Q2 2019 Earnings Call
Good day and welcome to the semantics energy coal IXYS see second COVID-19 earnings release Conference call.
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Good morning, everyone welcome to our second quarter 2019 conference call.
An updated presentation was posted to our website yesterday afternoon, and we may reference that presentation on our call today.
As a reminder, our discussion will contain forward looking statements 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 was filed yesterday and of course in our latest 10-K for the year ended December 31st 2018 for the risk factors associated with our business.
We'll begin today, our prepared remarks with an overview from our CEO , Tom Jorden, and then Joe Albi, Our COO will update you on operations, including production and well costs.
ATP it exploration John Lambeth Anorexia, a mark Burford are here to help answer any questions you might have.
As always and so that we can accommodate more of your questions. During the hour we have allotted for the call we'd like to ask that you limit yourself to one question and one follow up.
Feel free to get back into queue. If you like so with that I'll turn the call over to Tom.
Thank you Karen and thank you to all that have joined us on the call. This morning.
Sure works had a good second quarter and a challenging macro environment our production both.
Barrel of oil equivalent and oil production came in above the midpoint of our guidance range.
Total oil grew 5% sequentially with Permian, all growing almost 9% sequentially.
Oil growth is projected to continue with sequential growth expected for the remainder of 2019 and then to 2020.
Permian oil growth is expected to offset declining volumes in the mid continent.
We reaffirmed our capex for the full year, while raising our annual oil guidance by 1000 barrel per day at the midpoint.
Commodity prices had an impact on our cash flow and earnings this quarter with the price environment, we have faced particularly for natural gas and natural gas liquids. It would have been foolish to expect otherwise.
However in spite of these headwinds we expect to exit the year without incremental borrowing. Furthermore were pleased to be returning cash to shareholders in the form of our dividend, which we intend to grow over time.
We're bringing some outstanding projects online, they're delivering excellent fully burdened returns.
As we look ahead, we are completing the transition to a more consistent operational cadence.
Field consistency provides our best opportunity for consistent returns value creation and cash flow generation.
Constant stops and starts lead the field inefficiencies and increased costs. Our organization is focused on field consistency smooth execution and cost control.
We continue to benefit from the tremendous work, we're putting into understanding resource play development.
As we've said in the past Optum and development comes from understanding four key elements first understanding the stimulated fracture network, both along the borehole and away from the borehole.
Second understanding parent child interference and reservoir effects.
Third understanding proper well spacing and fourth configuring, an optimum project size and design.
Cimarex has discussed our learnings on each of these four key points. There is no one size fits all approach the optimum answer to each of these four issues as a function of the reservoir properties infrastructure requirements and economic conditions.
Through years of testing, we have gained a good and growing understanding of the requirements for profitable development within good capital efficiency.
I would again refer you to slides 24, and 25 in our presentation, which provides a window into our approach on the well spacing issue.
As we have studied development projects in all of our operating areas. We have grown more confident in our ability to design capital efficient development projects.
Two observed projects throughout our operating areas and to predict their outcomes. This has also given us the inside the stand out of some non operated projects.
Our results thus far this year speak for themselves.
We won't be making any detailed comments on our development activities in our prepared remarks I'll give you a quick overview of 2019 of course, we are prepared to answer any additional questions you may have.
As you know our 2019 capital is primarily allocated to the Delaware basin with majority going to upper Wolfcamp developments in Culberson Reeves and Lea County.
Four of the five culberson developments or online.
Three of the five Reeves developments expected online in 2019 are already producing and the Voce drug development. Our single development in Lee County. This year is currently flowing back.
We have three additional developments that will be on production later this year.
Operations are underway on several projects that will impact 2020, we currently have eight rigs running in the Delaware along with two completion crews.
Now I'll turn it over to Joe Albi, who will discuss our operations in more detail.
Thank you Tom and thank you all for joining us on our call today I'll touch on our second quarter production, our Q3 and 2019 full year production guidance.
And then I'll finish up with a few comments on LOE and service cost.
With a nice jump in our second quarter production, we continue with our strong start to 2019.
Our Q2 net equivalent production came in at a company record of 275000 deal we use per day right at the top end of our guidance range of 263 to 275000 barrels per day.
With the Mark our Q2 19 net equivalent production was up 6% over Q1, one nine and 30% over Q2 of 2018.
On the oil side, our company record Q2 oil volume of 83.4 thousand Boes per day.
Came in nearly a thousand barrels per day above our guidance midpoint.
And was up 5% and 35% from our Q1 19, and Q2 18 postings respectively.
The Permian drove the increase with our Q2 Permian oil volume of 70.7 Mboes per day up 45% over the 48.8 thousand barrels a day, we produced in Q2 18.
With the posting the Permian now accounts for 85% of our total company oil production.
As we look forward into 2019, we're reiterating our full year 2019 capital guidance and activity levels.
We've tightened our full year net equivalent production guidance to 263 to 272 M.B. always per day, keeping the same midpoint as our previous guidance.
And we've raised the midpoint of our full year net oil production guidance by 1000 barrels per day with a range of 83 to 87000 Boes per day.
For Q3 were projected net equivalent volumes to average 265 to 279 Mboe per day with our net oil volumes forecasted to average 85 to 91000 barrels per day up approximately 5.5%.
From the midpoint of or at the midpoint from Q2.
Shifting over to Opex with Resolute properties now on our books, our Q2 lifting cost came in at $3.51 per BOE. We that's just slightly above the midpoint of our guidance of 320 to 370.
And it's down 11 cents per BOE, we from our 2018 average of $3.62.
With our continued Permian focus we're tightening our full year lifting cost guidance with a new range of $3.30 to $3.65 per Boe.
And lastly, some comments on drilling and completion cost we've seen general market conditions remained relatively flat since our last call on both the drilling and the completion side.
That said with our continued focus on challenging completion design and operating efficiency, we've reduced our completion fees by 5% to 6% since April which translates into an attractive total where well cost reduction reductions in the range of 300 to $500000.
For each of our two mile lateral wells, depending on the program.
And our Wolfcamp program with a tweak in our completion design, we've dropped our two mile completion ASV by $400000.
As a result, our generic Reeves county, two mile Wolfcamp, a well is run in 10 to 12 and a half million dollars.
Depending on facility design and Frac logistics, that's down $400000 from last call and down $900000 from our estimate late last year.
Our shallower Wolfcamp, a wells in Culberson county around about $600000 less than the RIV Reeves County, Wolfcamp, a wells with an at the range of $9.4 million to $11.9 million.
I want to point out that with the efficiency gains derived through our multi well development drilling projects, our average development well development project per well costs are falling at the low end of these ranges.
And then the mid continent with the refined completion design and improved operating efficiencies, we've reduced completion cost in both our Woodford and Meramec programs.
Our current two mile Merrimack fees are running nine and a half to $11 million that's down another $500000 from last call down $1 million from late 2018 and down more than $2 million from the cost we quoted in early 2018.
So in closing our solid second quarter gives us a great springboard into the second half of the year with nine net wells previously planned for early Q3 first production coming online during the last two weeks of June we are forecasting a nice ramp in oil production in Q3, and Q4, resulting in an increase to our full year oil guide of 1000 barrels per day at the midpoint as compared to our guidance last call.
Our cost structure is healthy.
We're projecting similar FFO full year lifting cost guide as to as compared to last call and weve derive significant well cost reductions through efficiency and completion design.
We remain very well positioned to deliver the capital activity and production plan that we laid out for you at the beginning of the year, so with that I'll turn the call over to.
Q anyway.
We will now begin the question and answer session to ask a question and May press. The Star then one and you've touched on film.
If at any time. Your question has been addressed you love to hear your question. Please press Star then.
The first question.
Comes from Aaron Deer, Yara from JP Morgan. Please go ahead.
Yes. Good morning, Tom I was wondering if you could elaborate on some of your prepared comments when you're talking about.
Your expectations on a sequential oil growth into the second half of the year per your guidance into 2020, and how you're thinking about capital allocation next year, just given some of the headwinds weve seen on the NGL.
And gas side of the equation.
Well, yes.
Certainly 2020 is feels long ways away right now I will tell you that we're putting a lot of energy as I said my remarks on just planning our field effectiveness and smoothing out our field cadence as we talked about this in past quarters.
We would be ready to go for sequential oil growth now that said, we have informed our 2020 plans the commodity headwinds are certainly a major factor.
We're probably a little more bullish on on oil as the contribution or revenue and you're not surprised to hear me say that particularly with the.
Macro environment, we're seeing on gas and NGL pricing. So although we have formed 2020 plans I will say that.
To the extent that reallocating capital, we're probably going to want to be emphasizing oil.
And then although we'll be prepared for sequential growth.
We haven't formed or 2020 plans and we'll make our decisions when the.
Appropriate.
Great Great and just my follow up.
Maybe for Mark but was wondering if you could talk through.
You are marketing arrangements of around your Permian crude I know theres, a new west, Texas light benchmark out there. So just wanted to see if you could give us some thoughts or help as we model your Permian differentials on a go forward basis.
Hi, everyone. This is this is Joe.
Really for for the most part in Q2 to the extent that W. TL was or the higher gravity was a impact on our pricing.
We had already seeing that just have that in the.
During the second quarter, the indexes were seeing its wtf index.
Compared to.
Hi, this is now less than than a dollar.
We anticipate we'll have one other contract.
Fall under the W. TL.
Basis here by September .
And when we look at the volume representation of that contributor relative to our total Permian oil price I'm anticipating that that might have anywhere based on current strip.
In the neighborhood of maybe 30% to 35 cent overall hit on our total received oil price.
So.
Right now the deal with the basis at less than a dollar we're getting a premium to that W. TL and the revised contract that we're looking at September I don't know if that helps.
That's helpful. Just a an approximate mix of your you know your Permian output how much of that would be levered to maybe that the WT outposts that new contract versus W. T I.
That would be helpful.
Well, let's see I can give you a ballpark here.
Before assuming a locker room.
[laughter].
I'd say, it's probably about.
A third to a half.
In the end, but again a lot of that pricing is already in place.
Okay, all right. Thanks, a lot Jeff.
Your next question is from Neal Dingmann with Suntrust. Please go ahead.
Siddique among your line is open.
I apologize good morning, guys.
Tom you mentioned about the consistent cadence and I'm just wondering how do you when you and John and guys think about this balancing that was the optimal size of your Delaware pads going forward.
Well those are.
Really two related but independent issues.
The optimum size is kind of stands alone from.
Cadence, we look at the infrastructure requirements, we look at the amount of water handling at peak, we look at takeaway capacity, but first and foremost we look at the reservoir and to what extent is the reservoir forgiving of add ons and to what extent do add ons introduce complications in the parent child.
The issue.
So we you know we we look at all of that I will say this.
If all else were equal and reservoirs were infinitely forgiving, we would probably go for smaller projects and that may be six to eight wells per project.
Rather than these these large projects just for a whole host of reasons.
But let me let me, let John comment on that.
Well I think Tom hit hit most of the points relevant that that I think the biggest thing that controls that for US is just the amount of infrastructure required when you bring that many wells on.
Both on the water side on the gas side.
And what we tend to find in many of our areas that that as Tom alluded to that six to eight wells at a time is a pretty good both cadence.
But also.
Seems to fit well in terms of the pace of our infrastructure investment.
If we were to go much beyond that and quite frankly, I think we'd be subject into potential.
Problems with getting consistent growth because there is lot of moving parts out there.
So right now whether we are looking in culberson or reeves or even up into Mexico.
Typically most of projects that were proving to development projects are in that six to eight well range right now, yes, but you know what it among the many factors we consider we value the economics of our asset throughout the asset life. So if we if we do a project in one of the considerations in determining its size is when will we come back to add on and what impact will that production have on future development. Both the impact that production will have on future development and what impact will the future development have on that production.
And so we as we gained an understanding area by area and reservoir reservoir, that's important consideration to us. Some reservoirs are very forgiving you can come back and they will have no impact. Some reservoirs are very unforgiving. It also involves understanding where your frac barriers are within your vertical section and so ill just say again its not a one size fits all we'd like to make tailored decisions around particular project.
Great Great and then just one follow up can you talk about.
Investing your capital spend specifically how did you arrive at the midpoint of Capex of the year. It looks like you've already brought on about 60% of the wells and with about 60% of the Capex budget. So if you could just address that thank you.
Yes. This is this is Jeff.
When you look at what we report and and what we're forecasting for Capex. There's a lot of moving parts. We've we've got carryover dollars that were incurred 19 for 18 activity you've got dollars that we're going to spend here in 19 had to carry into 2020 activity. We've got infrastructure dollars, we got salt water to.
Disposal dollars and then on top of that we've got the timing of activity relative to when dollars get ultimately recorded in June we completed bright online 13.1, net wells 9.4 of those wells came on during the last two weeks and as a result of that we are anticipating that that carryover is going to flow into Q3, and then ultimately equate into the range that we've given you guys.
Great. Thank you.
The next question is from Matt Portillo with TT age. Please go ahead.
Good morning, guys.
I was wondering if you might be able to elaborate a little bit on the completion design optimization and what may be driving some of those cost tailwinds that you highlighted at the beginning of the call.
Well I'll take a stab at that Weve. There are lots of knobs that one has to turn on completion design and certainly spacing.
Stage spacing cluster types of cluster design number of clusters per stage amount of sand and fluid pump rate.
Are you zipper fracking or not I mean, all of those add up to the speed of efficiency in the field, but first and foremost we focused on completion effectiveness and we've done a lot of work on downhole effectiveness, we want to have a balance between cost effectiveness and completion and productivity effectiveness.
And so we look at all of that and try to strike the right balance I think we do an excellent job of it were always getting better and always questioning our core assumptions.
But I'll just finish and then let John comment first and foremost you have to understand your downhole fracture geometry, or you can make some really bad assumptions as it flows through to your other decisions.
Really that just add on what Tom just said.
We have been tweaking a few of our parameters I am not going to go into details on those parameters.
What is nice to see is over time, we're starting to see the benefit of those tweaks, we're starting to see.
A little bit faster cadence with each well that we complete so were seeing a nice cause and effect.
And yet with those minor tweaks, we're not in any way degrading the performance of the wells. So it's kind of what we've always wanted to do that we feel like in some cases, we have a pretty optimal design from a from a you are well performance basis.
And now we're making the small tweaks just an overall design that leads to a few more efficiencies the jobs get done a little bit quicker, which lease a little bit lower cost, but still not sacrifice. The overall performance of the well I think we're starting to see that more and more with a number of these development projects that were bringing on.
And I guess I'd add on top of that that beyond the design the fluids type C amounts the amount of sand et cetera.
Efficiency of execution out in the in that field is paramount so quicker clean outs quicker stages, all that translates itself into an overall more efficient and cost effective program.
Great and then a follow up question around 2020, I know things are still in the works in terms of the planning process. There, but I was wondering if you could comment a bit I guess on just given where the strip is at the moment for gas and NGL prices, how you're thinking about capital allocation.
To the mid Con next year versus kind of how things shake out this year and 2019 and then Tom I was wondering if you could flush out a little bit more just some of the commentary you mentioned at the beginning of the call in terms of the potential for continuing to show sequential oil growth quarter in quarter out as you move into next year, maybe the implications for.
From a high level perspective kind of year over year growth on on oil volumes going into 2020, and again I know things are kind of in the works, but just any incremental color you might yield right there.
Yes, I'll take a stab at both those.
Although we have informed our 2020 plans I would not anticipate our capital allocation.
Significantly changing now we can argue about what significant means.
We're in the process in the mid continent of trying to develop some new plays and some new concepts we've talked in the past that we really like Anadarko basin.
And we'd like to find some new things there and so that will probably be our dominant focus in the Anadarko basin, which will lead to a capital allocation that we will again be disproportionately in favor the Delaware basin.
And then in terms of the comments I made that you've asked me to follow up on sequential growth.
I will say that as we look ahead into 2020.
Well, we certainly have the capacity for a meaningful oil growth and delivering that and the sequential fashion.
But we have informed our 2020 plans and theres going to be some some soul searching on.
What the macro environment is and what we got to do with our capital.
But yeah, we put a lot of work in the field efficiencies, we put a lot of work into organizational effectiveness and planning and we certainly have made tremendous progress as we discussed in the past on Smith.
The next question is from Doug Leggate with Bank of America. Please go ahead.
Thanks, Good morning, everybody.
Told no question that your execution excellence continues to.
To you know to do there.
Exactly what you you you've guided us towards over the years focus on returns focus on capital discipline and so on.
My question I guess is really more of a high level philosophical question as to how to use.
Physician similar acts today to compete with a broader market because clearly what's happening in energy is pretty unprecedented as it relates to investor appetite for exposure to the space. So.
What is the right growth rate, how do you compete with the broader broader industrial sector and how are you thinking about potentially repositioning the company in this somewhat challenging time, we're in right now.
Well those are those are great questions Doug.
Yes, I think that all of us have to ask the question is what is the proper growth rate if at all.
We certainly have capacity to grow but I think that we are asking fundamental questions. All right. What's the growth rate that we think is.
Appropriate.
What amount of free cash can we and should regenerate and then what do we want to do with free cash I mean, those are the similar questions right now, we're all being challenged to behave like good manufacturers and I'll say at Cimarex, we accept that challenge.
We've had to do a little bit of internal work that we've talked about in terms of getting our field cadence more predictable, but then once we have that work done which I believe we do.
Now, it's it's beholden upon us to get to work and deliver consistent returns and deliver those returns to shareholders. I'll say this I think that if we could open the hood and let people look inside that some of the capital projects that were executing I think we would stand out for prudent.
Investment decisions and generating returns that are showing us that the effort we put into development learnings are paying off.
But you know these are these are all good questions were wrestling with that I think you'll see our 2020 plans reflecting that wrestling.
And you know we accept the challenge that and Mark do you want to comment on that.
Yes, Tom this is definitely items that we had we contemplate Doug as we as we've discussed in the past at your conference there.
Got the competitiveness of DNP trying to stack itself up against other industries and make it more attractive for the broader market.
And did not generate free cash flow.
And it's an amount of growth returning it to shareholders through dividends and other measures youre, making there are.
Our MP business Dart are set to more attractive and its something similar extra definitely focused on we've always had a focus on return on investment because you are getting full cycle returns and take that next step house can we further.
Make our stock in our AR.
Demonstrate that that return to shareholders. So.
Yes, I am going to finish Doug by making up youve environment to be philosophical and I'm going to take could take you up on that.
You know, we're all very short term in our thinking.
And worst subject to markets are subject to it.
And we always think that current conditions are the new normal and will be permanent conditions. We're in a cyclic business, we've seen lots of cycles and so we remain focused on the long term on developing and executing a business. That's sustainable that can withstand the cycles and commodity we remain cognizant of the fact that one or two world events could change this conversation materially we're confident that the world needs. The products, we produce for decades to come and finally, the things we're being asked to do show capital discipline.
Show that we can grow modestly and generate free cash flow demonstrate to the external markets that were prudent stewards of capital and making investments that are.
Efficient and effective those are good things to do regardless of changes in the macro environment, but so we're going to get after and we're going to demonstrate that we can adapt but we're also going to remind ourselves that we're in the business for the long term and that the things, we see and feel today may not be around forever. That's certainly been our experience. So we're here for the long haul.
I appreciate answering the question Tom you certainly been very consistent not message I certainly credit you this up.
If I may just a quick operational follow up.
There's a lot of moving parts on infrastructure, obviously going on in the second half of the year going into 2020. So I just wonder if you could kind of sum up the prognosis for for you guys as it relates to gas and NGL prognosis. If you like for how you see your differentials evolving I realize there were some accounting fundings on your gas realizations this quarter, but.
Any any help on line of sight as to how you see that moving into the next year and I'll leave it there. Thanks.
Yes, Doug looking at the Citi starting in the second half of 19 looking at the.
Well high in the past Permian gas price index, and we're looking around a 77 index for Q3 going $1.50 on the futures curve for Q4, so averaging just a little over a dollar dollar 20 or so for the second half year.
So we see that improving into the second half the year with Gulf Coast Express coming on futures markets, reflecting that and we expect our second half gas realization to improve and then you mentioned some of the differences with our reported realized price relative to.
With the counting.
ASV six those six which has some transportation and processing cost netted against it.
Which in Q2, there was 40 cents, an mcf of processing and transportation cost that against our realized price and that will continue selling in order to model the forward price.
Need to incorporate that differential for six to six netting against our price, but we gave you the magnitude of that that impact in our press release in the table.
And there's a transportation on the transport offset all right in terms of the guide.
That's it that's right Doug the transport offset exactly right.
And then going into 2020.
We see at a forward curve that athletes a fair amount into 2020.
In the first half of the year unit or first quarter is the as high as the dollar 70 going to 80 cents in the second and the dollar but on average it's averaging that Permian prices are averaging around $1 $30 40 for counting count 20, and a similar type.
Improvements our realization out to what we've seen.
In the second quarter of this year.
Got it appreciate the answers guys. Thanks for your time.
The next question is from Brian singer with Goldman Sachs. Please go ahead.
Thank you good morning.
Hi, Brian .
A couple of follow ups to the ones that have been asked earlier first on the mid Con you talked about new play concepts that you'd be working on or that you are working on can you just talk to where those where those stand and what you would need to see to allocate more more capital there in 2020.
Well I don't want to comment on any any particular place or the evolution of then we'll talk about and what we have results talk about but.
The second one is easy well, we would need to see or material returns that compete with our Delaware basin.
Certainly a lot of what we have in the mid con that today competes I mean, we're the capital. We're allocating is allocated the mid con that because it competes heads up with what we've seen in the Delaware, but you know that the robust inventory. There is not the same way of a deeper inventory of those things in the Delaware that compete for top tier capital than we do and the Darko and so what we would need to see is deeper inventory and some great returns out of new and emerging place.
And would you allocate rigs back.
Normal pastime among the base legacy legacy plays.
Relative to current levels.
Brian I would send rigs to the Moon, if we would make good profits doing so we're here to make money and.
We do that's that's our only bias is make money and be able to.
Make money through the commodity cycle. So absolutely we would we would reallocate capital if we thought it was in the best interest of our shareholders.
Great. Thanks, and then my follow up is it you've touched on this a bit earlier, but as it maybe it's part of your soul searching process for.
For 2020, it sounds like you're trying to.
Fine that precise optimal point of growth.
Asset level returns corporate level returns and free cash flow, but can you kind of talk to those weightings, a bit and particularly the importance of.
Free cash flow as you think about that 2020 plan versus that asset or corporate level returns.
Well, yes, I don't I don't know that we're doing any deeper broader soul searching everybody else I mean, I think I think we're all asking the question of alright, what clearly clearly growing at maximum capacity is not what.
The we're not getting market signals that thats, what people want and we are listening log unclear. We are also deeply cognizant of the fundamentals of supply and demand and that.
We certainly have some market bottlenecks so.
Were you know I'll just say this many of us throughout our industry and not just speaking about cimarex that many of US grew up in a world where we grew at the maximum rate, we could sustain and clearly today, that's not what we need to do and so it's a it's a tension between art do you want to grow at all and in so doing in making that decision.
If you throw your back your gross back you may generate free cash flow and then what do you do with it I mean, I'm just repeating myself here, but I think.
Anybody in the MP sector Thats paying attention is asking the same questions.
And we'll all have different different answers based on our portfolio our balance sheet and.
Our assets.
Great. Thank you.
The next question is from Microsoft with Brown Advisory. Please go ahead.
Hi, guys.
My question is along the lines on capital allocation I think it was about a year ago on the second quarter earnings call, there's questions and a lot of discussion about whether the company would initiate a buyback and I think I recall that you looked into it talked with the board and at that point in time, you guys decided not to do one if we fast forward to today you know the stock is about half of where it was then.
Oil prices are down a little bit, but and I'm, just wondering <unk>, especially as you alluded to what would you do with the free cash flow. If you went into a no growth state why there's no discussion currently at least to us about a buyback you know that the stock is down tremendously the NPV by Anybodys measure is much higher than the current stock price.
Yeah with liquidity on and the stock trading where it is you know can you give us an update on your thoughts as to what management is thinking.
Well, it's certainly.
Your points are well taken.
And the argument for buyback is more persuasive today than it was a year ago or two years ago.
But you know we will announce any decisions that we make once we make them I mean, we're we're always looking at it.
And it's a question of how much free cash do you have and is that where you want to deploy it.
Where we're really not a team that likes to get drawn into speculation you make good points and I acknowledge them and we certainly think that.
Our <unk> our share price is at a point, where any analysis. We have done in the past is outdated Mark you want to follow up on that yes, I think thats a.
Continue evaluating I think its a buyback.
Moving to self it's probably.
Looking at the valuation relative valuation your stock relative to other investments is something we've always taken account and right now with our stock price where it is relative attractiveness has only increased so we have to continue to evaluate it.
And I think if we had free cash at this point, we're still kind of neutral at this point, but as you look forward into outer periods do you still expect to your free cash flow and and I think we want to be eight looking it always that delta between what we think our stock valuation is and relative to other investments.
And this would be the point in time, if we had free cash flow right now in cash and the balance sheet, we definitely I think he's strong advocates of utilizing that.
I'll just leave it with US I think would sign a pretty strong signal to investors that the company recognizes the value of its own stock, especially given the long reserve life, we have and the a significant discount you have to that on valuation.
We we agree with that and I appreciate your comments.
Thanks.
So next question is from Jeanine Wai with Barclays. Please go ahead.
Hi, good morning, everyone.
Hi, Jeanine Vernon.
My first question is on efficiencies. So so far this year, you've completed more wells than anticipated due to a better efficiencies and can you quantify some of these efficiencies in terms of drilling or completion days and comment on how sustainable you think these are going forward I know you discussed in your prepared remarks. The end result, which is lower well cost, but just looking for a little more detail.
Yeah Jeanine.
The efficiencies that we really saw that I guess are evident in the.
10 extra wells that show up as online in Q2 versus Q3. They are really about two to three weeks worth of.
Of benefit that we saw from when we were able to turn on turn wells online and start to see first production.
So when we put our models together, we obviously using can't charts et cetera, trying to line up everything including drill outs or what have you. We've just seen over the last quarter.
Just some some very good efficiencies out in the field without any hiccups.
We've also seen these wells ready for production when we were done drilling out plugs with facilities and flow lines.
And and they started cutting hydrocarbon earlier than we had forecasted as well so.
We built a little bit of cushion into our forward looking guidance and and those wells just beat it.
Okay. Thanks, and then my follow up call is kind of following up on a couple of the other question. So regarding those 10 extra net wells that you did in Twoq even plan.
Can you talk about the process of eliminating those 12 wells in the back half of the year it sounds like to make up for it in the schedule.
Can you discuss the process for that in terms of maintaining the operational consistency that youve talked about it sounds like the quarterly timing shift might not be that big of a deal because of how late in the quarter those extra wells War.
And the way we see it you've got a lot of docket at the end of the year for Optionality heading into 2020, if you choose and then maybe an unpopular question, but is there a scenario where you would just consider keep going and pulling forward. Some of the 2020 wells into 2018, because it's the best thing to do operationally so.
Perhaps short term pain for medium term benefit I know you mentioned demonstrating that you can adapt in the current environment, but also that the market is a bit short term focus right now.
Well when you dissect our plan, what we really saw as just some.
Small accelerations of wells coming online from Q3 into Q2 and I'm talking weeks on that.
Hi, Mike.
Wait a month in advance.
And and some of the Q4 wells getting pulled earlier into Q4 and or even maybe the the tail end of Q3.
The end result, as far as this year is concerned.
We're pretty darn right on top of what we thought we do from a total net wealth standpoint, we're looking at about the same amount of ducs at the end of the year.
And then as far as trying to do anything and acceleration.
For 20, and 19, we're going to be very very cognizant of our capital and how much money, we're spending and 19.
Okay. Thank you very much.
The next question is from Mike Scialla with Stifel. Please go ahead.
Yes, good morning.
Just wondering now that you've entered a firm transport agreements or natural gas. If you revisit your thoughts on firm transport for oil at all.
Yes, we actually have we've been looking at and have entered into an agreement for.
Takeaway to the Gulf Coast out of the mid continent, which also gives us an offload.
And two are from the Permian.
And it's about 10000 barrel a day commitment expandable up to 20 and it begins the first quarter of.
Okay.
2021, so it's going to get us the ability to get out too.
To the Gulf Coast.
Belmond Corpus Christi, Houston ship channel with our oil.
And taking that oil either out of the mid con, Ed and or the West Texas area.
When you look at the spectrum, but what we're doing it's not only on the oil side, we put together long term arrangement for our mid con a gas which in here.
And then in the Permian, We've we've got had got some from out of.
West, Texas into Walheim, then with us getting onto the Whistler project.
At up to 125 million a day, we're looking at all the means to get out of the basin that we can and at the same time, we've locked up all of our gas sales for all of our residue gas through.
The majority of 2020, and so its really assurance of flow and then now trying to get to the better markets.
You think you are done in that regard at this point is that.
There is still more to go there I mean, we're always looking so it's over.
We've taken some steps above and beyond where we've been and we're going to continue to take additional steps going forward.
Okay, and just wanted to ask from an operational standpoint last quarter, you talked about and you mentioned in the slide deck.
The SER Barton and broker tip pads, just wondering what the end result was there I know you are testing X y sands.
Some spacing.
What did you learn there.
Yes.
Both of those.
Pads stir barden brokers to those were seven wells each that we brought on.
They were indeed testing as part of that development different landing zones with some of them being pushed up into what we call the high sand.
Instead of our more regular upper a landing zone.
Both projects are very economic for us, we're very pleased with them, but there has been some important learnings we are definitely seeing that if we can get those landings further up and get a little bit more vertical separation with the lower tier lay means we definitely like the results of those wells versus wonder a little bit more crowded on a vertical basis.
And so thats something that were incorporating in fact have incorporated into our next development project on the west side of Culberson would just carry back.
Also I would just say so far.
From from a cost standpoint, and Joe alluded to this.
We're very pleased especially on the western side of Culberson that what we're seeing so far on a cost basis and I would just say this is specifically just to this just these two projects.
But so far we're work we're seeing about a thousand dollars per foot cost on that development project combined for both of those.
Which is a very very good number and something that we expect going forward, especially on the western side, where it's a little bit shallower little bit lower pressure and thus much quicker drilling for us.
Very good thank you.
Okay.
The next question is from Jeffrey Campbell with Tuohy Brothers investment. Please go ahead.
Good morning.
I'll keep my question to one with a kind of a two parter.
We've been talking some about.
The new plays you're trying to.
They're down in the mid Con and the first question I want wanted to ask us.
In any of these efforts take place on existing acreage and the second one is if there is some success here with this increase in any potential for M&A or is this going to be an entirely organic effort.
Well certainly, yes, we have a very large acreage footprint and Anadarko and.
I have high expectations that among that footprint, yes, there will be opportunities of other landing zones or other intervals that.
It might lead to much better returns than say, what why we originally leased at which let's face it.
A lot of acreage was acquired and then drill at a time when natural gas prices were much higher.
So that essentially establish that footprint for us and as we've said in the past.
All of that acreage is held by production. So we have the luxury of digging in.
Understanding the overall stratigraphic column and then as Tom alluded looking for those intervals that clearly have the kind of hydrocarbon mix, which in this case means oil.
That with the right kind of drilling complete cost could lead to returns.
That could be competitive with our Permian program.
As far as could this lead to M&A I don't know I mean, obviously, that's an option, but first and foremost we have to our self be convinced that a we have found a zone that will compete for capital on ongoing basis, which means there must be size there must be sustainable.
And in that scenario, then yes, I think we would then see what other opportunities might be out there that could complement that that's above and beyond our existing acreage footprint.
Okay, Great I appreciate the color I will see you in New York on Thursday. Thank you.
Your next question is from Michael Hall, with Heikkinen Energy Advisors. Please go ahead.
Thanks, Good morning.
I appreciate the time.
Just wanted to think about or look at capital efficiency a little bit.
If I look at your year to date oil volumes and then third quarter guide.
Going to indicate the fourth quarter oil midpoint around 89.
Mboe a day.
Which we show as basically flat to maybe a hair down relative to Four Q1 8 pro forma.
For the resolute deal.
Is that a fair way to think about that if we look at the 2019 capital is it fair to think about 2019 capital is basically kind of a maintenance level for.
For your oil volumes at this point or.
Yes, I would say they are kind of transitory factors. It maybe suggest thats an inappropriate way of looking at a capital efficiency at this point.
Yes, Michael you know Theres, a lot of ways and look at capital efficiency and if you look at the capital that the pro forma capital along with pro forma cap from resolute in Cimarex quarter, both are ramping significantly to the fourth quarter. Both had a very high exit rate in the fourth quarter with our teams our completions that year, but definitely overplay on how you look at relative.
Fourth quarter, the fourth quarter.
Rates and.
The maintenance capital with resolute and as combined trying to maintain a flat fourth quarter, the fourth quarter, I guess and we our capital on a pro forma basis is down significantly year over year as we've made as we balance our capital plans to our cash flow into into 2019.
So I guess, so if you'd want to argue that.
With adjustments in our capital it by holding our capital our production roughly flat and Thats maintenance cap I wouldn't need to speak to you on that yes.
I just want to remind you that resolute was on a pretty massive outspend and as we folded that asset and certainly faced a commodity environment those little more hostile than what we anticipated we made the decision to.
During the combined entity forward within cash flow, but also want to say, we're very very pleased with those assets and we haven't talked a lot about operational detail in this call, but I will share with you that we are currently flowing back at San lot project, which was essentially an extension of a development project. The resolute had done two phases on.
On our extension, we incorporated some of the learnings that we brought and as we flow those wells back we're seeing significantly higher performance out of our new wells than had been the average on that project in prior we're seeing higher oil recoveries better returns.
And so we're we're really like those assets and we are seeing fruits of all the reasons why we wanted them in our hands.
Okay I appreciate that.
And then I guess as a follow up as you think about the weighted on completion count.
At the end of the year relative to your expectation around exit rig counts and crew counts.
How does that look relative to normal and.
You know what sort of timeframe, if thats above normal what sort of timeframe would you suggest is fair to think about that normalizing back down just trying to think about 2020 capital efficient.
I'm not I'm not certain what you're alluding to are you talking about the number of let's say frac fleets that we're running right now versus.
Beginning of the year.
No just the weighted on completion count that you provided for year end 2019, if you look at that relative to your expectations of rig and completion crews at the end of the year.
Yes, I compare to normal and helps yes, microparticle a normal level, but we have gone from three frac crews to two in the second half the year set has some bearing on that at the current year and 18, we had 28 net wells that were kind of waiting on first production. Those that has increased we're obviously protect 42.
Well, we're expecting they'll be waiting on production at the end of <unk>.
19, so it is up a little bit, but it's both are flushing that going from three crews to cruise as you go into 2000, we expect that to go back to three and it's still always is more of a over bigger overprint is the timing of the projects are developing the size of the different projects. That's the bigots overprint I think those nine net wells that kind of slipped a couple of weeks and end up in Q2 are really playing a role on and how it's I guess being perceived out there, but last quarter's guidance for the last half of the year, we were projecting 34 net wells.
For the last half of the year and right now were at 27. So all that's happened is a few wells slid into Q2 right at the very end of Q2.
Yeah.
Okay, but.
As I just think of I was trying to think about like 2020.
Potential tailwinds to 2020 capital efficiency from that that backlog of weighted on completion wells. It doesn't really sound like thats, particularly out of normal, particularly if you're going to pick up a completion crew a fair.
No Andy the Ducks are.
Virtually about the same in fact, a little bit more on our current forecast so.
Again is just some slight moving of of a couple of that wells is all that's really go.
Okay.
All right. Thanks, guys.
The next question from my Kelly with Seaport Global Please go ahead.
Thanks, guys good morning.
I'm a big fan of the Slide 13, you haven't here, which highlights your oil productivity in culberson relative to.
Other counties in the Delaware and with this in mind.
I was hoping to have you guys maybe.
What we could expect out of your Reeves County acreage in terms of oil productivity and ultimately the returns versus your kind of core culberson acreage and do.
Acknowledging that reaches a massive county too and did you guys hopefully be a board sweet spot, but just want to get your thoughts there. Thanks.
Yeah, I I know when you look at that slide and I'm, a big fan of that slide as well.
But its certainly highlights in a in a very significant way the performance of Culberson, which basically when you see culberson that summer Rex I mean, that's pretty much you comprised as those wells.
Whereas what Weve done is of course go onto the state data an amalgamated all the two mile laterals from all the operators and to making that graph.
And without a doubt as you said Reeves is a very big County, and as you can see on that particular graph Reeves tends to fall after 18 months to the lower end.
I can tell you that we've looked at that graph separately, just with similar ex wells and yes, we definitely separate ourself from what that background trend shows and yes, we feel very good that the acreage that we have and that recently acquired through resolute is some of the better acreage in Reeves County that does lead to better cumulative production than what you see as the average there for the entire county.
Okay, great to hear thanks, and you can't help but notice you've got this nice slide also here in the water infrastructure and just wanted to get your mid high level thoughts on what you think is a good value that we could potentially pegging that that system and.
If there's any kind of updated thoughts on your desire to to monetize that thank you.
Well value is and of course, you know water is becoming a bigger and bigger part of the Permian basin business.
You know we are we're always assessing that and I've I've talked in the past and they'll say again that.
There there may indeed be a point in time, we're monetizing some of our midstream assets make sense to US right now say the value we get out of it is low operating costs access to water for recycling and a really good environmental footprint with the way we've designed that water infrastructure.
You know with these monetization deals it ultimately becomes a trade off of Capex for Opex I mean, certainly we're investing capital in that system. If we were to sell it we would have a higher operating costs through a fee structure, but we keep that analysis evergreen we look at it as a business and.
There may indeed be an appropriate time, we will decide to monetize it but right now the biggest benefit for from US is operational efficiency low operating costs and it's really helping us also.
Have capital savings in water recycling so.
It's a great asset our team has really done a creative job in building it.
It's.
Something we're very proud of both from just an operational efficiency, but also in environmental footprint.
And monetizing it is not off the table.
Yes, but I'll just say this we look at it constantly and when we think its make sense we'll.
Move forward.
To elaborate a little bit further to Tom's point, just the recycling alone.
Is potentially saving us anywhere from 350000 to $550000 per well from a development cost standpoint, so when you multiply that by the number of wells potentially at Carpe Culberson, we're talking a fair amount of.
Capital reduction by virtue of owning it.
Got it I appreciate that color.
Your last question is from do Bank with Morgan Stanley . Please go ahead.
Hi, everyone.
Tom you talked about shifting to us more consistent activity pace and can you just talk about kind of what that what that looks like and where.
The right level of activity is assuming at the cash flow to fully fund enough.
Rig counts are.
Frac spreads there.
Some more high level way to quantify quiet.
Quantify that measure.
Well it it yes, you bet, you're having we're currently running eight rigs in the Permian and I think thats a reasonable cadence as we as we March forward.
I of course is this also involves what we decide to do in 2020, I will say that the biggest decision. We make is how many frac crews to deploy and that's often a function of the particular projects that we have and can we keep three frac crews continuously deployed and be efficient in doing that but we don't want to do is bring bring a third crewing and released the third crew and bring a third crew in the release the third group.
One of the things that again, we've talked about this in prior calls we're in an era, where two thirds or more of our well cost is on the completion facility side and that means that as we plan our field cadence that the drilling rig itself no longer needs to demand and control total project timing.
So we're looking at smoothing out that completion facilities capital to bring things on in a more consistent pace distribute the field work. So it's not peak demand slowdown peak demand slowdown.
And you know we're learning a lot on how to manage these projects were getting a lot better and.
I'm not particularly answering your question on what the right activity level is it'll it'll really be a function of what we decide to do as we look into 2020, but.
I'll say, our organization has gotten tremendously better at just project management and understanding.
How to eliminate these peaks and valleys and activity.
Thanks for that color, Tom just I guess, one follow up on that you guys have made a lot of progress on reducing well costs as they're much room for additional well cost reductions and how would that more consistent.
Activity cadence play into that.
I would answer that that we're always looking for well cost reductions so the 5% to 6% reductions that we saw in and completion cost just from April .
Really were due to the focus of design and operational efficiencies.
And we're looking at.
A plethora of data that we've been able to obtain over the years that we've been completing these wells and trying to optimize our caught all the ingredients to a frac.
And see the potential to continue.
To find ways to reduce our well cost so I don't want to throw a percent out there. That's that's possible because I don't I don't know what it is.
But I do know that there is data out there that says we can get more efficient and we can potentially.
Produced a higher net asset value well, maybe that may not have as high a peak rate, but certainly from a capital investment standpoint provide better economics. So we're looking at everything.
Thanks, John .
Yes.
This concludes our question and answer session I would like to turn the conference Rebecca Dom John again for any closing remarks.
In closing I, just want to thank everybody for your good questions.
We had a good quarter, we're looking forward to continuing to deliver.
Excellent results.
And.
Look forward to talking to you next quarter. Thank you.
The conference is now concluded. Thank you for attending today's presentation you may now disconnect.