth quarter.

While we are focused on reducing absolute debt, we see buying back our shares at today's valuation is a very attractive use of cash flow.

Strengthening our leadership team and redesigned our operating teams our new CFO Russell Parker is leaving no stone unturned as he assesses our business and benchmark their performance against industry.

Is making an impact applying his years of experience to safely enhance operational practices lower cost and create sustainable synergies to drive future performance I know he is eager to share some additional highlights and talk about his team some more during our Q&A.

But it is a start early operational wins include <unk>.

One we are materially reducing days versus depth through the elimination of casing strings, which decreased cycle times and enhances project returns.

Each of our developments going forward, we will have a fit for purpose casing design Taylor.

Taylor to maximize value we.

We've provided a couple of examples of this on page seven of the presentation materials.

Reductions in cost per lateral foot are being realized through the optimization of drill bits and the ability to drill long laterals on the completion side. We've increased complete completed lateral feet per day by as much as 20%, we're seeing repeatable efficiencies and pumping rates and hours pumped per day.

The impact of these realized improvements are driving overall performance into year end, we now anticipate to complete approximately 50000 more lateral feet and commenced drilling and an incremental five wells relative to our mid year forecast. This additional activity will benefit 2020 for production.

While staying within our existing budget.

These accomplishments have been realized in a very short period of time. After we've revamped our operations in recent months. This has demanded a tremendous amount of effort and I want to thank the entire organization for making this possible.

Let me shift gears and discuss our life of field co development model.

This thoughtful approach to development has been constantly evolving over the past five years.

It differentiates us from our peers and our well productivity is performing countered industry.

We've learned a great deal about interactions between our co developed zones and associated well spacing and placement.

This continuous learning provides a foundation for ongoing tailoring our projects to maximize returns for.

For example, our recent co development of our Delaware South area demonstrated that our deepest target zone to be developed separately over time, allowing us to reduce overall project sizes and cycle times.

As well as reduce facility investments.

Continuous improvement is critical to maximizing our MPV proposition.

Let me wrap up today's call by providing some of our early thoughts around 2024.

Consistent with prior practice look for formal guidance from US early next year.

First we will continue to focus on maximizing free cash flow our top cash flow priorities are to fund our high value developments reduce debt and repurchase shares we believe that allocating capital appropriately across these buckets will drive improvements in our cost of capital.

We will continue to be very disciplined with our capital investments with recent efficiency gains in drilling completion facilities, we expect to do more with less in 2024 and forecast average <unk> cost per well to be down over 15% versus 2023 and.

In addition, ongoing high grading of investments within our co development model will allow us to target lower investment rates to enhance free cash flow.

Our production trajectory in 'twenty, four will benefit from pulling forward more drilling and completion activity than initially plan as we are improving cycle times in the second half of this year.

As well as the return of a second completion crew early in the next year.

In terms of our early thoughts on 2024 production outlook increases in activity to drive topline growth will be secondary to driving improved capital efficiency as we prioritize debt reduction and share repurchases.

Also point out that we expect our oil mix to improve over the coming quarters as we focus on high return oil areas in the Delaware and Midland basins.

We will remain nimble as our 2024 program progresses and will evaluate increases in our activity to the extent, we achieved DCF reductions in excess of our original plan similar to what we've done in the second half of this year.

We appreciate you invest in our company and we look forward to taking your questions operator.

Thank you we will.

I'll now open the line for questions as a reminder to ask a question. Please press star one.

Our first question comes from Neal Dingmann with Truth Securities. Your line is open.

Good morning, all thanks for the time gentlemen, first question, maybe kind of get right to it maybe for Russell.

Just you talked about some 15% reductions in gist.

Really highlighting completion drilling just a lot of things I'd love to hear.

Great from Russell just when he when he looks at 24.

Thanks, a lot of these savings potentially could come from.

Hey, good morning, Liana I appreciate the question and actually we're already starting to see some of this come to fruition as we modify our casing strength, it's going to be a different mix of savings across the portfolio, probably the way it will shake out we think 15% plus on average per well <unk> in the way that breaks out it's about 15.

Sent on average savings on the drilling side about a 5% average.

On the completion side and about 50%.

Savings on facilities and really what that all below that there is a little bit of cost of services. There is a little bit of that.

Single digits, 3% to 5%, depending upon which which.

Youre talking about.

But really the big change is coming from shifting from a kind of a standard mindset a standard way of doing things to a fit for purpose. So we're looking at each individual location and looking at where we can reduce casing strains reduce hole size is running a bit program in a bit life much longer than what we have been particularly drilling with conventional tools instead of rotary <unk>.

<unk>.

And in some places, we actually save money doing that and can keep that to keep the tools and the whole longer.

And then on the facility on the completion side.

A lot of that savings is coming from sand, that's not unique to Cowen now, though some of the logistics is our unique to Cowen.

That's the bulk of where we see that savings coming from we think we could probably stretch a little bit further on the completion side, even as we go into 2024 and that will be our goal as we look to increase our pump rate potentially complete two paths at the same time, we're throwing a lot of ideas out there we're going to let the team really stretch their legs really kind of push the envelope of engineering excellence to help reduce those costs.

And then on the facility side, it's really a once again, it's fit for purpose. So.

A good deal of money over the years with our life of field model building up an infrastructure of equipment and flow lines, and hey, guys. What have you or corn out of the point, where we can actually once our harvesting of us of that equipment, but to also look at maybe building a building or on pad facilities, a little bit differently using more bulk lines truck lines.

Grating Gasless system, while it takes a little time to get together actually over time will save us money. So it's a large combination of projects.

If you had about four hours I'd love to take through all of it but we don't have it today, but.

And a whole lot of folks working on it but basically it's that fit for purpose design versus just taking a standard.

Great detail trusts and then definitely we'll take you up on that Lumpier more sometime offline and then Joe. My second question is just on capital allocation I'm just wondering what will be the primary drivers of what is the primary drivers of when you'd Kevin decide that now on a go forward lean into the buybacks versus allocate a bit more on the growth side. Thanks.

Yes.

Look.

We've talked about the three buckets that we have in terms of adding value clearly investing in the asset base in a disciplined way.

Not only from a cost perspective, but also from cycle times, but we are going to be Cogs, and we don't want those efficiencies of drag is too higher reinvestment rates. So.

By focusing on high grading our opportunity set.

Going forward, we can find a nice balance in between there to deliver high return projects keep our reinvestment rates in check have more free cash flow to deliver to incremental debt reduction and share repurchases.

Thank you guys.

Our next question comes from Zach <unk> with J P. Morgan Your line is open.

Hey, guys. Thanks for taking my question.

First could you give us a little more color on what youre seeing from those gas year wells in the Delaware West area, maybe add some thoughts on how you think about future development in that area that these well results change kind of how you think about your inventory that you have remaining over there.

Sure.

I'll take that question the Delaware West classically has been our gas is up.

Elimination of casing strings, which decrease the cycle times and enhances project returns.

Part of our portfolio Thats nothing new.

Just a real surprise.

Each of our developments going forward, we will have a fit for purpose casing design tailored.

The good news is we have a lot of places to invest money going forward too so as Joe was alluding to.

Tailored to maximize value we.

We've provided a couple of examples of this on page seven of the presentation materials.

We're going to look at one hour power design any spacing completing landing and developing the property with a lower cost structure going forward in order to continue to maximize value.

And then also in the near term or other assets the east in the Midland Basin, obviously, it will help.

That that oil mix as we're going forward.

And I think specifically on.

The combined impact of these realized improvements are driving overall performance into year end, we now anticipate to complete approximately 50000 more lateral feet and commenced drilling an incremental five wells relative to our mid year forecast. This additional activity will benefit 2024 production all of us while staying within our existing budget.

Delaware West project is that we had a lot higher <unk> ratios than we expected.

I think some of that is attributed to look as an active area around us overtime, so somewhat offset activity.

Most likely lead to some some depletion effects in that area, but there are lessons learned from that project going forward. We still think <unk> is an attractive area.

But with co developments that we've got to evolve over time, so I would probably put in a few more lessor.

Let me shift gears and discuss our life of field co development model.

Or sorry, few less sticks and the deeper zones in the Wolfcamp B and C.

Thoughtful approach to development has been constantly evolving over the past five years.

It would be one thing that we take away from that but overall dealer western area will be back to over time part of our program with scale developments to rotate our projects because theyre not over taxing infrastructure leverage infrastructure, we have in place and there's very similar returns.

It differentiates us from our peers and our well productivity is performing countered industry.

We've learned a great deal about interactions between our co developed zones and associated well spacing and placement.

This continuous learning provides a foundation for ongoing tailoring our projects to maximize returns for.

For example, our recent co development of our Delaware South area demonstrated that our deepest target zone could be developed separately over time, allowing us to reduce overall project sizes and cycle times as.

Across the portfolio for different reasons.

But hopefully that gives you a sense of where we're heading from Delaware, but theres certainly some takeaways there that we're incorporating and our designs going forward.

As well as reduce facility investments.

Got it and then maybe just following up on Neil's question, you've talked a lot about cost reductions on DCF.

This improvement is critical to maximizing our NPV proposition.

Let me wrap up today's call by providing some of our early thoughts around 2024.

Can you give us any sense of what 2020 for Capex might look like if cost play out the way that you think they will should we be thinking about a similar number of turned in lines next year and Capex is just simply 15% lower year over year or is it more complex and complicated than that.

Consistent with prior practice look for formal guidance from US early next year.

First we will continue to focus on maximizing free cash flow our top cash flow priorities are to fund our high valued developments reduce debt and repurchase shares we believe that allocating capital appropriately across these buckets will drive improvements in our cost of capital.

Yes.

I wanted to give you the building blocks here.

Certainly around DCF average well costs as I said the cycle time element is really critical here in terms of how we plan out for next year. Obviously, we have a good pathway into the beginning of the year with getting a jumpstart on activity into the first quarter from the savings we've had in 'twenty three but yes. It is more complicated than just.

In addition, ongoing high grading of investments within our co development model will allow us to target lower investment rates to enhance free cash flow.

Taking down 15%.

We do we want to be mindful as I said around reinvestment rates we could.

Our production trajectory in 'twenty, four will benefit from pulling forward more drilling and completion activity than initially plan as we are improving cycle times in the second half of this year.

Everything that we've shown.

In recent months on the drilling side and completion side.

That allows us to go faster in general, but we're going to moderate our investments appropriately to balance all of our free cash flow objectives. So it will be able to fill in.

As well as the return of a second completion crew early in the next year.

The holes here in the next couple of months, but certainly wanted to give you some of the building blocks going into next year again being lower DCF per well improved cycle times.

Also point out that we expect our oil mix to improve over the coming quarters as we focus on high return oil areas in the Delaware and Midland basins.

And a good trajectory going into the beginning of Q4 with some oil weighted projects.

Got it thanks, Joe.

Thank you.

Our next question comes from Oliver Huang with Tpa Your line is open.

Good morning, Joe Kevin and Russell.

We appreciate you invest in our company and we look forward to taking your questions operator.

Our.

Certainly.

Good to see the incremental detail around a lot of the cost initiatives that youll.

Thank you.

I'll now open the line for questions.

And working around and I mean, 15% is certainly a meaningful number but.

A reminder to ask a question please press star one.

Our first question comes from Neal Dingmann with Truth Securities. Your line is open.

Maybe just kind of a follow up to neal's earlier question. How immediate are these savings is that something that we would expect to start in full force at the beginning of 2024 I know you all have already made headway.

Good morning, all thanks for the time gentlemen, first question, maybe kind of get right to it maybe for Russell.

Just you talked about some 15% reductions in gist.

On that today or is that something that we should expect to kind of layer in a bit more gradually.

Really highlighting completion drilling just a lot of things I'd love to hear.

It's already happening now and I'd say as we get into Q1, we should we should be in the neighborhood of already realizing that hopefully definitely averaging it through the year, maybe even beating it as the year goes on depending of course, depending on where commodity prices and service rates are.

Straight from Russell just when.

When he when he looks at 24, where he thinks a lot of these savings potentially could come from.

Hey, good morning, Neil and I appreciate the question and actually we're already starting to see some of this come to fruition as we modify our casing strength, it's going to be a different mix of savings across the portfolio, probably the way it will shake out we think 15% plus on average per well <unk> in the way that breaks out it's about a 15.

But to that point and Joe mentioned earlier.

We've got extra projects that were actually drilling and completing this year about 50000 extra lateral feet.

Another handful of wells that we're going to spud in 'twenty three that were not in our anticipated budget.

<unk> on average savings on the drilling side about a 5% average.

On the completion side and about 50%.

Savings on facilities and really what that all of that there is a little bit of cost of services. There is a little bit of that.

Mid year. These projects are going to add production in Q4, obviously Q1, you won't see them in Q4, adding production next year.

Single digits, 3% to 5%, depending upon which which you are talking about.

But we're able to do that and still stay within our original budget and the reason is we're already starting to realize some of these prospects I don't think we're not quite to the 15% range yet maybe single digits because honestly one of the biggest cost savings, which is going to take time to layer into that facility fee that was going to be more Q2 three four.

But really the big change is coming from shifting from a kind of a standard mindset a standard way of doing things to a fit for purpose. So we're looking at each individual location and looking at where we can reduce casing strains reduce hole sizes run they're a bit program in a bit life much longer than what we have been potentially drilling with conventional tools instead of rotary <unk>.

But the bar on the D and the fee side, we're already starting to see.

Come to fruition now.

<unk>.

And in some places, we actually save money doing that and can keep that to keep the tools and the whole longer.

Excellent.

Awesome, that's helpful and maybe another follow up just with respect to the facility side.

And then on the facility on the completion side.

A lot of that savings is coming from sand, that's not unique to Cowen now, though some of the logistics is our unique to Cowen.

Such a change that you all are kind of talking about impact the expected production trajectory.

That's the bulk of where we see that savings coming from we think we could probably stretch a little bit further on the completion side, even as we go into 2024 and that will be our goal as we look to increase our pump rates potentially complete two pads at the same time, we're throwing a lot of ideas out there we're going to let the team really stretch their legs really pushed the envelope of engineering excellence to help reduce those costs.

Well productivity is it more so along the lines of just kind of constraining IP, a little bit more to avoid overbuilding in the facilities or is it more so along the lines of just.

Using stuff that's already existing.

It's usually things that are existing in some places, yes, you might actually see a lower IP 30, but it's similar IP 90, that's part of the ways in which we're saving some money is if you build everything for an IP 30.

And then another facility side, it's really a once again, it's fit for purpose. So we.

A good deal of money over the years with our life of field model building up an infrastructure of equipment and flow lines, and hey, guys what have you.

At your cost structure is higher however, if you look at your rate of return.

It's better billings towards the 1990, so over the year you wouldn't see it maybe on an exact well in an exact month you might see a different peak, but.

Now to the point, where we can actually once our harvesting of us of that equipment, but to also look at maybe building a building or on pad facilities, a little bit differently using more bulk lines trunk lines integrating gasless system, while it takes a little time to get together actually over time will save us save us money. So it's a large combination of projects.

If you were looking at a quarter of all publicly available data that I don't think you'd see the difference that you'd probably see more stable production over time, the other place it sounds like some of the design changes, we're talking about will actually help eliminate or reduce back pressure, which will actually improve particularly to improve some of our production on the base.

If you had about four hours I would love to take you through all of it but we don't have that today, but.

And a whole lot of folks working on it but basically it's that fit for purpose designed versus just making a standard.

Awesome and if I could squeeze just one more in with respect.

The Q4 guide.

Great detail trusts and then definitely we'll take you up on that more sometime off line and then Joe. My second question is just on capital allocation I'm just wondering what would be the primary drivers of what is the primary drivers of when you'd Kevin decide that now on a go forward lean into the buybacks versus allocate a bit more on the growth side. Thanks.

Obviously, a downward revision there, but just wanted to see is there any sort of breakout in terms of what could be attributed to the less oil than expected from the subset of wells that came out of the west area within the quarter versus just.

The incremental downtime from accelerating some of the optimization that you're doing on the artificial lift side.

Yes.

Look we've talked about the three buckets that we have in terms of adding value clearly investing in the asset base in a disciplined way first.

Yes.

The large majority of that from what we highlighted Delaware West.

Okay. Thanks.

First stop but we are very focused on debt reduction goals out there were serious about getting to them and also following through on our share repurchase program. So we have a lot of efficiencies that Russell's talked about here not only from a cost perspective, but also from cycle times, but we are going to be cognizant, we don't want those efficiencies of drag is.

I appreciate the color guys.

Okay.

Our next question comes from Derrick Whitfield with Stifel. Your line is open.

Thanks, Good morning, all and congrats on the structural improvements you've outlined this quarter.

Thanks, Eric.

Starting with a follow up on the Delaware less development.

Higher reinvestment rates so.

By focusing on high grading our opportunity set.

I wanted to ask if you could lean in on the learn lessons and specifically does the higher EUR indicate greater vertical connectivity through the lower wolfcamp zones or simply a gasior upper wolfcamp based on past depletion from bone spring development.

Going forward, we can.

Can find a nice balance in between there to deliver high return projects keep our reinvestment rates in check have more free cash flow to deliver two incremental debt reduction and share repurchases.

So I would say that the generic learning is is you got to make sure youre doing a great job taking into account that what also happened on your acreage, but offset acreage we're projecting that into the future looking at how how that regional depletion may impact you going forward and then also looking at how.

Thank you guys.

Our next question comes from Zach <unk> with JP Morgan Your line is open.

Hey, guys. Thanks for taking my question.

First could you give us a little more color on what youre seeing from those gasior wells in the Delaware West area, maybe add some thoughts on how you think about future development in that area that these well results change kind of how you think about your inventory that you have remaining over there.

Your spacing needs to be appropriately designed a redesign in order to optimize your capital investment going forward.

So there's still plenty to do there, but yes, a lot of what it may involve us in order to maximize NAV, because youre dealing with a little bit lower reservoir pressure as we're talking about wells with larger completions plus safely spaced further apart actually optimizes youre going.

Sure.

The exact question.

Delaware West classically has been our gassy.

Part of our portfolio Thats nothing new.

No real surprise.

When youre seeing that but that's really what I would say the key learning from this is is looking at bench by bench what is the appropriate spacing looking bench by bench to see which wells are communicating with what where you have local geologic features where you have localized increased depletion from offset operators.

The good news is we have a lot of places to invest money going forward too so as Joe was alluding to.

We're going to look at one hour power design any spacing completing landing and developing the property with a lower cost structure going forward in order to continue to maximize value.

To make sure that you are optimizing your capital going forward.

And then also in the near term or other assets the east in the Midland Basin, obviously will help pull up at that oil mix as we're going forward.

And Russell kind of looking forward with that development in that area.

Yes.

Do you think you'll have enough data kind of post this post.

And I think specifically on.

Delaware West project is that we had a lot higher <unk> ratios.

Testament to to have a good feel for what spacing should be as you guys look to develop that out in 2024 and 2029.

We expected.

I think some of that is attributed to as it look it is an active area around us overtime, so somewhat offset activity.

Absolutely not only are we looking at fit for purpose on the <unk> side, but we're actually really started to unlock some of the other team members as we change our structure and really take into account and analyzed quite a bit more data than that we have in the past as a company.

Most likely lead to some some depletion effects in that area, but there are lessons learned from that project going forward. We still think <unk> is an attractive area.

But with co developments that we've got to evolve over time, so I would probably put in a few more.

We're actually doing a lot of exciting things around machine learning and predictions in reservoir simulation.

Less a few less sticks and the deeper zones in the Wolfcamp B and C.

That would be one thing that we take away from that but overall dealer western area will be back to AUM.

What expenses, we see are communicating with one another we have been doing some expiring experiments actually to figure out.

Over time part of our program with scaled developments to rotate our projects as we are not over taxing infrastructure leverage infrastructure, we have in place and there's very similar returns.

Fluid typing.

And actually being able to really see what zones are communicating with with what other zones by doing what felt like a fluid fingerprint.

Across the portfolio for different reasons.

But hopefully it gives you a sense of where we're heading from Delaware, but theres certainly some takeaways there that we're incorporating and our designs going forward.

No absolutely, it's an incredible focus of our technical.

Nickel team not only in this basin, but everywhere.

Because same learnings St process can be used to help you optimize your NAV.

Got it and then maybe just following up on Neil's question, you've talked a lot about cost reductions on DCF.

All your assets.

I'm going to work on your side one final if I could just on page eight looking out into 2024 could you speak to how impactful III model lateral development could be in your operational plan.

Can you give us any sense of what 2020 for Capex might look like a cost play out the way that you think they will should we be thinking about a similar number of turn in lines next year and Capex is just simply 15% lower year over year or is it more complex and complicated than that.

So I think that how impactful a three mile lateral.

Correct, Yes, yes.

Well part of what we wanted to show there was actually not only just record lateral blood record time.

Yes.

We wanted to give you the building blocks here.

The first time saves money.

In terms of how many locations we'll have next year that'll be three miles that we're still working out our budget in figuring that out.

Certainly around DCF average well costs as I said the <unk>.

Fecal time element is really critical here in terms of how we plan out for next year. Obviously, we have a good pathway into the beginning of the year with getting a jumpstart on activity into the first quarter from the savings we've had in 'twenty three but yes. It is more complicated than just taking down 15%.

I'd say, probably the P 50 answers that we're still drilling at $3 50, 10000 foot wells, but we are looking for places where we can extend that wherever Boston matter of fact in one particular location, we couldnt, even drill Australia 15000 foot Hall.

So, but we drove basically if you will.

Do we want to be mindful as I said around reinvestment rates we could.

Feel like.

L shape well almost.

With everything that we've shown.

Our well abandonment in order to one optimized depletion of the reservoir dealing with these situations that we had acreage situation that we had our footprint, but also thereby maximizing our returns. So we're going to be looking at that we're going to be looking at U shaped wells, we're going to look at a lot of different concepts in order to optimize our NAV, but also.

In recent months on the drilling side and completion side.

That allows us to go faster in general, but we're going to moderate our investments appropriately to balance all of our free cash flow objective. So it will be able to fill in.

The holes here in the next couple of months, but certainly wanted to give you some of the building blocks going into next year again being lower DCF per well improved cycle times and a good trajectory going into the beginning of Q4 with some oil weighted projects.

So kind of opening our minds, all with them within the art of the possible in terms of well shaped landing links.

And tied to that.

That's a great update thanks for your time.

Got it thanks, Joe.

Thank you.

Our next question comes from Scott Hanold with RBC capital markets. Your line is open.

Our next question comes from Oliver Huang with Tpa.

Your line is open.

Hey, Thank you all.

Good morning, Joe Kevin and Russell.

And hopefully this hasn't been asked yet Ben just jump to a couple of calls that are going on but just in terms of.

Hello.

Certainly.

Good to see the incremental detail around a lot of the cost initiatives that you're working.

You all saw on the Delaware West and what Youre learning there.

Working around and I mean, 15% is certainly a meaningful number but.

Could you talk about like your asset base just more at large is there other areas that have regional pollution or spacing that theres something you will be cognizant of or is this one or is this more Delaware west specific and can you talk about where delver west fits into your overall inventory and activity levels moving forward.

Maybe just kind of a follow up to neal's earlier question.

How immediate are these savings is that something that we would expect to start in full force at the beginning of 2024 I know you all have already made headway.

On that today or is that something that we should expect to kind of layer in a bit more gradually.

<unk>.

So I'd say going forward into next year I assume we're probably going be more heavily weighted in the east and in the Midland Basin. However, we do already have some slated projects in south and west.

And honestly you can map. This we've actually made some cool little movies about it will videos.

But to that point and Joe mentioned earlier.

Regional pressure decline is real and all benches within the Permian. If anybody tells you that a thought and theyre not looking at the data that doesn't mean you can't make money. However that just means you've got to take it into account. When you are building your development plans and as you continue to learn and modify your developed plans. So I think look the process and what we learned in the Delaware West is something that you can apply everywhere.

We've got extra projects that were actually drilling and completing this year about 50000 extra lateral feet.

Another handful of wells that we're going to spud in 'twenty three that were not in our anticipated budget.

At mid year. These projects are going to add production in Q4, obviously Q1, you won't see them in Q4, adding production next year.

Do you see that same level of pressure decline all throughout the Permian know, it's specific by bench is specific by area that which parts of the county this year and so that's not a it's not a blanket answer which again is like I can go back to when you're developing your asset and same thing for Cowen you want to do a fit for purpose design because not each each area is seeing similar.

Biggest cost savings, which is going to take time to layer into that facility fee that was going to be more Q2 three four.

Phenomenon, but not at the same level and at the same degree not the same.

The same with ever bench right you don't see you don't see it because maybe the reservoir is it start out with the same.

But the bar on the D and the fee side, we are already starting to see.

Come to fruition now excellent.

<unk>, let's start out with the same.

Historically our.

Awesome, that's helpful and maybe one other follow up just with respect to the facility side.

Our geologic history and Digenesis, so theres, all sorts of reasons, but that produce different results, but the process and the learnings you can apply everywhere in terms of yes, where I see us spending money or where we see ourselves spending money definitely lot of prop.

Such a change that you all are kind of talking about impact the expected production trajectory.

More weighted to the Delaware and Midland asset in 'twenty, four we do still have projects selling the south and in the west and they were working on some things longer term to make the investment opportunity even more exciting in those basins that was part of our assets, but more to come on that Thats a teaser for next year.

Well productivity is it more sell along the lines of just kind of constraining it a little bit more to avoid overbuilding in the facilities or is it more so along the lines of just kind of using stuff that's already existing.

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