Good day, and welcome to the Cimarex Energy Call XEC Second Quarter 2019 Earnings Release Conference Call. [Operator Instructions]. Please note, this event is being recorded. I would like to turn the conference over to Karen Acierno, Vice President and Investor Relations. Please go ahead..

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 that 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, our latest 10-K for the year ended December 31, 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 cost. A replay of expiration, John Lambert and Margaret Ford are here to answer any questions you might have. [Operator Instructions]. So with that, I'll turn the call over to Tom..

first, understanding the stimulated fractured network, both along the borehole and away from the borehole; second, understanding parent/child interface and reservoir effects; third, understanding proper well spacing; and forth, configuring an optimum project size and design. Cemex has discussed our learnings on each of these 4 key points.

There is no one-size-fits-all approach. The optimum answer to each of these 4 issues is a function of the reservoir properties, infrastructure requirement and economic conditions. Through years of testing, we have gained a good and growing understanding of the requirement for profitable development within good capital efficiency.

I would, again, referring to slides 24 and 25 in our presentation, which provides a window into our approach on the well spacing issue.

As we've studied development projects in all of our operating areas, we have grown more confident in our ability to design capital-efficient development projects, to observe projects through our operating areas and to predict their outcomes. This has also give us insight to stand out of some non-operated projects.

Our results, thus far this year speak for themselves. We wouldn't be making a detailed comments in our productivities in a prepared remarks, I'll give you a quick overview of 2019, of course, we're open to answer any additional questions you may have.

As you know, our 2019 capital is primarily allocated to the definition, with majority going to Upper Wolfcamp did mention Professor, breeze and Lea County. Four of the 5 Culberson developers are online.

Three of the 5 Reevs development expected online in 2019 are already producing Andrew Obin, our single development in Reeves County this year is currently flowing back. We have 3 additional that would be on production later this year. Operations underway on several projects that will impact 2020.

We currently have 8 rigs running in the Delaware along with 2 completion crew. Now I'll turn it over to Joe Albi, who will discuss 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 the nice jump in our second quarter production, we continue with our strong start to 2019.

Our Q2 net equivalent production came in at the company record of 275,000 BOEs per day, right at the top-end of our guidance range of 263,000 to 275,000 BOEs per day. With the mark, our Q2 '19 net equivalent production was up 6% over Q1 '19 and 30% over Q2 '18.

On the oil side, our company record Q2 oil volume of 83.4000 BOEs per day came in early 1,000 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 [indiscernible] per day, up 45% over the 48.8000 barrels a day we produced in Q2 '18. With the posting, the Permian now accounts for 85% of our total company or production. As we look forwarded 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 262 MBOEs pay day, keeping the same midpoint as our previous guidance, and we've raised the midpoint of our full year net or production guidance by 1,000 barrels per day with the range of 83,000 to 87,000 BOEs per day.

With Q3, we are projecting net equivalent volumes to average 265 to 279 MBOE per day, with our net oil volumes forecasted average 85,000 to 91,000 barrels per day, up approximately 5.5% from the midpoint -- at midpoint from Q2. Shifting over to OpEx. With revenue properties now on our books, our Q2 lifting costs came in at $3.51 per BOE.

That's just slightly above the midpoint of our guidance of $3.20 to $3.70, and it's down $0.11 per BOE from our 2018 average of $3.62. With our continued Permian focus, retightening our full year lifting cost guidance within the range of $3.30 to $3.65 per BOE. And lastly, some comments on growing and completion costs.

We've seen general market conditions remain relatively flat since our last call on both the ruling and the completion side.

That said, with our continued focus on challenging completion design and operating efficiency, we've reduced our completion by 5% to 6% since April, which transition to an attractive total well cost reduction, or reductions in the range of $300,000 to $500,000 for each of our 2-mile lateral wells depending on the program.

And our Wolfcamp program, with the tweak in our completion design, we've dropped our 2-mile completion APV by $400,000. As a result, our generic Reeves County, 2-mile Wolfcamp well is running $10 million to $12.5 million, depending on facility design and frac logistics.

That's down $400,000 from last call, and down $900,000 from our estimate late last year. Our shallower Wolfcamp A wells in Culberson County are running about $600,000 less than Reeves County Wolfcamp A wells, within AFE of $9.4 million to $11.9 million.

I want to point out that with the efficiency gains derived throughout our multiple development drilling projects, our average treatment well -- development project per well costs are funding at the low end of these ranges.

And in the Mid-Continent, with refined completion design improved operating efficiencies, we've reduced completion costs in both our Woodford and Meramec programs. Our current 2-mile Meramec AFEs are running $9.5 million to $11 million.

That's down another $500,000 from the 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 9 net wells previously planned for early Q3 first production coming online during the last 2 weeks of June, we are forecasting a rent ramp in our production in Q3 and Q4, resulting in an increase for our full year oil guide of 1,000 per day at the midpoint as compared to our guidance last call. Our cost structure is healthy.

We're projecting similar full year lifting costs guidance to -- as compared to last call, and we've derived 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 that, I'll turn the call over to Q&A..

[Operator Instructions]. You're first question was from Arun Jayaram from JPMorgan..

Tom, was wondering if you could elaborate on some of your prepared comments when you're talking about your expectations on sequential growth into the second half of the year per your guide and into 2020? And how you're thinking about capital allocation next year just given some of the headwinds we've seen on the NGL and gas side of the equation? Well, yes, Arun.

Certainly, 2020 is -- feels a long way right now. I will tell you that we're putting a lot of energy, as I said in my remarks, on just planning our field effectiveness and smoothing out our full cadence. We talked about this in past quarters. We would be ready to go for sequential oil growth. Now that said, we haven't formed our 2020 plans.

The commodity headwinds are certainly major factor. We're probably a little more bullish on oil as a contribution on our revenue, and you are not surprised to hear me say that, particularly with the environment we're seeing on gas and energy pricing.

So although we haven't formed 2020 plans, I would say that to the extent of allocating capital, we're probably going to want to be emphasizing oil and then, although we'll be prepared for sequential growth, we have informed our 2020 plans and we'll make our decisions when more appropriate. Great. Great.

And just follow-up, maybe for Mark, but I was wondering if you can talk through your marketing arrangements of around your Permian crude. I know there's a new of West Texas light benchmark out there.

So just wondering if you can give us some thoughts on health as the model you're Permian differentials on a go-forward basis?.

Arun, this is Joe. Really, for the most part in Q2, to the extent that the beauty of those or high gravity was an impact on our pricing, we had already seen adjust of that in the -- during the second quarter. The index, as we're seeing it, the WTI of the next compared to May the push is now less than $1.

We anticipate we'll have one of the contract fall under the WTL 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 a 30% to 35% overall hit on our total received oil price.

So right now, the -- with basis of less than $1, we're getting a premium to that the beauty and the revised contract that we're looking at September.

I don't know if that helps you out? And just an approximate mix of your primate upward, how much of that would be leveraged and maybe the beauty of posting new corporate versus WTI? That would be helpful..

Let's see if I can give you a ballpark here. First made me love the room. I'd say it's probably about 1/3 to a 0.5 in the end. But again, a lot of that pricing is already in place..

You're next question is from Neil with SunTrust..

Tom, you mentioned about the consistent cadence.

I'm just wondering how do you in the John and that I think about balancing that with the optimal size of a Delaware pass going forward?.

Well, those are really two related, but independent issues. The optimum size is kind of stands alone from cadence.

We look at infrastructure requirements, we look at the amount of water handling at peak, we look at take away capacity, but first and foremost, we looking at the reservoir and what extent is the reservoir forgiving of add-ons and to what extent add-ons does introduce competitions in the parent-child issue. So we look at all of that.

I will say this, if all else were equal and resourceful forgiving, we would probably go for smaller projects and then maybe 6 to 8 wells per project rather than these large projects and just for a whole host of region. But let me let John comment on that..

Well, I think Tom hit the most part the relevant to that. I think most thing that controls are for us is the amount of infrastructure required when you bring on, both on both on the website of the gas side.

And what we can to find in many of our areas that, Tom alluded to, is 6 to 8 well at the time is a pretty good cadence but also seems to fit well in terms of the pace of our infrastructure investment.

If we were to go much beyond that, then, quite frankly, I think we'd be subject then to potential problems with getting consistent growth because there's a lot of moving parts out there.

So right now, whether we looking in Culberson or Reeves or even up New Mexico, typically most of projects that were driven, the building projects or in that 6 to 8 well range right now. A - Thomas Jorden Yes. But among the many factors we consider, we evaluate the economics of our assets throughout the asset life.

So for the project and one of the considerations in determining size is when will we come back to add-on and what impact will that production have efficient development, both the impact of production we'll have on future development and what impact to the future development have 1 that production.

And so we -- as you gain an understanding, area by area and reservoir by 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 you frac barriers are within your vertical section.

And so, I just say again, it's not a one-size-fits-all. We'd like to make daily decisions around particular project..

Great. Great. And just one follow up. You talked about capital expense specific. How do you arrive at the midpoint of CapEx of the year? It looks like you've already brought on about 60% of the wells and it was about 50% of the CapEx budgets, so if you could address that..

Yes. This is Joe. When you look at what we report, and what we're forecasting for CapEx, there's a lot of moving parts. We've got carry over dollars that were incurring '19 or '18 activity. You've got dollars that we're going to spend in '19 at a carry into 2020 activity.

We've got infrastructure dollars, we've got soil water dollars and then on top of that, we've got the timing of activity relative to when dollars that ultimately recorded. In June, we completed and brought on line 13.1 net wells, 9.4 of those wells came on during the last two weeks.

And as a result of that, we're anticipating that, that carry over is going to blow over in Q3 and then ultimately Crittenton our brains that we've given you guys..

The next question is from Matthew Portillo with TPH..

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 costs say that you highlighted at the meaning of the call?.

Well I take a stab at that. There's lots of knobs that one has to return on completion design. And certainly, spacing, states facing, cluster, types of cluster design, number of cluster per staged, amount of sand and fluid, pump rate, are your 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 down whole 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.

We're always getting better and always questioning our core assumption, but I'll just finish and then let John comment. First and foremost, you have to understand your dumb reflecting geometry or you can make some really bad assumptions as it flows through the other decision..

Really to add on what Tom just said. We have been tweaking a few of our parameters. I'm not going to go into details of those parameters. What is nice to see is, over time, we starting to see the benefits of those weeks. We're starting to see little bit faster cadence with little bit of week.

So we're seeing a nice cause-and-effect, and yet, with those minor tweaks, we're not, in any way, degrading the performance of the well.

So it's kind of what we've always wanted to do that we like, in some cases, we have a pretty optimal design from a ERU well performance basis, and now we're making the smart weeks just an overall design that leads to a few more efficiencies.

The jobs get done a little bit better and lower cost and we're not going to set up as the overall performance of the well. I think we're starting to see more and more with adjournment of the project that we're bringing on..

And I guess I'd add on top of that, that on the design, the fluid times the amount of sand, et cetera, efficiency of execution out in the wilderness paramount. So quicker cleanouts, quicker stages, all that translate 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 profits 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 MidCon next year versus kind of how things should come this year in 2019? And then, Tom, I was wondering if you could flush out a little bit more of just some of the country you mentioned at the beginning of the call in terms of the potential for continuing to show sequential order growth quarter in an quarter out as you move into action? May be indications for -- from a high-level perspective kind of year-over-year growth on oil volumes into 2020? And I know things or kind of in the works, but just any incremental current might right there..

Yes. I think a stab at both those. Although we haven't formed 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 find and develop into a new plays and some new concept.

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 really to a capital allocation that will, again, be disproportionately in favor of the Delaware Basin.

And then in terms of the comments I made that you've asked me to follow up on, on sequential growth. I would say that as we look at into 2020, we certainly have the capacity for a meaningful oil growth and delivering that in a sequential fashion. But we have formed our 2020 plans.

And there's going to be some soul-searching on what the macro environment is and what we've got to do with our capital.

But 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 smoothing out a field operations and being able to deliver consistent quarterly execution.

And we have that capacity, we have that ability, but we haven't yet formed the specifics of our 2020 plan..

You're next question is from Doug Leggett with Bank of America..

Tom, no question that your execution excellence continues to do the -- exactly what you kind of over the years, focus on returns, focus on capital disciplines and so on.

My question, I guess, is really more of a high-level philosophical question as to how do you position Cimarex today to compete with the broader market? Because clearly, what's happening in energy is putting pressure if. It does relate to investor appetite for exposure to the space.

So what is the right growth great? How do you compete with the broad industrial sector? And how we think about potentially repositioning the company in this somewhat challenging time we're in right now?.

Well, those are great question, Doug.

I think all of us have to ask question is what is the proper growth rate if at all? We sent you have the capacity to go but I think that we are asking for no other questions what's the growth rate that, we think, is appropriate? What amount of free cash can we and should be generated? And then what do you want to do with the free cash? I mean those are the similar questions right now.

We are being challenged to behave like good man factors, and I'd say, at Cimarex, we accept that challenge.

We've had to do a little bit of internal work that we talked about in terms of getting our field cadence more predictable, but than once we have that work done, which I believe we do, now it's beholding upon us to get to work and deliver consistent returns and there were those returns to shareholders.

I'll say this, I think that, if we can open the word and let people look inside at some of the capital projects that we're executing, I think we would stand out for prudent investment decisions and generating returns that are showing us that the effort we've put into development learnings are paying off.

But these are all good questions, we're wrestling with that. I think you'll see our 2020 plans reflecting that wrestling, and we accept the challenge.

And, Mark, do you want to comment on that?.

Yes, Tom. That's definitely the items that we contemplate.

And Doug, as we discussed in the past and future conference, the competitiveness of European countries text of up against industries and make it more attractive for the broader markets and generate free cash flow and some committed growth from, returning it to shareholders through different other measures, making our EMP business and our attractive and that something Cimarex will definitely focus on.

We've focused on return on investment, making sure we're getting full cyclic returns and taking the next step how we can further make our stock and our demonstrate should that return to shareholders. .

You know, I'm going to finish, Doug, by saying philosophical, I'm going to take you up on that. We're all very short-term and in our thinking. And we subject to it, markets are subject to it, we always that current conditions are the new normal and will be permanent condition. 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 1 or 2 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 free cash flow, demonstrate to the extent markets that we're prudence stewards of capital and making investments that are efficient and effective.

Those are good things to do regardless of changes in the macro environment. So we're going to get after, and we're going to the mission that we can adapt. But we're also want to remind ourselves that we're in the business for the long-term, and 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 you answering the question, Tom. you're certainly right in answering the question I agree with you on that. If I may, just a quick operation 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 wondered if you can kind of sum up the prognosis for you guys as it reached to gas and NGL with prognosis, if you like, for how you see your differentials evolving? I realized there was some funny on your gas realizations this quarter, but any help from 20 see that moving into the next year and I'll leave it there..

Doug, looking at the -- starting at the second half of '19, looking at Waha and the gas price index, we're looking at index, we're looking around [indiscernible] Q3 going into $1.50 in the future serve, for Q4. They're averaging little bit over $1.20 or so for the second half of the year.

So we see that improving into the second half of the year with Gulf Coast Express coming on. Future spark is reflecting that, and we expect our second half naturalization to improve.

And then you mentioned some of the reported realized price relative to accounting ASC 606, which has an processing costs against it, which, in Q2, there was $0.40 in Mcf, a processing and translation cost against the realized price that will continue.

Sino in order to model the full price and to corporate the differential for 66 a surprise, so we get the amount for the impact in the press release and payable..

There's a transfer of said, though, on that?.

That's right, Doug. There's a transfer of said. That's exactly right. I mean going into 2020, we see a forward curve that oscillates a fair amount into 2020.

Our first year, our first orders hires $1.70, going to $0.80 in the second, but either premium prices or going to $1.30 to $1.40, similar type improvements or realization compared to what we've seen in the second quarter this year..

The next question is from Brian Singer with Goldman Sachs..

Couple of follow-ups that I wanted to ask earlier. First come on the midterm. You talked about concepts that you'd be working on that you are working on.

Can you just talk to where those stand? And what you would need to see to allocate more capital there in 2020?.

Well, I don't want to comment on any particular place or the evolution of them. We talk about it and what we have resulted talk about in the second one is easy. When we need to see a material returns that compete with the Delaware Basin.

Certainly, a lot of what we have in the Mid-Continent today can be, they capital allocating as it Mid-Continent because it heads up what you seeing with Delaware. But the robust inventory there is not the same. we have a deep inventory of those things from the Delaware that compete for talk to the capital that we do in an adorable.

And so what would need to see his deep inventory and some great returns of new and emerging plays..

And would you allocate rigs back on a normal -- just among the base legacy place relative to current levels?.

Brian, I would send rigs to the moon if you would make good profits doing so. we're here to make money and we -- that's our only bias to make money and be able to make money through the commodity cycle. So absolutely, we would relocate capital if he thought it was in the best interest of our shareholders..

And then my follow-up is, you've touched on this a bit earlier, but maybe it's part of your soul searching process for 2020.

It sounds like you're trying to find that precise optimal point of growth [indiscernible] a corporate level doesn't free cash flow, but any of calculus with exhibit and particularly importance of free cash flow as you think about that 2020 plan versus asset or corporate-level returns?.

Well, yes, I do know that we're doing a deeper, broader sole searching than anybody else. I think we're all asking the question of clearly growing a maximum capacity is not what -- we're not getting market signals, but that's what people want, and we're listening long and clear.

We also deeply cognizant of the fundamentals demand and that we certainly have some market bottleneck. So we're -- I'll say this, many of us -- through the industry, not just talking by some expert many of this group in a world where we grew the national rate we could sustain. And clearly today, that's not what we need to do.

And so it's a tension between our do you want to read all? And if so, doing and making a decision, if you throw up -- your growth back, you may generate free cash flow and then what you do with it. I mean I'm just repeating myself, but I think anybody in the EMP sector that's paying attention is asking the same question.

And we'll all have different answers based on our portfolio, our balance sheet and our assets..

You're next question is from next [indiscernible]..

My question is long going on capital allocation. I think it was a year ago on your call. Discussions a lot of discussion about whether the company would initiate a buy back. And I think I recall it, you look into it, talked to the board and at that point in time, you guys decide not to do one.

Fast-forward today, this talking about half of it was than [indiscernible] all prices are down little bit, but I'm just wondering, especially as you alluded to, what would you do with the free cash flow if you went into a no-growth state? Why does no discussion currently, at least to us, about a buyback? The stock is down tremendously, the NAV, by anybody's measure, is much higher than the current stock price.

With liquidity and a stock trading where it is, can you give us an update on your talk as to what management is thinking?.

Well, certainly, your points are well taken and the argument for buyback is more persuasive today than it was a year ago or 2 years ago. But we will announce any decisions that we make once we make them. I mean we always looking at it and it's a question of how much free cash do you have, and is that where do you want to deploy it.

We really not a team that likes to get drawn into spec condition. You made good and acknowledge them and we certainly think that our share price is at the point where an analysis of that in the past is outdated.

Mark, do you want to follow on that?.

Yes. I think that's containing evaluating. I think it's buyback in an itself looking at the relation to stock relative to the investment is something we've always taken into account. And right now, with the stock price, which is, and so we have to continue to be validated.

And I think it's if you had free cash flow at this point, we're still kind of neutral at this point. But as you look forward into our experience, we expect to free cash flow. And I think we're going to be looking at that time between what we think the stock relation is this compared to the other investments. And this would be the point in time.

If we had free cash flow right now, and cash in the balance sheet, we definitely, I think, realizing that..

I just leave it with, I think, pretty strong on investors that the company recognizes the value of it's own stock especially given the long reserve that we have and the significant discount you have on the valuation..

We agree with that and appreciate your comment..

The next question is from Jeanine Wai with Barclays..

My first question is on efficiency. So far this year, you completed more wells and anticipated due to better efficiencies.

Can you quantify some of these deficiencies in terms of drilling or completion days? And commented on how sustainable you think you guys or going forward? I know you discussed in your prepared remarks the end result, which is your cost, but just looking for a little bit more detail?.

Yes, Janine. The efficiencies that we really, that are, I guess, are evident in the arrests that show up as a night in Q2 versus Q3, they are really about 2 to 3 weeks' worth of benefit that we saw from an were able to turn on, turn both online and start to see first production.

So when we put our models together, we, obviously, using charts, et cetera, trying to line up everything including relapse and what have you, we've just seen, over the last quarter, just 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 our plugs with facilities and mines and they started cutting hydrocarbon earlier than we had forecasted that is well. So we built a little bit of cushion into our forward-looking guidance and those restaurants beat it..

Okay. And then my follow-up call is kind of following up on the couple of the other questions. Regarding those 10 extra net wells that we did in 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 you talked about? It sounds like the quarterly timing shift might not be that big of a deal because of hardly in the extra well were. And the way we see it, you've got it. Lot of debts at the end of the year for of snidely heading into 2020, if you choose.

And then maybe in an popular question, but is there a scenario where you would just considered to keep going and pulling forward some of the 2020 wells into the because it's the best thing to do operationally. So perhaps short-term paying for medium-term benefit.

And we mentioned him asserting that you can adapt to the current environment, but also that the market is a bit short-term focus right now..

Well, when you dissect a plan, what we really thought, just some small accelerations of wells coming online from Q3 into Q2, and I've talked weeks on that, not like way a month in advance. And some of the Q4 wells getting pulled earlier in the Q4 and/or even maybe 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 might do from a technical standpoint. And looking at about the same amount of decks at the end of the year.

And then as far as trying to do anything in acceleration for over '20 and '19, we're going to be very, very cognizant of our capital and how much money we're spending in '19..

The next question is from Mike's Kaplowitz Chief Financial Officer..

Just wondering now that you've transfer agreement for natural gas, if you revisited your thoughts on transfer for oil at all?.

Yes, we actually have. We've been looking at and have entered into an agreement for take way to the Gulf Coast out of the Mid-Continent, which also gives us an off-road into a from the Permian. And about 10,000 barrels a day commitment, expandable up to 20,000 and it begins at first quarter of 2021.

So it's going to give us the ability to get up to the Gulf Coast, Houston ship Channel with our oil and thinking that oil either out of the Mid-Continent or the West Texas area. When you look at the speck of what we're doing, it's not only on oil side. We've particular long-term arrangement for May kind of gas question year.

And then in the Permian, we've gone ahead and got some fair amount of West Texas into Waha and then, with us getting into the reserve project, add 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 majority of the 2020. And it's really insurance flow and trying to get to the better markets..

You think you're done in that regard at this point? Or is that more so to go there?.

Do not really speaking. So we've taken some steps above and beyond where we've been, and we're going to continue to take additional steps going forward..

Good. Okay. And just wanted us ask, from an operational standpoint, last quarter, you talked about -- and you mentioned in the slide deck, the Sir Barton and have Brokers Tip pads. Just wondering what the end result was there? I now you were testing X and Y Sands and some spacing.

What did you learn there?.

Yes. Both of those pads, Sir Barton Brokers Tip, those were 7 wells each that we brought on. They were indeed testing as part of the development, different landing zones with some of them being pushed up into what we call the Y sand instead over our regular in landing zone. Both projects are very economic for us.

We're very pleased with them, but there's been some important learnings. We're definitely seeing that if we can get those landings further up and get a little bit more vertical separation with the lower tier landings, we definitely like the results of those wells versus when they're a little bit more crowded on a vertical basis.

And so that's something we're incorporating, in fact, have incorporated into the next open project on the west side of commerce, which is carryback.

Also, I'd just say, from a cost standpoint, and you alluded to this, we're very pleased, especially in the Western side of Culberson that what we're seeing so far on a cost basis and have adjusted this is specifically just these two projects, but so far, we're seeing about $1,000 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 in the personal side, where it's a little bit shallower, a little bit lower pressure and thus, much quicker drilling for us..

The next question is from Jeffrey Campbell with 3 Brothers Investment..

I'll my question to one of the two-part. We've been talking some about that the new place that we're trying to stay down in the MidCon.

And first question I want to ask us, can any of these efforts take place on existing acreage? And the second one is, if there is some success here, would this increase any provision for M&A? Or is this going to be an entirely organic effort?.

a, we have found a zone that for capital on ongoing basis, which means there must be cited, it 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..

Appreciate the color, and we will see you in New York on Thursday..

Next question is from Michael Hall with Heikkinen Energy Advisors..

I just wanted to talk about capital a little bit. If you look at your year-to-date oil volumes and then into third quarter guide, kind of indicate the fourth quarter oil midpoint around 89 MBOE per day, which was basically flat to maybe relative to 4Q '18 pro forma for the Resolute deal.

Is that a fair way to think about? Then if we look at the 2019 capital, is it fair to think about 2019 capital is basically kind of a maintenance level for your oil volumes at this point? Or it's kind of transfer of factors that may suggest that the inappropriate way of looking at that capital efficiency at this point?.

Yes, Michael, there's a lot of ways to look at capital efficiency. And if you look at the capital that the pro forma capital along with pro forma both ramping significantly to the fourth quarter, both had a very high exit rate in the fourth quarter accomplishes that year.

That definitely has a overpay is how we look to lose the fourth quarter to fourth quarter rates. And the maintenance capital with Resolute and some I'm trying to maintain a flat fourth quarter fourth quarter. I guess, we're -- our capital on a pro forma basis is down year-over-year as abundance of capital and cash into 2019.

So I guess, going to argue that with adjustments in a capital, by holding our capital -- our production roughly flat, I would see on that. Yes.

I just want to remind you that Resolute was on a pretty massive outspend and as we pulled with an asset and we certainly face the commodity environment a number of certain we anticipated, we made the decision to bring the combined entity forward within cash flow. But I 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 would share with you that, we are currently flowing back at Sandlot project, which was essentially an extension of a development project that Resolute had been 2 phases.

On our extension, we incorporated some of the earnings that we brought, and as we flow some of those wells back, we have performance our revenue wells that had been the average of the project on the pain.

We're seeing high oil recovery, but their plans and so we really like those assets and we sing fruits of all the reasons why we wanted them in our hand..

Okay. And I guess there is a follow-up.

As you think about the completion count, at the end of the year, relative to expectations around exit, recounting 2 counts, how does that look relative to normal? And what sort of timeframe -- if that's above normal, what sort of timeframe would you suggest is to think about that normalizing back down? Just trying to think more predictable efficiency..

I'm not certain what you're alluding to.

Are you talking about the number of, let's say, frac plays that we're running right now, versus beginning of the year?.

No. Just wanted a completion count that you provided for year-end 2019.

If you look at that relative to expectations of rig and completion crew's at the end of the year, how does that compare to normal? And should we...?.

A normal level, but we have gone from two factors to two, there's some bearing on that. At the year-end '18, we had 20 or network that we kind of waiting on first production. That has increased and, obviously, 42 [indiscernible] waiting production at the end of '19. But it is up a little bit but it is sufficiently from 3 crews to 2 crews.

As we going to '20, and we expect that back to 3. And it's one of our bigger timing of the projects we're developing and the size of the different projects. That's the biggest book offering..

I think those nine net wells kind of slipped a couple of weeks in Q2 are really playing a role in how I guess we are being perceived out there. But last quarter's guidance, for the rest of the year, we're projecting 34 net wells for the last half of the year, and right now, we're now at 27.

So all this happened is a few wells slid into Q2 right at the very end of Q2..

Okay. And I just think about I was trying to think about what 2020 -- potential tailwinds 2020 capital efficiency from that backlog reflected on completion wells.

It doesn't really sound like that's particularly out of normal, particularly if you're going to begin up the completion crew up there?.

No. Indeed, The docs are virtually about the same effect a little bit more on a going forward. So again, it's just a some slight moving of a couple net wells is all that's really going on..

The next question is from Mark with Seaport Global..

I'm a big fan of the Slide 13, which highlights year or productivity, Culberson relative to other counties in Delaware.

With this in mind, I was hoping to have you guys may be, what we can expect at the Reeves County acreage in terms of our productivity, and ultimately, the returns versus kind of [indiscernible] Culberson acreage, acknowledging that range is a massive to and figures hopefully would be more sweet spot. But just wanted to get your thoughts there..

We're not yes. When you look at the site and I'm a big fan of the upside as well, that it certainly highlights, in a very significant rate, the performance of Culberson, which basically, when you see Culberson, that's Cimarex. I mean that's pretty much comprised those well.

Whereas what we've done is of course going to the state that the end amalgamated or the 2-mile lateral from all the operators into making that craft. 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 lower end.

I can tell you that we've looked at that graph separately just with Cimarex wells, and yes, we definitely separate themselves from with that background trend shows.

And yes, we feel very good that the acreage that we have and have recently acquired through Resolute is some of the rhetoric, which in Reeves County that does need to better commutative production and what you see is the average there for the entire county..

And can't help to notice you got this next line of said in the water infrastructure.

And just wanted to get your men high-level thoughts on what you think is a good value then we could potentially peg in that event system? And if there's any kind of updated thoughts on your desire to monetize that?.

Well, value is [indiscernible] water is becoming a bigger and bigger part of the Permian Basin business. We're always obsessing that, and I've talked in the past, and I'll say again, that there may, indeed be a point in time, we're monetizing some of our midstream assets make sense to us.

Right now, I'd say the value we get out of it is the operating cost, access to water for recycling and a really good environmental footprint with the way we've designed the water infrastructure. With these monetization needs, it ultimately becomes a tradeoff of CapEx of OpEx. I mean certainly, we're invested capital in that system.

If you were to select, if you would have a higher operating cost 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 where we'll decide to monetize it.

But right now, the biggest benefit for -- from us, is operational efficiency, low operating cost 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 accretive job in building it.

It's something we're very proud of, both from just an operating efficiency, but from an informative footprint. And monetizing it is not off the table, but I'll just say this, we look at it constantly and when we think it makes sense, we'll move forward..

To elaborate a little bit further to Tom's point, just the recycling alone is potentially saving is anywhere from $350,000 to $550,000 per well from an development cost and point. So many months rather by the number of wells, potentially, the Culberson, we're talking a fair amount of capital reduction by virtue of owning it..

The last question is from blanker with Morgan Stanley..

You're thoughts about shifting to be consistent activity pace and can you just talk about kind of what that looks like? And where the right level of activities assuming that the cashless fully funded rig count or fax parents.

Some more high-level way to qualify that measure?.

Well, yes. We're currently running rings in the Permian, and I think that's a reasonable cadence as much forward. Of course, this also involves what we decided to do in 2020.

I'd say that the biggest decision we make is how many frac to deploy, and that's often the particular project that we have and can we keep 3 frac crews continuously deployed and be efficient in doing that. Well what we don't want to do is bring a third when and release the third 2, bring the third row in and release the third crew.

One of the things that again, we talked about this on prior calls, we are in an area where 2/3 or more of our well cost is on the completion of facility site and that means that as we plan our field events that the drilling rig itself no longer needs the 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 fieldwork so it's not peak demand slowdown, peak demand slowdown. And we're learning a lot and how to manage these projects.

We're getting a lot better, and I'm not particularly answering your question on what the right activity level is. It will 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 in activity..

Thanks for that color, tom. I guess 1 follow-up on that. You guys have made a lot of progress on reducing well cost.

Is there much room for additional more cost reductions? And how would that more consistent activity cadenced will play into that?.

I would answer that, that will always looking for will cost reduction. So the 5% to 6% reduction that we saw in completion costs 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 these ingredients to the frac and see the potential to continue to find ways to reduce our well cost.

So don't want to possible because I don't know that it is what I do know that this is out there that since we can give more efficient and we can potentially produce our net asset value well maybe that may not have as happy great, but certainly, from a capital investments standpoint, providing better economic. So we're looking at everything..

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

Yes. In closing, I just want to thank everybody for the good questions. We had a good got it. We looking forward to continuing to deliver excellent results and look forward to talking to you next got it. Thank you..

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