Logo of jester cap with thought bubble.

Image source: The Motley Fool.

Cimarex Energy Co (NYSE:XEC)
Q1 2019 Earnings Call
May. 9, 2019, 11:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

Good day, and welcome to the Cimarex Energy First Quarter 2019 Earnings Release Conference Call. (Operator Instructions) Please note this event is being recorded. I would like to now turn the conference over to Karen Acierno. Please go ahead.

Karen Acierno -- Director of Investor Relations

Good morning, everyone, and welcome to our conference call. An updated presentation was posted to our website yesterday afternoon, and we will be referring to this presentation during the call today. Just 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 we filed today and our latest 10-K for the year ended December 31, 2018, for the risk factors associated with our business.

We will begin our prepared remarks with an overview from our CEO, Tom Jorden. As John Lambuth is unavailable this morning, Tom will also update you on our drilling activities and results. And then Joe Albi, our COO, will update you on operations, including production and well costs. Mark Bradford, our CFO, is also here to help answer any questions. (Operator Instructions)

With that, I'll turn the call over to Tom.

Thomas E. Jorden -- Chairman, Chief Executive Officer & President

Thank you, Karen, and good morning, everyone. Cimarex is off to a good start in 2019. We closed the Resolute Energy transaction on Friday, March 1. By Sunday, March 3, we had a completion crew on location at the Sandlot development. And on March 8, we closed on the issuance of $500 million in senior note that essentially refinanced Resolute notes at a much more attractive interest rate, 4 3/8% versus the 8.5% previously being paid. 2019 will be a year dominated by development projects as we capitalize on the work we have done in the past few years in understanding optimum development of each area and each reservoir. I will walk you through some of the projects we're developing in 2019, but first, I would like to take a minute to describe our approach to optimum economic development. I will be referring to Slide 6 and 7 in our updated presentation. Our goal is to maximize the value of our assets. And as we have said in the past, optimum well spacing is not a "one size fits all" solution.

Optimum economics development involves 4 key components: one, understanding fracture geometry and cluster efficiency; two, understanding parent-child interference; three, understanding the details of well spacing and well-to-well interference; and four, understanding the governing factors of optimal project size, which includes total capital investment, including infrastructure, as well as the impact that project size has on project timing. Slide 6 and 7 illustrate our methodology on choosing optimum well spacing, which is only 1 of the 4 key criteria. Often, well spacing gets confused with parent-child interference. They are 2 different but related phenomenon. These data, which are an outgrowth of many detailed experiments, are actual examples from 2 different well spacing projects. Together, they illustrate the economic sensitivity of adding additional wells to a development project. Too many wells can quickly become value destroying. Too few wells can leave value untapped.

As the slides illustrate, we believe that the economic sweet spot is found somewhere between maximizing rate of return and maximizing net present value. These principles underpin all of the development projects we'll be discussing today. Understanding these nuances for every reservoir and for every area are key to Cimarex development decisions. We have a great team at work here, and we strive to make prudent decisions based upon sound science in order to maximize the value of our assets. Details count here. Getting it right is the difference between value creation and value destruction. Finally, I want to highlight an additional slide in our updated presentation that illustrates the tremendous quality of our Culberson County asset. We have long described the outstanding returns we deliver with our extended length horizontal wells in Culberson County. We have also discussed the fact that these wells exhibit lower-than-normal oil decline, primarily driven by the energy in these overpressured reservoirs and the fact that the reservoir phase has tremendous mobility.

Referring to Slide 15. It may surprise you to learn that Culberson County surpasses all other counties in the Delaware Basin in cumulative oil production. Slide 15 shows a Delaware Basin breakdown by county, of 6-, 12- and 18-month cumulative oil production. This slide is built for public data using all wells since 2016 with lateral lengths greater than 8,500 feet in the Wolfcamp and Bone Spring formation. We have not applied any filter other than lateral length, date of first production information. Each of you should be able to recreate these graphs on your own. Furthermore, the Culberson wells produced with lower lease operating expense due to the fact they do not require artificial lift until later in their lives. High return, low LOE, basin-leading cumulative oil, it's a great trifecta. We're in a tough patch on residue gas prices. As we promised, we have flow assurance of our produced gas, but we are experiencing brutal Waha and Panhandle Eastern pricing. We do expect these differentials to NYMEX to soften as additional pipeline capacity opens up later this year.

Nonetheless, our flow assurance gives us access to the liquids component of our gas stream, which is much more valuable than the residue gas. Residue gas is a minor component to our overall revenue stream. 2019 will be another year of solid execution. We're seeing the benefits of our emphasis on science and innovation as well as our organizational capability and focus on return. Now on to some operational highlights. During the first quarter, Cimarex invested $368 million in exploration development activities. We invested $319 million in drilling and completion capital. In 2019, we expect to spend between $1.1 billion and $1.2 billion of drilling completion capital, 85% of which is expected to be invested in the Permian region. We currently operate 9 gross rigs, with 8 in the Permian and 1 in the Mid-Continent. I will start in the Permian region where we brought online 12 gross, 5 net wells in the first quarter. Although the net well count may seem low, activity was not. We had multiple development projects that were being completed during the first quarter, with much of the production coming online in the second quarter and beyond.

Four developments are now flowing back, that's our Sandlot, Capote, Brokers Tip and Sir Barton. And 17 of the 21 net wells expected to be on production in the Permian region during the second quarter are already online and flowing. One of these development projects is the 4-well Sandlot development located in Reeves County. This is the first development project to come online that is a direct result of our acquisition of Resolute Energy, with 2 more development projects on the acquired Resolute acreage to be drilled later this year. Two developments in Culberson County are also flowing back, the Brokers Tip and Sir Barton projects, both of which are 7-well developments located on the western half of our Culberson acreage position. You can see these on Slide 13 in our updated presentation. We are watching these particular developments very carefully because a number of the wells were landed higher up in the section in the Upper Wolfcamp section in the X and Y sands. Results from these projects could influence our future spacing on this acreage position.

Although we don't have any developments planned in the Lower Wolfcamp for 2019, the Animal Kingdom pilot, which has now been online for over 6 months, is providing critical information that will guide our development plans in the future for the Lower Wolfcamp. As you can see on Slide 27 in the appendix to our presentation, these wells have cumulative production of over 2.7 million BOE in their first 225 days. We are very pleased with the results of this project. Now on to the Mid-Continent. In the first quarter, the Mid-Continent region brought online 26 gross, 3 net wells. The majority of the production for this region will come online in the second quarter as we complete 3 Meramec development projects, that being the Billy, the Wort and the Miss Mary. The spacing for these projects varies from 3 to 5 wells per section. By the middle of May, the Mid-Continent region will release the one operated rig it has under contract. Wort continues to finalize the timing and capital plans for the next major development in the region, which will most likely be the Leota Jacobs project located in the liquids-rich part of the Woodford. The first wells in this project are currently scheduled to spud in late December.

With that, I'll turn the call over to Joe Albi.

Joseph R. Albi -- Executive Vice President, Chief Operating Officer & Director

Well, thank you, Tom, and thank you all of you for joining us on our call today. I'll touch on the usual items, hitting first on our first quarter production, then hit on our Q2 and 2019 full year production guidance, and then finish up with a few comments on lease operating expense and service costs. We're off to a strong start here in 2019, with Q1 net equivalent production coming in at 259,000 BOEs per day. We beat the high end of our guidance range of 245,000 to 257,000 and also set a new record for the company for equivalent production. With 8 net wells coming online during the quarter, our net equivalent production was up 3% over Q4 '18 and 26% over the first quarter of 2018. On the oil side, our Q1 oil volume of 79,400 barrels per day came in 2% above our guidance midpoint and was up 22% over our Q1 '18 posting of 65,000 barrels per day. The Permian drove that increase with our first quarter '19 Permian oil volume of 65,000 barrels a day, up over 30% over the 50,000 barrels a day we produced in Q1 '18 in the Permian.

Looking forward into 2019, we're reiterating our full year 2019 capital guidance and activity levels. That said, with the strong start to the year, we've modestly increased our full year equivalent and oil production projections. We've bumped our full year net equivalent production guidance to 260,000 to 275,000 BOEs per day. That's up 7,500 BOEs per day or 3% over our previous guidance that we gave last call. And we've also raised our full year net oil guidance to 80,000 to 88,000 barrels a day. That's up 1,000 barrels a day or 1% over the midpoint of our previous oil guidance. For Q2, our model is projecting net equivalent volumes to average 263,000 to 275,000 BOEs per day and our net oil volumes to average 79,000 to 85,500 barrels of oil per day, both the equivalent and the oil up 4% quarter-over-quarter at their respective midpoints. Shifting to our operating expense. Our first quarter lifting costs came in at $3.31 per BOE.

That's below the midpoint of our guidance range that we gave of $3.20 to $3.70, and it's down $0.31 per BOE from our 2018 average of $3.62. With the Resolute properties now on our books, we're maintaining our full year lifting cost guidance of $3.20 to $3.70 which also incorporates our continued Permian focus and the market pressures we've been seeing in cost items, such as SWD and compression. And lastly, some comments on drilling and completion costs. On the drilling side, with the drilling cost components holding relatively stable since our last call, we're keeping the drilling portion of our AFEs in check. And on our completion AFEs, we're holding them flat as well, as we continue to focus on cost savings by challenging completion designs, utilizing local sand sources and through efficiency gains we've derived from water recycling and zipper fracking. And as a result, we're maintaining the total well cost estimates that we mentioned last call in our Wolfcamp program. Depending on area, interval, facility design and frac logistics, our current Wolfcamp 2-mile AFEs are running $10.4 million to $12.9 million.

That's down $0.5 million from the estimates that we quoted late last year. With the efficiency gains that we're deriving through multi-well development drilling, the average crude well cost that we've seen in our Wolfcamp development projects are falling well in that low end of that range. And in the Mid-Continent, with our refined completion design and local sand pricing, we're holding our 2-mile Meramec AFE range at $10 million to $11.5 million. Again, that's down about $0.5 million from late 2018 and more than $1.5 million lower than the total well cost that we quoted about a year ago. So in closing, we're coming off a great quarter with our net oil and equivalent volumes beating the midpoints of our model. With the strong start, we're projecting continued production growth into Q2, and we've raised our full year guidance ranges for both equivalent volumes and for oil. And with our healthy overall cost structure, we're well positioned to deliver the capital, activity and production plan that we put in place at the beginning of the year.

So with that, we'll open it up for questions.

Questions and Answers:

Operator

Thank you. (Operator Instructions) Our first question today comes from Gabe Daoud with Cowen. Please go ahead.

Gabe Daoud -- Cowen -- Analyst

Hey, good morning, Tom good morning, everyone, I was hoping we could start with Permian pricing maybe. You've provided us with a cash flow sensitivity for a couple of different oil price scenarios. Was just curious what happens to cash flow this year if gas prices were to remain at or below 0 until Gulf Coast Express comes on later this year? And then on oil, are you guys seeing any API gravity deducts anywhere across the asset base?

G. Mark Burford -- Vice President & Chief Financial Officer

Yes. Gabe, this is Mark. Yes, if you look at Permian cash flow, if the gas prices averaged 0 for the second -- or the second and third quarter and taking account our hedge position of about 35% of our gas hedging in the Permian, our net cash flow impact is somewhere in the $30 million impact to our annual cash flow.

Gabe Daoud -- Cowen -- Analyst

Okay. Great. Great. That's helpful. And then I guess just as a follow-up at the asset level, could you just maybe talk a little bit about Mid-Con, 1Q down quarter-over-quarter, obviously not a ton of activity. But maybe could you just give us a sense of when that asset does receive more operator activity? At what, I guess, commodity price would incentivize more activity on that asset?

Thomas E. Jorden -- Chairman, Chief Executive Officer & President

Well, we're certainly looking seriously at additional development projects on that West side liquids-rich window. I mentioned that Leota Jacobs is one that's seriously being contemplated to spud later this year. We're also looking at a number of projects in that Lone Rock area that really compete with anything in our portfolio. But certainly, we've been asked about our relative investment in the Mid-Continent versus Permian. We'd like to see that be a little more balanced, and our Mid-Continent team is hard at work looking for new opportunities and trying to compete for capital. I'll say this, we really like the Mid-Continent.

If you asked me what I would look for in a U.S. basin, I would say I'd look for a multi-pay basin, overpressured in a fairly friendly business regulatory environment. And certainly I've just described the Permian basin, but I've also described the Delaware Basin. And so we've got our team hard at work looking for new opportunities -- I'm sorry, Anadarko Basin. We've got our team hard at work looking for new opportunities and it doesn't -- it's all held by production. So we're really at a point where we are working on new zones, new targets. And we really hope to be discussing some things in the future.

Gabe Daoud -- Cowen -- Analyst

Thanks so much time and just to follow up on the API gravity question, please, if I may.Thanks again.

Joseph R. Albi -- Executive Vice President, Chief Operating Officer & Director

Yes. This is Joe, I can handle that for now. We've seen a few price deducts in our Permian production here in March and in April. It basically impacts about 20% to 23% of our total gross production, which, as we net it down, might equate to about 15,000 barrels a day of our net production, and annualized for the year would impact us to the tune of only $7 million. So that's what we've seen today. Part of that includes the addition of the Resolute properties, which are deduct right after we bought it.

Gabe Daoud -- Cowen -- Analyst

Understood , thanks again, guys.

Operator

Our next question today comes from Jeanine Wai with Barclays. Please go ahead.

Jeanine Wai -- Barclays -- Analyst

Hi, good morning everyone.

Joseph R. Albi -- Executive Vice President, Chief Operating Officer & Director

Hi Jeanine.

Jeanine Wai -- Barclays -- Analyst

Just wanted to follow up just as second here on Gabe's question on the oil pricing. I believe historically, for Cimarex, Culberson County has had the highest API and Lea County had the lowest, but I think I'm a little stale on that, so I'm not sure if anything has changed over the past couple of years. And so if this is a potential scenario for Cimarex, kind of what steps can you take to mitigate some of the negative deducts for oil pricing? Is there something maybe contractually that you're looking to go after? Or is there something about pipes or anything about going after different formations? Just what kind of levers you can pull to kind of counteract some negative pricing?

Joseph R. Albi -- Executive Vice President, Chief Operating Officer & Director

This is Joe. I'll take a stab at that. Obviously, renegotiating some of the contracts is certainly in the mix. There are certain positives on both sides of the contracts that -- negatives, likewise, for each party. And to that extent, without going any deeper into that, it's something we'll look at. The other thing we're looking at is the -- trying to get these oil directly sold at the Gulf Coast. And that's more of a long-term perspective that we're taking on right now, not just here but also in the Mid-Continent where we see gravity issues being a potential risk.

Jeanine Wai -- Barclays -- Analyst

Okay, great, thank you for taking my question.

Operator

Our next question today comes from Jeffrey Campbell with Tuohy Brothers. Please go ahead.

Jeffrey Campbell -- Tuohy Brothers -- Analyst

Good morning. And by the way, I just wanted to say how much I appreciate the additional disclosure that you've shown at the slides. It's really helpful. Tom, you mentioned Wolfcamp XY tests that could influence future development. I just wondered, was the point here that you're testing zone communication between the XY and the Upper Wolfcamp? Or did you make something else?

Thomas E. Jorden -- Chairman, Chief Executive Officer & President

Well, no. The Wolfcamp is a petroleum system. And so understanding the individual zones within that system that can contribute is really important. One of the things that we've seen with individual wells is those X and Y sands can have great deliverability. And they're probably not going to be in new independent landing zone, but it may allow us to get more wells per section through a stack stagger arrangement. It also speaks directly to deliverability. Their deliverability at wells that land in those targets, we are hopeful, will be an uplift over our primary Upper Wolfcamp target. So anytime you have, let's say, 600, 700 feet of productive reservoir, the more landing zones you have available to you, the more flexibility you have in your spacing.

Jeffrey Campbell -- Tuohy Brothers -- Analyst

Okay, thank you for that color. My other question is on Slide 17. I thought the little illustration on the frac generation was quite interesting. And what really stuck out to me is that Gen 4 behaves very differently than the other 3 generations. It's faster out of the gate and then stays that way, where some of the others may start faster but decline or start slower and rise. So I was just wondering if you could just give any color on what's going on there to make that different behavior in Gen 4.

Thomas E. Jorden -- Chairman, Chief Executive Officer & President

Well, obviously, what you'd like to see is curves that are up to the left and straight lines and -- because that shows not only higher productivity but the degree of linearity shows low decline. When they bend over, those wells are declining. Now this Gen 4, there is a limiting factor in that reservoir resource and play. So at some point, they will bend over. But what we're hoping to see is maximum amount of time in that straight-line behavior because that speaks directly to return on our investment. So that's a wonderful outcome, but that's not going to be straight up until forever, it's going to bend over.

Jeffrey Campbell -- Tuohy Brothers -- Analyst

Understood. Okay, thanks very much. Appreciate it.

Operator

Our next question comes from Mike Scialla with Stifel. Please go ahead.

Michael Stephen Scialla -- Stifel, Nicolaus & Company -- Analyst

Yeah, good morning everybody. Right. You have resisted entering any firm transport contracts for Permian oil in the past, and that decision looks like it's probably a good one. Wanted to see if you have any thoughts on potentially taking firm transport on natural gas out of the basin given your outlook for that commodity long term.

Thomas E. Jorden -- Chairman, Chief Executive Officer & President

Well, I'll take a stab at that and then turn it over to Joe. That -- firm on natural gas is one of the things that we're seriously discussing. And although we typically resist firm because of the -- you're really committing to future capital investment, we think about residue gas a little differently than our other bases. Because firm transport on residue gas is really insurance against your oil revenue. In particular, if we get into a flaring situation, it's anybody's guess what that looks like long term. So we are discussing some firm transport on pipelines out of the basin. We're in pretty good shape in the short run with our marketing arrangement. But in the long run, I think you'd find our thinking is evolving on firm with regards to gas. Joe, you want to comment on that.

Joseph R. Albi -- Executive Vice President, Chief Operating Officer & Director

Yes. I'd just echo a lot of what Tom said. As far as our strategy today, it's been to line ourselves up with suppliers and shippers with firm on pipe out of the basin. And with each and every quarter, we continue to extend the contracts that we're putting into place. We're nearly 100% through the first quarter of 2020 and have upwards of 75% to 80% of all of our residue gas already sold through October 2020. But we are also looking at, as Tom said, to a longer-term strategy to firm up a portion of our volumes on pipe directly to the goal. I might add that, years back, we put together an arrangement with Cheniere on the Cheniere pipeline to do the same coming out of the Anadarko Basin with really no obligation to commit to any volumes until 2020, 2021. And so we've done it before, and it's something that we certainly are still looking at.

Michael Stephen Scialla -- Stifel, Nicolaus & Company -- Analyst

Got you. Okay. And then looking at your Slide 27, Tom, you mentioned the Animal Kingdom had, it looks like, some really strong rates from those wells. I assume that, I guess, one that makes you feel pretty comfortable about 14 wells per section in the Lower Wolfcamp in that area. But I was also thinking, how do you think about developing the Lower Wolfcamp? I know you've shown better returns and a higher oil cut in the Wolfcamp A in Culberson. When you think about that -- those criteria that you talked about to maximize value on Slide 6 and 7, wanted to see how you develop the Lower Wolfcamp. Can you develop it later? I mean can you develop the upper zones first and then leave the lower? Or do you need to do some sort of co-development?

Thomas E. Jorden -- Chairman, Chief Executive Officer & President

I'll take your second question first and then come back to your first question. The nice thing about Lower Wolfcamp is it is, as best we've been able to determine over years of analysis, completely isolated from the Upper Wolfcamp. We don't think there's fractured communication. There's no drainage, so that the Upper and Lower Wolfcamp can be treated as completely independent zones and one is not at the hostage of another on development timing. And that's a wonderful thing to be able to say as we look at that asset. . As far as spacing, Animal Kingdom was a success. That doesn't mean that we'll space it 14 wells per section. We like to watch these wells over time. We like to watch the GOR behavior over time. And 14 wells per section is an early success. But I would say it's probably going to land 12 to 14, but we want to watch these wells before we really pound the table. So far so good. Excellent return on that project. We're very pleased with it. But we're not forced to make an early call on that, and we'd like to watch those wells.

Michael Stephen Scialla -- Stifel, Nicolaus & Company -- Analyst

Yeah, OK, thank you.

Operator

Our next question today comes from Brian Singer at Goldman Sachs. Please go ahead.

Brian Singer -- Goldman Sachs -- Analyst

Thank you. Good morning. First question is a quick follow-up on a comment that you made earlier on with regards to the Mid-Continent. You indicated that your team is focused on finding additional opportunities for -- to compete for capital. Was that a comment on organic opportunities within the existing acreage position that you have? Or was that more of an inorganic -- pursuing inorganic opportunities, such as what you've recently done in the Permian?

Thomas E. Jorden -- Chairman, Chief Executive Officer & President

Well, opportunity is an opportunity. I don't care whether it's organic or inorganic, what I care about is the entry cost. And so organic opportunities, or we'll redevelop an idea and get in and lease it, typically has the lowest opportunity cost but also has the highest risk. But that's our business. And the Anadarko is great hunting ground. . And I don't want to give anybody the impression that there's some hinge thing coming in the Anadarko. But we get asked a lot about our capital allocation and I think it's a fair answer to say we're not pleased with it long term. We want to see a more robust allocation of capital. But right now, we're quite pleased with where our money is flowing. We think it's flowing appropriately. And it's a nice challenge for Anadarko team to come roaring back. . I'll say this, and finishing my answer to your question, it hasn't always been this way. There were years when it was exactly the opposite, where the Permian was having a hard time competing for capital and the Anadarko is leading the charge. So we tend to take a little longer-term view on this than quarter-to-quarter, and it's going to work its way out.

Brian Singer -- Goldman Sachs -- Analyst

That's helpful color. And then my follow-up is with regards to the spacing in the Upper Wolfcamp and the Bone Spring relative to the schematics that you have on Slide 6. Would you say you're moving more as you try to seek here C case, which the optimal spacing? That you're moving more from A to C or moving more from B to C. And just kind of wondering how -- what we should expect from a well productivity perspective going forward.

Thomas E. Jorden -- Chairman, Chief Executive Officer & President

Well, we want to stay -- referring to the slides, where, for those of you that aren't looking at the slides, B is an example where the wells are greatly interfering. There's tremendous fracture overlap, and you've destroyed capital. So my easy answer is we want to stay as far away from B as we can. But our only point here is that many voices out there say you should maximize rate of return. And many voices out there say you should maximize PV-10. We don't think either one of those are very good rule. We think it's reservoir by reservoir. And in particular, you can't make the decision based on the cumulative total project. You really need to look at the incremental return on that last well drilled. Some reservoirs can be very forgiving. And if you drill a well or 2, you're going to be OK. You won't hurt yourself. Other reservoirs, as illustrated on Slide 7, and this is a real-life example, a different example than the ones shown on Slide 6, some reservoirs are so sensitive that if you drill one extra well and push all of those wells closer together, that extra well you drilled absolutely destroyed capital. So we want to be somewhere between that maximum rate of return and that maximum present value. And it's going to be reservoir-by-reservoir and area-by-area dependent.

Brian Singer -- Goldman Sachs -- Analyst

Great, thank you.

Operator

Our next question comes from Doug Leggate with Bank of America. Please go ahead.

John Abbott -- Bank of America -- Analyst

Good morning, this is John Abbott on for Doug Leggate. First question is going back to Slide 6, just trying to get a little bit more color on this. So this 12 to 14 wells per section, how does that decision -- or in this particular example, how would that decision play out at a $50 oil deck, a $55 oil deck or a $60 oil deck? How would that cumulative, that analysis of PV versus return, changes as far as sections -- wells per section?

Thomas E. Jorden -- Chairman, Chief Executive Officer & President

Well, at different commodity prices, those curves are going to shift a little. Certainly, the rate of return is going to shift and the present value is going to shift. But the way it would play out, and we make this decision at every development project, it's a function of your understanding of your fracture geometry and how confident you are in these plots. And I just want to make a little plug for organization, they started working on this type of analysis a couple of years ago. And then after a lot of success internally, we turned them loose studying some competitor development projects. And in similar reservoirs, we asked them to predict the well-to-well interference for some of our competitors' projects, and they had a remarkable fidelity in looking at these analysis, and not only predicting our own well interference but also predicting some competitor well interference. But one of the things that this is also a function of is what does your inventory look like and what are your other opportunities available to you. And why do I say that?

Well, I say that because there are voices out there that are saying that on a graph like this, you should be at the point where you're maximizing PV-10. And although that's not a goofy statement, at Cimarex, we would roundly disagree with that. We would never seek to maximize PV-10 because, implicitly, that means that, that last well you drilled is at a 10% rate of return. And our history, our body of experience tells us that putting drilling capital in for an incremental 10% rate of return is a perilous decision. So we also generate, although we didn't illustrate this on this slide, when we do this internally, we will also show present value 20 and present value 30. Because those are rates of return or discount rates that allow us to make a better decision when comparing other opportunities on our portfolio for that capital. So I know I gave you more detail than you asked for, but we really believe in these curves. They're grounded on a lot of science and years of experimentation. And we're pretty confident in our application of them.

John Abbott -- Bank of America -- Analyst

That was very helpful. And then for the second question, what are your latest thoughts about potentially monetizing your midstream assets at some point?

Thomas E. Jorden -- Chairman, Chief Executive Officer & President

Well, we think about it all the time. We -- at some point, I think it would be appropriate for us to monetize our midstream asset. If we could find a midstream partner that would allow us to take the midstream capital off our balance sheet and give us the absolute outstanding service that we give ourselves, it would be a fairly easy decision. But that's -- a lot of moving parts on what I just said. And that includes run time, compression run time, our midstream assets, are we ready for peak production when it comes online? One of the things I've said for years is you can see Cimarex assets easily, all you have to do is overfly the Delaware Basin at night and you'll see the dark spot, and that's Cimarex surrounded by a lot of heavy flaring. Our midstream group really does a nice job minimizing our flaring, maximizing our run time. And everything I just said is also true for our water assets. Now I don't want to -- I will tell you we talk about this a lot, and I am sure that there will be a time when monetization makes sense. But right now, I will say the reason we own these asset is because it enhances the profitability of our production base. And as long as that's still true, we want to own them.

John Abbott -- Bank of America -- Analyst

Thank you very much for taking our questions.

Operator

Our next question today comes from Neal Dingmann with SunTrust. please go ahead.

Neal Dingmann -- SunTrust -- Analyst

Morning, guys. Tom, I think you all have said when you look at sort of returns or top 10 returns that there is, I think you've mentioned in the past around $65 pretty well split up between the Permian and the Mid-Con. And when it gets down close to $55, it ends up weighted heavily more toward the Delaware. I'm just wondering, prices go back up and were not too far away from that, say, about the $65 and stayed there for a while, would you all consider reallocating more resources there or just adding more, as the prior question had asked, just adding more activity there in general?

Thomas E. Jorden -- Chairman, Chief Executive Officer & President

Well, we -- of course, this is very price-dependent. It's also oil versus natural gas price dependent, and NGL prices are a critical element as well. What we said is of our 10 type curves, our top 10 opportunity set, at typical prices, $55 to $65 band, typically 6 or 7 of our top 10 are Delaware Basin and 3 to 4 of our top 10 are Anadarko Basin. Now there's a lot of other considerations, not the least of which is repeatability, our confidence that we can invest and get the returns that we're targeting, and then our capital needs in a given year. And it just so happens in 2019, Anadarko has made great progress on a lot of fronts, including the Woodford, including the Meramec. Because we were living within cash flow, we just had a higher degree of confidence and decided to swing more of our capital into the Delaware Basin this year. But Anadarko is fighting back, and they're going make it hard for us to keep that true. And that's exactly what we want out of them.

Neal Dingmann -- SunTrust -- Analyst

Okay. I have one follow-up. I'm wondering -- just maybe, Tom, for you or John, you haven't had the new Resolute asset too terribly long, but I'm just wondering, have you listed them and developed them long enough to have confidence in even more sort of multi-zone development, larger pad areas? Just talk about how you see potentially developing it and if anything's changed since you initially got those assets that time?

Thomas E. Jorden -- Chairman, Chief Executive Officer & President

Well, no. We're -- we understood those assets really well. That was right in our operating arena. We're thrilled to have those assets. We're very high on those assets. And as I said in remarks, we have a lot of activity planned on those in 2019. The only thing that's changed from when we did the deal is oil prices went down at the end of the year. We made a commitment to live firmly within cash flow and generate free cash flow this year. And I just want to remind everybody that Resolute was on a pretty screaming outspend. And so folding those in and having a combined discipline meant that we're probably doing a little less on that than we would have said in October, November last fall. But that's a decision we made. That was the right decision for Cimarex. And those assets are going to be a great contributing piece to our portfolio in 2019 and beyond.

Neal Dingmann -- SunTrust -- Analyst

That's a great add. Thanks so much Tom.

Thomas E. Jorden -- Chairman, Chief Executive Officer & President

Thank you.

Operator

Our next question today comes from Michael Hall with Heikkinen Energy Advisors. Please go ahead.

Michael Hall -- Heikkinen Energy Advisorsc -- Analyst

Good morning, thanks for the time. I guess maybe just following up on the questions on Resolute. I was just curious just where we stand on that asset from a volume current standpoint and maybe give us some color about or some confidence in the trajectory of the oil volumes here heading into the second quarter. And when you close the Resolute, volumes were quite a bit lower than at the time of the announcement. And as you said, you're reining back the outspend. Have those assets kind of tapered off on their declines yet? And yes -- and just what sort of early data can you provide us as it relates to trajectory here in the second quarter?

Thomas E. Jorden -- Chairman, Chief Executive Officer & President

Well, let me just give you an intro, and then Joe will make a few comments. One of the other things that happened in the transition period once we got antitrust approval, we were able to get a little more conversational on operations. And we had some information that Resolute did not have. I think it's fairly widely understood that Resolute was drilling wells that we think were spaced much too close together. And I'll also share with you that we had a different interpretation on what that meant than Resolute did. You have multiple landing zones, and so there's always an issue where you need to understand is your interference from landing zone to landing zone or top to bottom, or is it side to side because of your core well-to-well spacing.

And so in the first quarter, we -- sort of by mutual agreement, Resolute sort of stood down a lot of their activity. They released their drilling rigs and they decided not to complete some wells and leave them for Cimarex to complete. That was a decision that we participated in and it was the absolute right decision for those assets. So I know some people were a little surprised that maybe that -- as that oil production declined a little more than they were anticipating, I just want to tell you that, that was a design consequence, not a surprise. And Joe, you want to say anything?

Joseph R. Albi -- Executive Vice President, Chief Operating Officer & Director

Yes. The only thing I'll add is that internally, the minute we put those assets into our shop, they were Cimarex assets. And so we haven't divided up our model or our database in any way, shape or form to say, "Okay, here's this group of properties or that group of properties." Right now, it's all Cimarex. So whatever decline the properties are owned, they're all built into the production guidance that we're giving you guys.

Michael Hall -- Heikkinen Energy Advisorsc -- Analyst

Okay. That's helpful. And just to be clear, I think I heard in the comments, but just want to confirm, I think you said 17 of the 30 wells to sales this quarter are already flowing back, is that right?

Joseph R. Albi -- Executive Vice President, Chief Operating Officer & Director

And we got -- of the Permian wells, 17 of the 21 projected Q2 wells are online. And when drilling the Mid-Continent, we've got 21 out of the total 30 wells that we're projecting for Q2 already online. I know Karen has gotten some questions about the midpoint increase Q2 over Q1. And the other thing I'd reiterate there, and particularly on the oil, is that of the 319-some-odd million that I think we put in our press release, about 70% plus of that is capital associated with the production that's going to come on Q2, 3 or 4. And most of that production is coming on here in May. So April should have been -- should be pretty flat to Q1 with our increase for Q2 starting midyear.

Michael Hall -- Heikkinen Energy Advisorsc -- Analyst

Okay. That's super helpful. And then one other just on the Animal Kingdom pilot. How would you say those Lower Culberson -- or Lower Wolfcamp wells and Culberson compete with the activity set or opportunity set in Reeves? Just curious.

Thomas E. Jorden -- Chairman, Chief Executive Officer & President

Well, if I had to rank our type curves, certainly the Upper Wolfcamp is going to be below that Lower Wolfcamp at current pricing situation. So the Upper Reeves is Upper Wolfcamp. So if you asked me to rank Upper Wolfcamp -- Culberson, Upper Wolfcamp, Reeves or Lower Wolfcamp, Culberson -- it's going to be 1, 2, 3 in that order. They generate very good returns, but they're a little lower yield. And thus, at current commodity pricing, they're third in line with those 3.

Michael Hall -- Heikkinen Energy Advisorsc -- Analyst

Okay, that's helpful, thanks guys.

Operator

Our next question comes from Paul Grigel with Macquarie. Please go ahead.

Paul Grigel -- Macquarie Research -- Analyst

Hi, good morning. The 2019 management incentives now include grow assets in the strategic section with removal of A and D focus from the tactical section. Given the completion of Resolute and your comment earlier on the entry costs for new plays, how should we consider exploration in the scope of 2019 and beyond for Cimarex?

Thomas E. Jorden -- Chairman, Chief Executive Officer & President

Well, you should consider exploration to be part of our DNA and something that we are unrelentingly focused on. If John were here, he would be quick to tell you that I beat on him mercilessly on this subject. And we've got a very good team there. But the challenge is high because we've also got this wonderful deep inventory. So it's a bit of a contradiction to say, "Wow, we have this great inventory, but we always want to be on the hunt for new asset." But that's absolutely the truth. Two reasons. We'd love to find assets that would supplant things in our current portfolio, but just that constant hunt really makes us better as a geoscience organization. And so we would love to find something. I mean many of you are aware, we've talked that we do have a position in Louisiana Chalk. We had that position in Kentucky a few years ago. These were meaningful positions that we got in the low-entry cost. I'm disappointed to tell you that we may never have a lot of production to report. But you know what, it was a low-entry cost. One of these is going to work and we're going to keep hunting. It's just what we do and, quite frankly, it's what we're good at as an organization.

Paul Grigel -- Macquarie Research -- Analyst

Understood. Makes sense. And I guess coming back toward the Permian on the follow-up. Could you provide more color on Culberson? And you mentioned it was overpressured. Is that simply what's driving kind of the continued performance? Is there rock characteristics that vary in there and are more unique to that region? Would be curious of anything else you can share in more detail there.

Thomas E. Jorden -- Chairman, Chief Executive Officer & President

Well, Culberson -- Culberson is unbelievable. I mean I don't want to be promotional on that, but it is tremendous asset. And I hope that many of you were surprised to see the Culberson County by 18 months of production is the #1 oil cume on average in the basin. And what's driving that -- there's Culberson County, and I'm talking Upper Wolfcamp now, is either retrograde condensate of oil to oil in the reservoir, tremendous mobility in that phase and with our 2-mile horizontal wells. So it's not just the rocks, it's that our asset and our acreage is configured to drill long horizontal wells without regard to the least one. So if you look at our average lateral length in Culberson County, it's about 10,000 feet. I mean every single well we're drilling is 2 miles long. And so you get that 2-mile long well, you got all of the feed-in from an effective fracture network, you have the mobility in the reservoir and it's a lower decline in that oil.

And then the other thing that is just as important to point as that cumulative oil is if we were to do a lease -- an LOE or lifting cost analysis county by county, we haven't done that and we should probably do that, but Culberson County -- I would be surprised if Culberson County weren't the lowest lifting cost in the basin because we don't have to put these wells on artificial lift. We also have a tremendous saltwater disposal network there. Our operations team has really built a smart asset. So a lot of things that have come together in Culberson County. Just a jewel for us. But the rocks are primary there. The -- it produces a lot of gas. And from time to time, I think people have discounted Culberson County because of its gas production. But the gas production, the energy in that reservoir and the mobility is wide. It's the #1 oil-producing county in -- on average in the basin.

Paul Grigel -- Macquarie Research -- Analyst

That's very, very helpful color.

Operator

Our next question comes from Noel Parks with Coker Palmer. Please go ahead.

Noel Augustus Parks -- Coker & Palmer Investment Securities, Inc -- Analyst

Good morning. I wanted to touch back a little bit on saltwater disposal. And just as a reality check, you mentioned in your slides that you have a new agreement in Lea County. So could you sort of contrast your own internal water disposal cost versus, I guess, what the market bears for third-party water disposal services. Just give us a sense of the difference.

Joseph R. Albi -- Executive Vice President, Chief Operating Officer & Director

This is -- Bill, I'll take a stab at that. It's not just a quick and easy answer. Because when you put the infrastructure in place, we're spending capital dollars that once we've spend them, we're done and then it just becomes operating expenses. Where we find that there's efficiencies to do that or we have large acreage positions, such as -- altogether, such as in Triple Crown or in Matterhorn. As we get into New Mexico, where we don't have this contiguous leasehold position, we may not have the means to create those efficiencies by virtue of the capital dollars spent for very new wells that might be able to be tied into it. We're seeing, over the last couple of years, there's a number of saltwater disposal service providers in that area that have created a fairly competitive arena for us to have them tie to our wells and put together contracts by which we can dispose into their systems as well as take up out systems water for recycling to create the same efficiencies that we're seeing in Triple Crown and Matterhorn with regard to water recycling for our completion. We may pay upwards of $0.55 to $0.85 per barrel to get into some of those systems in those areas. And again, it's all a matter of who's up there and how much pipe's up there and how competitive the market is. But the overall operating cost of the system we've already put capital into will be much lower than that. And we're building into a return of a capital on all the rates, they're going to charge you any way.

Thomas E. Jorden -- Chairman, Chief Executive Officer & President

It's not just the disposal, but it's also the ability to reuse the water. And we've struck some creative agreements with third-party providers in New Mexico and in certain parts of Texas, where we have the ability to essentially buy back some of that produced water and reuse it in frac operation. . But the beauty of our Culberson County, and what Joe said, Matterhorn, that's our Reeves County system. What the beauty of those 2 systems is that we've designed those with this reuse of produced water in mind. And so as shown in Slide 16, there's a picture of a saltwater system, a riser coming out where we can tap into this produced water system and divert it to a frac crew and use that water for fracking. And that's given us tremendous savings in our water. So there's a lot of moving parts. We're not here telling you that there can be places where third-party solutions are a better solution. And what Joe said, Eddy and Lea County are often that. But we're pretty efficient from a capital standpoint where we're controlling and owning these assets.

Noel Augustus Parks -- Coker & Palmer Investment Securities, Inc -- Analyst

Great. And then for another question. Just wondering in your northernmost Lea County acreage, I think you've done a little bit of drilling to the Wolfcamp B up there. Just wondering, do you have any plans up there or any update on anything you've recently done?

Thomas E. Jorden -- Chairman, Chief Executive Officer & President

Well, that's an area that's more exploratory. It's a little deeper formation than what produces elsewhere in the basin. We've tried 2 or 3 wells up there with OK results. I don't think it's going to be something that we're going to do a lot more drilling on in the near term. But that's an example of, going back to the prior question, it was -- it's really clever idea, we were -- we're really glad to try it, but it's probably not going to turn into a new program that will make -- investors like.

Noel Augustus Parks -- Coker & Palmer Investment Securities, Inc -- Analyst

Got it. Thanks a lot.

Operator

Our next question is a follow-up from Jeffrey Campbell with Tuohy Brothers. Please go ahead.

Jeffrey Campbell -- Tuohy Brothers -- Analyst

Thanks for letting me back in. I just noticed that no one has discussed the upper provision to production in full year '19. I just wanted to ask you what was the primary variables or variable that supported that upgrade?

Joseph R. Albi -- Executive Vice President, Chief Operating Officer & Director

Yes. This is Joe. I'll take an easy stab at that. It's primarily acceleration in the timing of our Permian completion. You saw a little bit of that in Q1. And when we put together our 2 frac fleet schedule and revisited the timing of our completions, it's accelerated not only Q1 but we saw that in Q2 all through the year. So it's basically pulling production up within the quarters but not necessarily changing the well count that we have projected at the beginning of the year.

Jeffrey Campbell -- Tuohy Brothers -- Analyst

Okay, great. That makes sense. Thank you.

Operator

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

Thomas E. Jorden -- Chairman, Chief Executive Officer & President

Yes. Thank you. Just in closing, I want to say we're very excited about our current performance. Very confident that our organization will execute and deliver on what we promised. And in closing, I really want to thank everybody on the call. We've had some good questions, some pertinent questions and focusing on issues that we think are good to discuss. I hope we've given you complete and thorough answers, and we always look forward to good discussions about Cimarex. So thank you very, very much.

Operator

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

Duration: 57 minutes

Call participants:

Karen Acierno -- Director of Investor Relations

Thomas E. Jorden -- Chairman, Chief Executive Officer & President

Joseph R. Albi -- Executive Vice President, Chief Operating Officer & Director

G. Mark Burford -- Vice President & Chief Financial Officer

Gabe Daoud -- Cowen -- Analyst

Jeanine Wai -- Barclays -- Analyst

Jeffrey Campbell -- Tuohy Brothers -- Analyst

Michael Stephen Scialla -- Stifel, Nicolaus & Company -- Analyst

Brian Singer -- Goldman Sachs -- Analyst

John Abbott -- Bank of America -- Analyst

Neal Dingmann -- SunTrust -- Analyst

Michael Hall -- Heikkinen Energy Advisorsc -- Analyst

Paul Grigel -- Macquarie Research -- Analyst

Noel Augustus Parks -- Coker & Palmer Investment Securities, Inc -- Analyst

More XEC analysis

All earnings call transcripts

AlphaStreet Logo