Q3 2019 Earnings Call

Good morning, and welcome to the cigarettes Energy Company third quarter 2019 earnings release Conference call.

Participants will be in listen only mode.

You need assistance. Please signal a conference specialist pressing the star key followed by zero.

After today's presentation, there will be an opportunity to ask questions to ask a question you May Press Star then one on your telephone keypad.

Draw. Your question. Please press Star then too.

Please note. This is that is being recorded.

I would now like to turn the conference over to current carrying Chernow, Vice President Investor Relations. Please go ahead.

Thanks, Gary and good morning, everyone welcome to our third quarter 2019 conference call. An updated presentation was posted to our website yesterday afternoon, and we may reference that presentation on our call today.

Just as a reminder, our discussion will contain forward looking statement a number of actions could cause actual results to differ materially from what we discussed.

You should read our disclosures on forward looking statements on our news release and in our 10-Q, which we filed later today.

Also available to our latest 10-K for the year ended December 31st 2018.

Although it will have the risk factors associated with our business.

We will begin our repair our prepared remarks with an overview from our CEO . Tom Jorden, then Joe Albi, Our C. O. We'll update you on operations, including production and welcome.

He VP of exploration, John Lambeth, and simmer axis CFO , Mark Burford are here to help answer any questions.

As always and so that we can accommodate more of your questions. During the out or we have a lot of political we'd like you have to do you limit yourself to one question and one follow up feel free to get back in the queue. If you like so with that I'll turn the call over to Tom.

Thank you Karen and thank you all for joining us on the call. This morning.

I will briefly discuss our operational highlights and focus.

Oh boy or C O, Joe Albi, who will provide a more detailed breakdown on our quarterly details.

Summer show solid third quarter in a challenging macro environment or oil production came in above the midpoint of our guidance range total all grew 8% sequentially with Permian all growing 6.6% sequentially.

Permian oil growth is projected to continue well we plan on continuous sequential growth occasionally refine the projects are ready to come online sooner than planned in all cases, we bring our wells online as soon as they're ready.

We lowered our capital guidance for year by $15 million at the midpoint, while keeping our production guidance and well count unchanged.

Commodity prices continued to be a challenging headwinds, particularly for natural gas or natural gas liquids. In spite of these headwinds we expect to exit the year without incremental borrowings. Furthermore, we're pleased to be returning cash to shareholders in the form of our dividend, which we intend to continue to grow overtime.

We continued to deliver excellent fully burdened returns as we've described in the past we measure ourselves on a fully burden basis, which includes all drilling completion facilities midstream land science and junior in a.

Oh, well productivity and cost improvements for the past few years have resulted in robust and repeatable investment returns.

Our current returns are also more resilient to drops in commodity prices than they were five or six years ago.

As an example, we have stress tested our total program returns for each of the Threep. Prior years, 2016, 17, and 18 by modeling all future cash flows as if the flat FCC prices in effect at the end of Q3 last it forever.

Even with these low prices on a go forward basis. Our total program returns our robust our investment performance has become repeatable robust and better defendable against commodity price swings.

With this knowledge and confidence we're doing a better job of planning our future.

We also continued to benefit from the tremendous work in science that we've put into understanding resource play development. Our program was almost entirely development at this point.

We still have a surprise or two but we continue to gain operational confidence in our development in space can decisions.

We also continued to make a mistake or two along the way this was the nature progress.

We are laser focused on all elements of our cost structure capital expenditures and lease operating expenses.

As we look into 2020, our plan is to generate free cash in a 50 dollar WT <unk> oil $2.50 Nymex gas environment.

We will remain discipline cautious and flexible we're not burdened by service contracts are under lease expiration issues that can grow our business at the right pace for the current environment now alternatives over to Joe to discuss our operations in more detail.

Thank you Tom and thank you all for joining our call today, Oh, a touch unusual items, our third quarter production.

Fourth quarter and full year production guidance, and then I'll finish up with a few comments on L., we and service costs.

As far as Q3 production volumes go with continued strong execution, we achieved another nice jump in our production during Q3, our third quarter posting for net equivalent production came in at a company record 287000 be always per day.

3% above the top end of our guidance range of 265 to 279 and up 4% and 31% over Q2, 19, and Q3 18, respectively.

The guidance beat was was driven by continued strong Permian production growth and higher than forecasted NGL recoveries during the quarter.

On the oil side, we posted another company record for production. Our Q3 oil volume came in at 89.7 thousand barrels of oil per day, beating the midpoint of our guidance by 1700 barrels a day I'm, putting us up 8% and 40% over Q2, 19, and Q3 18 risk.

Back to post it.

Although we saw a quarter to quarter <unk> oil production increases in both the Permian and the mid Con Ed the Permian drove the increased with our Q3 Permian oil volume up 74.8 thousand barrels a day up 6% over Q2, 19, and 53% over Q3, a time when.

The post spin the Permian now accounts for 83% of our total company oil production.

Shifting gears to capital and our full year production guidance.

As Tom mentioned through efficiency gains and cost savings, we've lowered our full year 2019, Indeed capital guidance to 1.3 to 1.4 billion down $50 million or 4% at the midpoint of our previously issued guidance.

That said, we've kept our forecasted full year net completion count at 80 net wells.

With our revised completion scheduling our updated modeled projects our Q4 net equivalent volume to range from 272 to 292000 barrels per day.

With the midpoint down just slightly from Q3 due primarily to own uncertainties. We have surrounding the extent of any ethane rejection that may occur during Q4.

On the oil side, we're modeling a range of 86 to 92000 barrels a day with the midpoint virtually flat to Q3, and that's a byproduct of our projected at 11.2 net wells coming online during Q4.

Comparing to the 21.4 that we had on line in Q3 and 39.5.

In Q2.

So with our strong execution over the past three quarters, we're increasing our full year guidance ranges for bulk equivalent and oil production, we bumped our full year net equivalent production guidance to 273 to 278000 BOE per day, that's up 3% the midpoint from our guidance last call and with the rain.

As of 84.5 to 86.5 thousand barrels world per day for full year net oil production. We've raised the midpoint of our guidance our oil guidance by 500 barrels a day or approximately 1% front range that we quoted last call.

Jumping to Opex, we had a strong quarter for our lifting costs, our Q3 posting of $3.34 per equivalent barrel was down 5% from Q2.

But our year to date lifting cost or $3.39 per Billy just slightly above the low end of our full year guidance range that we've quoted last call Threethirty to 365 and represented a drop of 6% from our 2018 average of $3.62 per be a week.

With the posting we've tightened our full year lifting cost guidance to a range of Threethirty to 355 for beer, we are lowering our midpoint by five cents per deal we from a range that we quoted last call.

And lastly, some some comments on drilling and completion cost with the slowdown in industry activity, we're seeing cost reductions on both the drilling and completion sides.

Current drilling day rates are down 5% to 9% from last call and with service cost reductions and our continued focus on Frac design, we've dropped our completion at these by 11% to 12% from last call, which translates to a 17% to 19% drop from completion activities earlier in this year.

As such we've realized sizable drops in our projected total well cost during the quarter.

And our Wolfcamp program as an example cost reductions have dropped or generic Reeves county, two mile Wolfcamp a EFI.

To $9.3 million to $11.8 million again, depending on facility design in Frac logistics that range is down $700000 for Mark our estimate last call $1.1 million from earlier, this year and down $1.6 million from our estimate.

Late last year.

Our shallower Wolfcamp a wells in Culberson County are running about $500000 less than this range with an at the range of $8.8 million to $11.1 million.

Efficiency gains that we derived through our multi well development drilling projects as we've talked about for put our average development well.

Total well costs at the low end up these ranges.

And then the mid continent, our refined completion design improved operating efficiencies and service cost reductions.

Combined have reduced our fees and both are Woodford and our mayor rack programs. For example, our current two mile. Merrimack EFI is run an 8.5 to 10 million that's down $1 million from last call 1.5 million from earlier this year and 3 million from the cost that we quoted.

And early 2008.

So as Tom mentioned, we've made tremendous strides and our cost structure, particularly on the total well cost side and it really is showing up in our statistics through operational efficiencies realized cost reductions and by drilling longer laterals are 2019, Permian program total well cost per lateral foot metric is estimated at 11.

100 per 1150 to $1200.

This estimate includes all necessary cost to bring while online drilling stimulation facility and flowback cost at it implies a 20% reduction over that same metric that we saw in 2018.

So in closing we had a great Q3, we executed on the strong production ramp we promised and forecasted with equivalent in oil production guidance speech along the way.

We've raised the midpoint of both our full year net oil equivalent production ranges with resulting in year over year growth of 26% and 24% or net oil and adequate equivalent volumes, respectively. Our cost structure is strong our Q3 lifting costs was down 5% from Q2, and we've lowered the midpoint of our full year guidance.

By five cents per BOE, we we've lowered our total well cost significantly with our average Permian total well cost metrics and the 11, 50% 1200 dollar per lateral foot range down 20% from 2018 levels, we're executing on all cylinders and we're well positioned to deliver on the capital activity in the production play.

And that we put in place beginning of the year.

So with that I'll open it up for QNX.

We will now begin the question and answer session.

To ask a question you May Press Star then one on your Touchtone phone.

You are using a speakerphone please pick up your handset before pressing the keys to withdraw your question. Please press Star then to at this time, we will pause momentarily to assemble a roster.

Our first question comes from Gabe Daoud with Cowen. Please go ahead.

Hey, good morning, everyone. I appreciate all of our prepared remarks and high level framework on 20 was I guess wondering if you could just give us a sense on assume Permian activity levels for the.

The range of oil prices that you get what whether that's in terms of rigs.

Crews or turn in lines, and then I guess, what kind of overall growth do you see for for corporate oil production next year.

Yes, I gave this is mark.

For 2020, and we're still working in our plans and we don't have a lot I want to give a lot of detail on on the plan into 2020 occurring eight rigs in the Permian, we have some plans that we'd actually increase and that rig count into 2020, but our current forecasting the scenarios are running.

And then the turn in lines here with the cycle time for seeing our turn in lines have improved with the compressed cycle times. So.

The different scenarios, we're working on a 2020, we are seeing in activity. That's a good piece activity into 2020.

And we're focused enough Permian oil growth and we're forecasting growth into 2020.

Understood. Thanks Mark.

My guess is as a follow up I think this year you had some exploration spend in the budget and just I guess as a way to maximize free cash flow next year do you think that comes out of the budget and and then I guess, if you could maybe even just quantify that number of exploration spend that was in the budget for this year. Thanks guys.

Yes, this is John land, but.

We did have some exploration spend but again, it's not that much money in regards to 2019.

When we do have a land effort usually were very early interest thus far entry costs are extremely low. So you really don't even see it within the overall call capital framework. So it's not something and I think one needs to worry too much about in terms of our capital plans for the following year.

We track that very closely as a percentage or total capital that's a metric in our with our focus on fully burden returns that we watch from the inception of summer X, we haven't budgeted tremendous amount for exploration.

Hoping that we're going to find some things that we love.

And we should have plenty of room there.

Great. Thanks, Tom Thanks, Sean.

The next question is from our own Jayaram with JP Morgan. Please go ahead.

Yes, good morning, a Tom I was wondering if you could comment your thoughts around risk associated with your federal acreage position as we approach.

An election year and have you had any conversations.

With the Governor of New Mexico, and just general thoughts around that risk, which has been evident some tweets.

In early September .

Pardon me. It appears that we may have lost connection with the main speaker, Ryan I'm going to put the call on hold and try and reconnect one moment. Please.

Pardon me. This is the conference operator, we have reconnected with the main speaker location and going to join our runs back in for his question as well. Please go ahead.

Tom can you hear me I can thank you okay.

Did you hear my question on federal acreage, if not I could restate. It yes, no. We did not we lost connection. So can you. Please restate.

Okay, Great Tom I wanted to get your thoughts on potential risk around excimer access state federal.

Pardon me at your federal acreage position in the Permian as we approach the election year have you had any conversations with the governor or officials in new Mexico, and how do you think about that risk.

To go forward basis.

Well.

Lot of questions our room, but certainly similar exosome engaged with the governor and such I have not personally discuss this issue with the governor.

Here's how I think about the risk we're at a primary season and it's always on the primary season. Some ideas get floated that are a bit extreme I mean, if you go back four years and watch either the democratic or the Republican debate. So I think you'll make that observation.

We are sure we are certainly exposed to new Mexico, I mean, we've been very forthcoming on that.

We don't think that there is going to be a ban on fracking on federal lands.

We are nicely positioned for Texas as well so even if it were to happen or there'll be some discussion around that we've got plenty of places to adjust and move to but I'll just close by saying.

Federal royalties are such a huge part of the state of New-mexico's total revenue stream.

That I cannot imagine.

A situation, where the federal government would close the door on new Mexico.

But we will be prepared either way with flexibility our program.

Great and just as my follow up Tom going back to Gabes question Slide 19.

You've highlighted.

In a different free cash flow yields in a 2020 program from 50 to 60 I was wondering is at a at the lower end of that band would you still anticipate growing some oil next year or would that resemble more of a maintenance program.

Based on the initial forecast so no we grow oil under all those scenarios.

Great. Thanks, a lot Tom.

The next question is from Neal Dingmann with Suntrust. Please go ahead.

Good morning.

First question I had was just pertaining to can you talk about a little bit just on your deed your Delaware plans by county, it looks like.

Most continued the for 19 in Culberson I'm, just wondering I know fully understand you don't have the detailed 2020 out yet maybe just talk a little bit about.

Focus be relatively similar.

Well I would say it will be relatively similar we're always going to have a very healthy healthy level of activity in culberson with our joint development agreement with Chevron.

Well, we've a lot of projects, we like in Eddy County longer projects, and Lea County, but yell Reeves County also has a lot of activity.

We're getting after that resolute acreage. In addition to the acres, we brought to the table and we're going to be active really across our portfolio.

Okay, and then one just follow up thanks, Tom.

Just looked like for 19, you had about 70 million budget for midstream again, knowing full well you don't have detailed 2020 just on average do you think the spend for I would just say non DNC will continue to be about the same or will that start to trickle down a bit.

Well this year anticipated to be 70, or maybe slightly below and then as we move into 2020 are for our focus is going to be on trying to capitalize on the infrastructure that we have and minimize any.

It's stream associated costs, it would be tied to our development programs.

Pretty good thank you.

The next question is from Mike Sierra with Stifel. Please go ahead.

Hi, good morning, everybody congrats on the quarter.

Tom You said that that 50 dollar case with the 2% free cash will yield that you still grow oil just want to see if you could provide.

Maintenance capital level that you need to spend to keep your oil flat say with the projected fourth quarter rate.

Yes, I am a bounce Pat said to Mark.

Well, we've calculated that yes, brash, yes, Mike we havent counter that fresh working on 2020 plan right now which has in turn anticipate growth in our oil and we're working on allocation you were allocating into 20 other externally looking at it even a greater portion of our capital going to the Permian, but we don't have I don't have a maintenance capital associated with.

But that yield that we're talking slightly under 2% to nearly 10% is a scenario are there. Some engineers are working on with a steady steady to slightly down cat DNC capital that could you derive that type yield and it's basically kind of anticipating pushing that 50 into 50 type Nymex oil and gas price.

Right.

At this again at steady slide down capital holding up flat good morning that through the here.

No problem, Okay and then.

The 250 gas price I guess, we're looking at what price is still below at dollar.

Even with the Gulf Coast Express online I assume thats what you.

You had mentioned earlier in your prepared remarks on that you are using.

Kind of the current prices held flat.

How does that.

I guess impact you're thinking about your plans for 2020 or does it.

Well, we dose Nymex prices are always quote that because that's the index marker, but we bring that back to our actual sheet price at the wellhead. So were accounting for all of those basis differentials fully in our go forward plans Mark you want to channel that's right, Mike So Mike we the rent different flat cases or.

Even price to current forward strip for 2020 is right around two to get things to 52 last Friday, So it's fairly close to the flap Kate priced Nymex price for using but the extent, we just from that to a flat case from the strip case, we keep unfortunately reduce the realized prices in areas were to local market differentials piece on that.

Correct, although differential so we bake fully bake in all those differentials.

So our cash flow fully incorporates the local pricing.

Oh products business for gas and NGL that's right.

Thank you.

The next question is from Jeffrey Campbell with Tuohy Brothers. Please go ahead.

Good morning, and congratulations on the quarter.

Slide eight illustrated that the second COVID-19.

Half of the entire 2019 timelines.

That activity trade trailed off in the second half.

Since 2028 becomes a year or potentially meaningful free cash generation I was wondering if you're going to follow a similar operational plan as you did in 2019 or would you prefer to make the free cash generation more level loaded throughout the year.

Well all.

Start us off and then one more comment.

Ideally, we would love if it were level loaded across the platform well with eight rigs running and this development projects. There is a certain structure to when we bring these wells online and you know this is just our business.

We are making good attempt to try to smooth out this field operations to try to have a more even field cadence.

But.

Wanted to just be clear our primary goal is to generate outstanding returns on invested capital stress test those returns for the downside and make sure that we account out we account for every single cost incurred and bringing our production online.

The production timing is a consequence of good decision so not a primary driver yes, we'd love for this to be smooth uneven, but the world doesn't always behave that way with these development projects Mark you want to touch on that yes, absolutely the second what you're seeing in the fact that.

Number of wells brought on into production any particular quarter can be very bite size the pads for joining and again in a different development.

The development that we're drilling for well I don't see completed per quarter is much more consistent in our operational cadence is what we're focused on his operational cadence of our activities in drilling lateral completing our laterals and drilling our wells.

And the timing of these well productivity, we brought on bringing any quarter will be very depending on again to size the pads.

The areas that we're drilling and even can vary somewhat bit the working interest that we have in areas. We're bringing on since this is a net well completion per quarter.

We are definitely focus on operational canes are well lateral feet drilled per quarter and again the quarterly production.

Cadence at wells brought online can be more look more erotic than what the underlying operations represent yes, I want to make one other comment.

We're focused on costs.

I said in my opening remarks at that is laser focus of ours and to smoothed out that could be done, but it could involve significant costs mobilization costs getting enough water on on pad as you need it and so there are lot of other considerations.

But we are we are out there it sounds like a broken record here were driven by returns on invested capital Joe you want to comment on that yet I wanted to use. This year is as an example of this completion cadence to both Mark and Tom we're talking about.

Look back over the year I'm going to talk about multi well projects in the Permian.

You too we had two multi well projects on a gross basis for they only were two wells per project that was four net wells for that.

Total gross wells for the quarter.

Q2, we had six multi well projects it ranged anywhere from two to seven wells per pad project and on the average there were five wells for every one of those projects. So in Q2. These six projects brought on 30 wells in Q3 five projects brought on 21 wells as we go into Q4 two.

With these projects are bringing on 12 wells and as I mentioned in my opening statements. That's that's really the by product of our plateau oil production here in Q Q4, So we're always going to have some semblance of that completion cadence.

Production.

Well I really appreciate the color and I think your points are fair and then probably what we should end up doing is taking a free cash on annualized basis, rather than getting too hung up on sequential.

But I thought it is fair question to ask.

Totally fair question and you know we look at this I wish I want to call. Early this morning on just this topic and.

I was convinced that.

By spreading it out further we get better returns a lower cost structure. So that it's a it's a really fair question. We welcome to question.

But but some of this is just.

Ill.

Details that in ironing a program out sometimes the chips fall in a non ideal way I'll just leave it there okay.

As my follow up on slide 28.

References summer access to gas gathering systems, and slide 29 illustrates the water management system I'm. Just wondering is the longer term view to keep these assets in house for cost control. Since you guys mentioned, you're very focused on cost or could you sell them is still have an advantaged cost structure well that's a that's a very part.

Good question to us because as we've discussed in prior calls this is something that is an active subject to investigation.

We've done a lot of work over the last quarter on this we certainly have a very valuable gas gathering system and a very valuable water gathering system I will tell you that we have and continue to explore monetization options.

But it really is a trade off between a quick hit of cash when you monetize versus the longer term increased operating expenses.

If I were surprised by anything even at today's multiples, it's not an obvious decision.

You can you can sell them take the cash now, but you're going to pay for it in perpetuity with higher operating costs. We think we've got one of the lowest cost structures around.

We realized that that cost structure is a real asset of ours.

Gathering system, both for gas and water provides us tremendous operational flexibility. So although we continue to explore that we have conversations on this everyday I will say that for now we have not made a commitment to monetize these assets its a.

So the active argument at some were actually it's a it's a healthy argument.

But it still it's pay me now or pay me later type choice.

Okay, Great now I appreciate that color and again congratulations on the quarter.

Thank you.

The next question is from Noel Parks with Coker Palmer. Please go ahead.

Good morning.

Had a couple of questions.

Thinking about.

Culberson County in the economics out there right.

Also thinking about.

Gas and NGL.

Issues that you on the whole industry is there.

How sensitive.

Do you consider the Culberson County, economics to sort of the the uncertainty around the.

Takeaway and processing part of the equation.

Just sort of thinking here theres that pieces and of course, the demand piece for the products. It also.

Yep.

Fluctuate from a lot with Ngls.

Well.

We don't see a.

Uncertainty in takeaway of processing, we've got that system with multiple outlets for takeaway, we have multiple outlets for processing and all that Joe comment on this but our operations and marketing group had done a tremendous job when we've had occasional interruptions with our processors are gathered.

First.

Transporters, we've been able to very adeptly redirect cash flow because we do control that asset Mcgathey standpoint, we have multiple outlets.

Oil is the dominant phase dominant revenue phasor Culberson County.

Hi, I wish gas and Ngls were stronger revenue component, but even at current pricing with this hostile price environment. The economics of Culberson County, our Supreme late attractive to us and we just see upside to pricing.

If if we can make the kind of returns were making now it's just only going to get better if we see any kind of recovery in gas and NGL pricing those economics, such I. Appreciate your question because I think the economics of Culberson County are under appreciated not only as Colbert.

In county, as we demonstrate in our slide one of the Premier counties for cumulative oil production, but we deliver that oil at a basin wide low operating costs, because the nature of that reservoir and the low operating cost of our system. So we're pretty pleased with that asset Joe you want to comment on that is far.

Let's take where it goes Tom had to read on the head as far as the value to the infrastructure kind of leads into the prior question.

Triple Crown as an example, we have.

Large system for gas gathering, which can offload to four or five different processors at any point in time, we see adequate processing capacity in the Delaware to handle not only our guests the majority of the basins gas in the near term as far as NGL takeaway is concerned were Lincoln our sales to those owners.

The production facilities to have pipe out of the basin.

On the oil side, we're doing the same thing 85% of our oils on type, we're selling to purchasers who can get inside of the basin.

On the gas side as we've talked about the residue gas side, we secure sales of gas our gas through 2020, 100% through the first quarter.

It is committed to be sold and we got 75% on the average over the remainder of 2020, that's committed purchasers all the while we secure takeaway.

On whitewater to get to Wall Hall, and also I think at our.

Earnings presentation, you'll see that we've committed to Whistler. So were long term thinking and it's all about getting that basin that are getting their product at a place.

Great. Thanks, and my other question.

Hey, let's just curious have you seen any significant change in the leasing environment and the Woodford Meramec.

Over the past few months or so.

Hi, This is John .

Well certainly there is a lot less activity within the whole stack play.

And.

Yes, I think it's fair to say not as much in terms of competition, if once looking for that incremental acreage.

So yes, thanks have slowed down definitely when that base current day, one change I've observed is because so many of our competitors are.

Passed with living within their cash flow. There are a lot of operators that are looking to sell non operated interest a number of operators because they are sticking to that discipline of living within their cash flow find that they only have the cash flow to participate in their own operated properties. So we've had some pretty good.

The charities.

In the Anadarko and in the Delaware basin to pick up additional interest and some of our projects at cost that.

Frankly, we haven't seen in years.

Terrific and just to clarify our are those things that.

Our people actively approaching you or you're just aware view as you see people go non consent that they are right in issue.

Hi, it runs the gamut.

Mainly it should stay make it aware that they are looking to to get out of the wells. If we're operating and submit system. We make an offer sometimes it is at Poolings, where we get through the pulling it varies but as Tom alluded to there is quite a few operators who to stay within that budget. They are getting.

From a non op perspective, so we've got very well and picking up some of that additional interest.

As an interesting aside and a statement of how free markets function private equity has come out of the would work on this subject private equity is highly attuned to this opportunity and the number of private equity players are actively soliciting relationships, where they will pick up this non operated interest if operators don't want to purchase.

So there's a there's a little market that's developing for this.

But it's a change in our business, we wouldnt have seen this a few years ago.

Great. Thanks, a lot.

The next question is from drew Venker with Morgan Stanley . Please go ahead.

Good morning.

You've talked a lot about maximizing NPV and rates return and including as you've talked about 2020 free cash flow is another important aspect can you talk about.

How spacing might play into your.

Optimization of returns versus.

Hi, This is NPV and the current commodity price backdrop as you sensed it.

It's kind of harsh at this point.

I think especially given that you have probably as good of an understanding of spacing.

And downhaul, well geometries as anybody.

Well I appreciate that question sure. We we've talked about this at length, and we love talking about it because we limit everyday.

We see the spacing decision as a trade off and the natural interplay between rate of return and net present value.

And we have these discussions everyday in fact I had a discussion this morning on a spacing project, where we made it clear to one another into our operating group that we will not.

Spend money to bring on non economic production at least I'll say, we won't do it on purpose and so studying these projects and understanding where your Breakover point is and when you should stop down spacing is really an important element. So we seek to not be waste.

All by having our wells to coarsely space.

And we seek to not be wasteful by having our wells to tightly space and there are waste of both sides of that.

Yes, it's not a one size fits all it changes from area to area. It changes from reservoir to reservoir.

No.

I'll, just say I've tremendous confidence in our team and our approach and understanding the science behind this.

John leads that effort and.

As I said in my opening remarks, we make mistakes were not perfect on this subject.

And yet I really am confident and saying that we are continuously getting better you want to comment on this John .

Well it just as a follow up I would emphasize what Tom said not one size fits all we definitely see variations in our spacing thoughts even within the Wolfcamp as we go across our acreage from culberson to reserves to Lee.

And on and there is somebody dynamics in there, but we have a very good understanding of it that we're able to adjust on a section level basis to come up with the proper spacing. So I feel very good about what will be able to do a 20 in terms of development projects and currently have planned and appropriate spacing for.

Thanks for the detailed was just thinking this as a follow up to that if you're using 2019 as a starting point and point of comparison, if your we end up being at the lower end of this 50 to $60 price range you laid out for 2020.

Does that generally by a few towards wider spacing and Conversely, if we're at 16 tighter spacing.

Well, we've run those models and we've looked at not only commodity pricing, but also.

Net revenue interest and I will say that that.

Our experience is that the boundary on over spacing can be so punitive that it's not really going to change within the price file that you just quoted.

I would not see us at a 60 or even $70 oil price, making different spacing decisions.

Thanks.

The next question is from Beijing with Credit Suisse. Please go ahead.

Good morning.

Two questions on costs.

First on Capex, there just brings tremendous progress this year cutting the Permian well cost by a 20% year on year, just wanted to understand our dear additional levers to move dot elevenfifty to 1200 per foot cause even lower as we look out to 2020 and are there any of that.

Being reflected in a preliminary free cash flow outlook.

Barry This is Joe.

We're constantly looking at how we can become more and more efficient.

A lot of the recent drop that we've seeing has has come as a result of service cost reductions on the completion side.

We're pushing hard to optimize efficiencies and combine some of our midstream.

Efforts and contractors and to land flow lines for wells to the midstream systems as an example.

We're looking at our battery design, so that we could.

Produced more wells into a battery and potentially apply a drill to fill type of strategy to optimize our completion costs. So it's hard for me to give you hey, we can reduce it by FX, but I will tell you that it has a strong emphasis around this company right now.

<unk> costs are relevant and this price environment and in order for us to really be a top performers. So it's our focus.

Yes opinion as far as it being forecasted into 20 are typical practices to kind of use the current fee that we have in hand kind of our current cost structure.

And not to make assumptions on better further improvements from there, even though there's potential for that.

Let me join the course here.

Yes, we want a fairly in transparently report our costs, we think the focus on cost per lateral foot is a good focus that said.

Similar ex operates over a fairly wide geographic range within the basin and our costs will vary significantly across the basin. We have some development projects in Culberson County that all in or below a thousand dollars a foot.

And we're averaging that with some projects in the deep basin, where you have a little more pressure and a little more drilling and completion challenges that that average at number up.

We also have some one mile wells in our portfolio, although on average, we're certainly going to longer and longer laterals as shown in our deck.

But I don't want to discourage our teams from bringing forward one mile projects that have outstanding returns and so we're going to continue to report a transparent average, but within that average there's a lot of structure.

Got it no that's really helpful color. Thank you for that and then similarly on the other cost item out east.

Historically oilier production growth typically put upward pressure on cost, but that has not being the case for you guys. This year going forward or how should we expect al you to evolve as youre couldn't youre growing oil production in the Permian, but seeing declining gas production out of MOCON. So do you think.

There's a bit more room to.

To come down the per unit basis.

This is Joe again I this quarter, we saw a nice reduction in our overall absolute lowi.

Even with the resolute assets coming on board tail into Q1.

We were down on the always side, but our Workover expense was up and that's a result of converting to lift so theres a lot of wells to lift so theres a lot of variables in that number because they've got the day today.

We cost operate the wells and then you've got Workover expenses at slide into that category as well our focus.

Just going to remain on the same items. We are now at the bigger bigger emphasis is going to be on SWT.

Salt water disposal, that's where the majority of our cost reductions that achieved and its were going forward there going to we're going to be able to take advantage of that's where that infrastructure that keeps pop and it's it's set up comes into play.

The the Optionality and the cost optimization at the systems provide us allow us to swing water to to use for our Fracs and at the same time, we're using our water for a fracs were not having to incur any kind of electrical charges to the SWT wells to dispose it although that sounds like a small item that cat. So.

For those efficiencies have been coming from and that's where our focus is going to be going forward, yes, maybe I'll just add on.

Highlights of our Culberson County lease operating expense per barrel in that county, orally or close to $2 a barrel.

<unk> expense.

In total total Permian early about 350 in court reported three dogs and 34 cents per barrel our production expense per barrel equivalent.

Looking at 2020, a blending of the Permian Anadarko, we still expect very competitive cost structure, even with the Permian growing more rapidly.

Got it no. This is really helpful. Thank you.

Your next question is from Brian Downey with Citigroup. Please go ahead.

Good morning, Thanks for taking the questions just quick one for me I believe you had recently tried an easy Frac completion, just wanted to confirm that that was correct and any color you could provide on cost savings uptime versus conventional or stage efficiencies I realize that maybe a small sample size that any cure curious on any comments and if you got future plans to continue using them when available.

Yes, we did just finished one trial.

Completion on two wells and we should not finalized all the costs associated with it. So it's still early for me to tell you the.

Fission sees that we may or may not have achieved what that operation but.

We try to because we want to learn more and we are working with our our main service provider to see how we maybe able to better utilize infrastructure electrical infrastructure that we have in particular, a triple crown.

Two in the near term distant future transition ourselves into that that realm, not only for cost savings, but also from an admission standpoint see tremendous benefit to cut in any kind of admissions or would be associated with brands.

Now so does that mean, you're using the electric infrastructure within the field are you still use and field gas or or I guess, what would be the final word for.

In this case the.

Right that we tried was using.

Fuel source not coming from our transmission lines.

CMG.

But going forward, what we're really seeing the true economic benefit.

Where we see again is being able to provider on power offer on grid.

And that could substantially we believe lower the cost to continue the frac.

Yeah, we own our own electrical distribution systems, Culberson County, and then a Reeves County.

And.

Like many others have.

Views, that's probably where electrification will ultimately go rather than towing a power plant around the oilfield. It probably makes more sense to have a power source that stationary and just equipment that is mobile we're studying this problem hard.

We have a team digging into it we're looking for so long range solutions.

And like so many things that we study hard they look a lot simpler to us the less we know about it and as we learn more and more it becomes more complex, but we're convinced that this is a long term direction that we want to go in and we're hard at work just.

Understanding the problem.

That's helpful. I appreciate the color et cetera.

The next question is from Niton Kumar with Wells Fargo. Please go ahead.

Good morning, and thanks for taking my question just a quick one I was looking at the Reeves County acreage and you need this presentation on slide 12.

Slight drop off about 13000 acres could you.

Help us understand what happened there.

Yes, if you look at our Reeves County, math or some acreage in the far south of the county that was an exploration play that we embarked upon a few years ago.

It's actually off the map on slide 12.

We don't carry any locations on that acreage currently we never have and some of it was due to expire we led to expire we just couldn't make economic wells there.

You want to add to that John .

We could make.

[laughter] that your part.

Okay all right.

So suffice it to say didnt meet the cost threshold.

I guess a broader question.

Tom in the past, you've talked about Optionality and kind of.

Having two basins as I look at the initial guidance clearly you're factoring the Permian and I get it why but how far is the mid con today for competing within your capital program.

Well, there, we could easily put 30% or more of our capital in the mid Con next year and that would be opportunities that compete heads up we have a lot of things in the mid continent that are competitive in today's environment that said as we've discussed in the past.

We are in a let's pull back and see what we can accomplish from a asset growth standpoint to mid continent.

John and his team are harder to work looking for new areas do landing zones, and we'd like to just beef up that asset and havent compete longer term.

You want to comment on that John .

The only thing I'd add is it is just what we're looking for more depth to that inventory. So there is a more sustainability to it.

So we're putting a lot of effort to not just looking across our existing acreage positions that we have.

And it Furthermore, looking beyond that because that's somewhat said earlier in the call there are opportunities now.

And we're just looking for work where are those opportunities, where we think we have maybe an advantage to get and maybe at a reasonable price and bring for things that would compete for capital. So that's kind of where we're at right now with the Anadarko basin.

Great. Thank you gentlemen.

This concludes our question and answer session I would like to turn the conference back over to Tom Jorden for any closing remarks.

Yes, I want to thank everybody for participating also thank you for your patience with our telephone interruption, we've had a lot of great questions and I appreciate the thoughtful probing a we're looking forward to executing on what we've laid out today and updating you with the our progress on future calls so thank you again.

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

And.

[noise].