Karen Acierno - Cimarex Energy Co. Thomas E. Jorden - Cimarex Energy Co. John Lambuth - Cimarex Energy Co. Joseph R. Albi - Cimarex Energy Co. G. Mark Burford - Cimarex Energy Co..

Michael Stephen Scialla - Stifel, Nicolaus & Co., Inc. Joseph Allman - Robert W. Baird & Co., Inc. Neal D. Dingmann - SunTrust Robinson Humphrey, Inc. David A. Deckelbaum - KeyBanc Capital Markets, Inc. Michael Dugan Kelly - Seaport Global Securities LLC John H.

Abbott - Bank of America Merrill Lynch Jeffrey Campbell - Tuohy Brothers Investment Research, Inc. David Martin Heikkinen - Heikkinen Energy Advisors LLC Jamaal Dardar - Tudor, Pickering, Holt & Co. John Nelson - Goldman Sachs & Co. LLC.

Good morning, and welcome to the Cimarex Energy First Quarter Conference Call. All participants will be in listen-only mode. After today's presentation, there will be an opportunity to ask questions. Please note, this event is being recorded. I would now like to turn the conference over to Karen Acierno. Please go ahead..

Good morning, and welcome to the Cimarex first quarter 2018 conference call. An updated presentation was posted to our website yesterday afternoon, and we will be referring to this presentation during the call today. As a reminder, our discussion will contain forward-looking statements.

A number of actions could cause actual results to differ materially from what we discuss. You should read our disclosures on forward-looking statements in our latest 10-K and other filings and news releases for the risk factors associated with our business.

And we filed our 10-Q for the three months ended March 31, 2018, yesterday As always, we will begin with prepared remarks with an overview from our CEO, Tom Jorden, followed by an update on our drilling activities, and results from John Lambuth, SVP of Exploration.

And then Joe Albi, our COO, will update you on operations, including production and well costs. Our CFO, Mark Burford is here to help answer any questions you might have.

So that we can accommodate more of your questions during the hour we have allotted for the call, we'd ask that you limit yourself to one question and one follow-up, feel free to get back in the queue if you like. With that, I'll turn the call over to Tom..

Thank you, Karen, and welcome to everyone on the call this morning. Cimarex delivered a strong first quarter. We reported solid operational and financial results, with production averaging 206,000 barrels of oil equivalent per day, which was at the high-end of our guidance.

Oil production for the quarter averaged over 65,000 barrels per day, we reported adjusted net income of $174 million or $1.82 per share. We're off to a strong start to 2018. In the Delaware Basin, we have 14 new Cimarex-operated wells, which achieved a sustained 30-day peak production rate during the first quarter.

These 14 wells had an average IP-30 of 1,908 barrels of oil equivalent per day. Oil from these wells averaged 1,178 barrels of oil per day.

Our production and capital guidance for the year remain unchanged, with production anticipated to average 216,000 barrels of oil equivalent per day at the midpoint and capital projected to be $1.65 billion at the midpoint. We have a number of projects underway that we look forward to discussing as results come in.

Our Lea County, New Mexico program is delivering strong results as we expected. In Lea County, Reeves County, and Culberson County, we have a number of development programs underway that are progressing well, and we look forward to discussing their results as the year rolls on. John will update you on a few of these projects in a moment.

Thus far, service costs inflation has not been a significant factor in 2018. Furthermore, we are increasing our use of local sand in the Delaware Basin, which holds the promise of modestly decreasing our stimulation costs.

The overwhelming majority of our wells for 2018, are multi-pad development wells, whose capital efficiencies are included within our guidance range. We also announced marketing commitments that give us surety of flow for our Permian gas volumes through 2019.

Although we expect midstream operators to find additional takeaway capacity through compression upgrades and creative engineering of flow dynamics, these marketing commitments give us confidence that our gas will flow to market.

While the conversation revolves around gas, these marketing commitments for our gas volumes are really insurance that protects our oil revenues, which are projected to be almost 75% of our total Permian revenues. In the current environment, oil revenues are the backbone of both our cash flow and our development project economics.

We are in good shape on oil takeaway. We have strategic partners in our core areas who purchase our oil and have backstopped these volumes with firm pipeline takeaway. Over 70% of our Permian oil volumes leave the field on pipe, which reduces our exposure to trucking volatility. These marketing commitments are priced at local index.

Although 30% to 35% of our Permian oil basis differential is hedged, the majority of our sales are at index price. Temporary blips in index pricing are a part of the business that we are prepared to weather. These differentials are baked into our cash flow models and development economics. As I tell our organization, we are an ark, not a party boat.

We retain flexibility to adjust our CapEx as conditions dictate. At this time, we're holding firm with our previously-announced production and CapEx guidance. However, as conditions change, we're prepared to make adjustments to adapt to these changes. Right now, it's steady as she goes.

We said at the beginning of the year that 2018 would be a year that defines companies by their ability to execute complex projects, apply good science, and deliver results that are top-tier.

Cimarex continues to be driven by science, as we work on configuring development projects that maximize value, understand the physics of our stimulations and well-to-well interference, and execute a capital program that delivers full cycle, fully-burdened returns. We have not strayed from that focus.

Production growth and headline wells are fun and interesting, but there are consequences of good investment decisions, not primary drivers. We are here for the long run. With that, I'll turn the call over to John..

Thanks, Tom. During the first quarter, Cimarex invested $313 million in exploration and development activities, of which $264 million was invested in the drilling and completion of new wells. 61% of our capital was spent in the Permian region and 38% in the Mid-Continent.

We brought 15 net wells on production during the quarter and are currently operating 13 gross rigs, with 10 in the Permian region and three in Mid-Continent. Now, I'll turn to some specifics about each region.

I will start in the Permian region where we brought nine wells online during the first quarter, including two significant Avalon wells in Lea County, New Mexico.

One of them, the 10,000-foot lateral Coriander AOC 1-12 State 1H, had an average peak 30-day initial potential rate of 3,333 barrels of oil equivalent per day, of which 67% was oil, 17% NGL, and 16% gas.

While the other, the 5,000-foot lateral Thyme APY FED 19H, had an average peak 30-day rate of 2,059 barrels of oil equivalent per day, 69% oil, 18% NGL, and 13% gas.

The results and learnings from these two Avalon wells are proving critical in finalizing the final stimulation design for the soon-to-be completed six well Triste Draw spacing pilot, which is testing 20 wells per section within two benches in the Avalon section.

Moving on to the Wolfcamp, where we have two spacing tests currently waiting on started completion. In Culberson County, the Animal Kingdom infill development, which consists of eight 10,000-foot laterals in the Lower Wolfcamp should begin fracking operations in early June.

These wells are testing the equivalent of 14 wells per section by both decreasing the spacing between wells in a bench plus adding an additional landing zone in the top part of the Lower Wolfcamp, a zone which we used to refer to as the Wolfcamp C. These wells are expected to be on production by the end of the third quarter.

Another important test in the Upper Wolfcamp, located in Reeves County, is the Snowshoe pilot, which is scheduled to begin completions later this month. These eight 10,000-foot wells are testing the equivalent of 18 wells per section in the Upper Wolfcamp. Stay tuned for result on these development projects later this year.

As shown on slide 12 of our investor presentation, we continue to make great strides in understanding and designing highly-economic development projects, with the appropriate completion design, landing zone, as well as the optimal number of development wells per section.

As shown on the bar chart, our latest generation completion design, Gen 4, was used not only on single-well projects, but also to complete our first ten 10,000-foot Upper Wolfcamp infill wells, which are located in Reeves County.

Not only did these wells achieve 90% of the 180-day cumulative production number of the 23 parent wells completed with that same design, they have also significantly outperformed their actual parent well which was completed with a Gen 2 completion. You can view this performance on slide 16.

And because of the efficiencies gained from pad drilling and zipper fracs, the Gen 4 infill wells were drilled and completed at a cost, which is approximately 90% that of a Gen 4 parent well. Now on to the Mid-Continent.

Completion operations are underway on the Meramec Steve O development project, which consists of six 10,000-foot laterals landed in two benches within the Meramec. This development is the equivalent of eight wells per section.

We've learned a lot from our own spacing pilot, the Leon Gundy, as well as the results of several recently completed non-operated Meramec spacing pilots. These learnings were incorporated into to the final landing zones and completion design for this and other Meramec development projects planned for 2018.

First production from the Steve O well is expected in August. We planned to spud three other Meramec development projects in 2018 across our acreage position. And in the Woodford Lone Rock area, completion operations are underway on the Shelly spacing pilot, with first production expect to begin in late September.

Furthermore, a second Lone Rock development project called JD Hoppinscotch will finish drilling by the end of this month, with completion operations scheduled to begin in early June. With that, I'll turn the call over to Joe Albi..

Thank you, John, and thank you all for joining our call today. I'll touch on our first quarter production, our full-year 2018 production guidance, and then, I'll finish up with a few comments on Permian takeaway, LOE and service costs.

As Tom mentioned, we had a solid quarter for our production in Q1, with reported equivalent volume of 206.1 MBOEs per day. We came in above the upper-end of our guidance and set new records for equivalent production at both the company and regional levels. With the mark, we were up 3% over Q4 2017 and 16% over Q1 2017.

Oil, again, drove the growth with our Q1 net oil production of 65,212 barrels a day, up 6% over Q4 2017 and 25% over Q1 2017. With strong activity in both areas, we continue to see nice production gains in both the Permian and the Mid-Continent.

Our first quarter Permian posting of 114.2 MBOEs per day was up 19% as compared to Q1 2017, while our Mid-Continent volume of 91.4 MBOEs per day was up 13% from a year ago. Oil, again, played a significant role in regional production growth, with our Q1 Permian oil volume up 21% and our Mid-Continent volume up 38% as compared to Q1 2017.

Moving on to our 2018 production outlook, with a strong Q1 in the books, and some slight shifting of completion timing into the second half of the year, we're maintaining our full-year guidance projection of 211 MBOEs per day to 221 MBOEs per day.

Similar to our discussion last call, the majority of our completion activity is planned for later in the year, with an estimated 38 net completions timed for the first half of the year, and 83 timed for the second half of the year.

With that we're projecting second quarter production to be relatively flat to Q1, followed by a strong production ramp beginning in late Q3 and extending into Q4. With the ramp, we're projecting our Q4 oil volumes to be up 30% to 35% over our Q4, 2017 oil volume of 61,771 barrels per day.

With the model we're guiding our Q2, net equivalent volumes to land in a range of 200 MBOEs per day to 209 MBOEs per day, with our forecasted late year production ramp resulting in a full-year guidance range of 211 MBOEs per day to 221 MBOEs per day, that's an 11% to 16% increase over 2017 production. Few words on Permian takeaway.

With the recent tightening of product takeaway in the Permian, our marketing team has been hard at work to ensure, our oil, gas, and NGLs move out of the basin. On the gas side, we've agreed to terms for the sale of more than 98% of our projected Permian residue gas volumes through October of 2019.

Our NGL production is linked to numerous processing facilities across the basin where we have either purchaser-backed, firm or established long-term sale arrangements in place. And on the oil side, the majority of our Permian oil is on pipe, the strategic partnerships and oil agreements in place to ensure flow through 2019 and beyond.

Our marketing team has done a great job to ensure, flow is coming out of the Permian and they remain equally focused on flow out of the Mid-Continent as well, where we are currently evaluating all means to ensure, near to long-term product flow to get our oil, gas, and NGL to market.

Our goal in both the Permian and the Mid-Continent is to ensure product flow. On a realized price basis, however, we will still be exposed to the El Paso, and Waha basis differentials in the Permian, and the Panhandle and Ann Arr (15:37) and OGT differentials in the Mid-Continent.

Shifting gears to OpEx, our Q1, lifting costs came in at $3.84 per BOE, down slightly from the $3.89 posting we had in Q4 2017, and in the lower-end of our guidance range of $3.75 to $4.35 per BOE.

We saw some cost pressure in items such as compression, contract labor, and rentals during the quarter, and with Q1 in the books and our previous guidance incorporating potential cost creep during the year, we're keeping our lifting costs guidance midpoint intact, but we're tightening our range to $3.80 to $4.30 per BOE for the remainder of the year.

And lastly, some comments on drilling and completion costs. On the drilling side, we've seen some small increases in ancillary services such as mud and cement and equal pressure on rig day rates during the quarter.

But with our continued focus on efficiencies and primarily a result of our completion costs components remaining relatively in check, as Tom mentioned during the quarter, our current drilling and completion AFEs remain in check, with the ranges that we quoted last call, with the exception of our Permian wells, which should begin to see the cost savings benefits of us procuring a regional sand sourcing arrangement with our service provider beginning here in May.

In the Permian, depending on area, interval, facility design and frac logistics, our current Wolfcamp 2-mile AFEs are running in the range of $11 million to $13.5 million. With local sand sourcing, we anticipate this range dropping to approximately $500,000 per well to $10.5 million to $13 million here in Q2.

With our New Mexico Bone Spring development in the deeper areas of northern Eddy and Lea Counties, our 1-mile Bone Spring AFEs are running $7 million to $8.5 million per well, and again, with local sand sourcing, we're anticipating to drop this range by $300,000 per well to $6.7 million to $8.2 million.

In Cana, our 1-mile lateral Woodford AFEs continue to run around $7.5 million to $8 million. And with our current frac design, our 2-mile Meramec AFEs are still on the $11.8 million to $12.8 million range, the same levels we quoted last call. So, in closing, we had a solid first quarter.

Our liquids-rich focus in the Permian and Mid-Continent continues to generate sizable oil growth. Our beginning year 2018 production guidance remains unchanged. Projecting a strong Q4 production ramp, with Q4 oil volumes forecasted to be up 30% to 35% from Q4 2017.

Our lifting and development costs remain in check, with further Permian well costs reductions anticipated in Q2, with the implementation of local sand sourcing. And we've taken steps on the marketing inside to ensure takeaway issues do not become a bottleneck for either 2018 or 2019 Permian programs.

We remain excited about the prospects for yet another successful year here in 2018. So with that, I'll turn the call over to Q&A..

We will now begin the question-and-answer session. The first question comes from Mike Scialla with Stifel..

Yeah, good morning, everybody. I wanted to ask you about your guidance, in particular, for second quarter production, you're forecasting kind of flattish, with first quarter actually down slightly, looking at what you did in the first quarter when you brought on only 15 net wells, you had some sequential growth.

Looks like you're planning on adding more wells in the second quarter than you did in the first quarter, I think 23 wells.

Just wondering is that too simplistic in approach to suggest that your second quarter guidance is conservative, or I guess, any color you can add to that?.

This is Joe, and I guess I'll answer that question is relative to what we guided at the beginning of the year. We virtually from our standpoint have not seen significant change in our guidance at all. Last quarter, we were quoting, I think, 45 wells during the first half of the year and 82 wells in the latter half of the year.

We're currently at 38 wells in the first half of the year and 83 wells in the last half of the year. The shifting of completions that I mentioned about is really associated with, primarily with one of our eight well infill projects, which was scheduled to come on here in Q2, but we'd split it into Q3.

And that was due primarily to a drilling issue on one of the wells, and when you have an eight well project, one well can affect all eight with regard to the timing of the completion of all eight wells. And it's not just that type of program that's really driving our production profile.

We've got the Animal Kingdom eight well projects; the Hallertau, six well projects; Snowshoe, eight well project; Triste Draw, six well project. All of these wells are coming on line here, with the majority of our capital going into Q2 and Q3 and in fact, we're up in our rig count – our frac fleet count up to 6 fleets here in June.

The profile you're seeing is just a result of that. And what Tom alluded to, we don't run our business based on what production profile we're going to get, we run it on the rate of return and we're expecting to generate out of our projects and the capital that we deploy.

So, our profile becomes a byproduct of it, and if you look at net well counts changing, I know Karen's got a number of questions about what wells dropped or what wells didn't, I'll simplify it and say as compared to our previous model, we had 12 wells move out of Q2 and Q3 that were previously in our original year guidance.

Two of those wells moved into the first quarter. Seven of those wells moved into either fourth quarter or first quarter of 2019 and three other ones moved further in the year with a reshuffling of some of our drilling schedule. The bottom line to us is, the guidance didn't change..

Okay..

Mike, let me just add to that. Our guidance, we tried to do a good job, best we can and sometimes, it's simple and sometimes, it's complex. But our guidance is really a function of two things. Certainly, our well schedule and that's pretty sad. I don't anticipate that's going to change. And then the second factor is our estimate of production per well.

And so, is our guidance conservative? Well, I hope not I think it's realistic. We, certainly, try to make it realistic. But we're always playing around with stimulations and to the extent that there's some upside there.

I'd love to see us report in the future quarter that our wells produce in excess of what we model based on some stimulation advancement. But I don't think we're sandbagging, that we're just trying to give you our best guess..

Okay, perfect. Thanks. And I want to ask on your gas sales agreement.

Are there any minimum volume commitments associated with that, or acres dedication? Anything you can say about how that works?.

Yeah. I know there'll be number of questions on it. So I'll just cover it at a high level. Fortunately, with our Triple Crown and our Matterhorn systems in place, we have access to multiple markets, which certainly works in our favor. As Tom mentioned, our focus has been surety of flow, make sure the product gets sold.

We sell our residue gas either as gas we take-in-kind on the tailgate of a processing plant or directly to the purchaser at the tailgate of the processing plant.

What we've done during the last quarter, and I feel like we've done a very, very good job of is for that gas that we can take-in-kind we're either selling directly to utilities, LDCs, end-users, who have demand, and firm transports or that gas; or to counter-parties and I've put there are reputable processors in the same category that either have firm transport out or a purchaser-backed with purchasers who have firm in their hip pocket to get the gas out of the basin.

So, our goal was to sell to parties that have firm and we have confidence have firm to get the gas out of the basin. We took a look at our projected production profiles, not only of our base wells, but our 2018 and 2019 drilling programs.

We looked at what potential residue could be there under recovery or rejection, of each one of those processing facilities and we put our forecasted volumes in place that our marketing team was able to line up with purchasers..

So, Mike, there's – we've committed volumes. So, as Joe just said, we do through 2019 estimate volumes. We pre-commit to sell those volumes. And we're going to be working to deliver those volumes. But they're not long-term commitments. They will be on 2019..

Great. Thank you..

And I might mention that this is a typical day of business for our marketing team. We just don't typically go out two years for our take-in-kind of sales, but we did in this case..

The next question comes from Joe Allman with Baird..

Thank you. Hi, everybody..

Hi, Joe..

On Slide 19, could you – regarding the Delaware oil takeaway. Could you talk about the other 30% that does not flow on pipe? And then also, Joe, you mentioned kind of recent tightness.

Have you folks actually seen physical signs of tightness?.

Joe, this is Joe. We have not seen the signs you're talking about. And I want to take a step back on the oil, because there's a perception out there that the piped oil is safe and the trucked oil may be at some risk.

As we've mentioned, the majority of our oil is on pipe and that oil is on pipe with entities that we have these strategic partnerships and agreements in place, with committed volumes that they're allowing us to flow out of the basin. The parties that we're selling to the majority of our oil have pipe out of the basin and we have space on that pipe.

The trucked volumes that we have, albeit although, they may not be on pipe, a vast majority of those trucked volumes are also being sold to those same entities that have the pipe out of the basin where we're able to piggyback on those piped arrangements. If not, in one case, we're selling to purchaser but they're a local refinery.

So, what we're seeing from a risk standpoint or a volatility standpoint on the trucking side isn't getting it out of the basin. It maybe, we're at some risk as to what the trucking costs might end up doing..

You know Joe, what I look at it, when I see these volumes and we look at what percent is on pipe and what percent is on truck, I think about it more in terms of field management and exposure to weather delays and also trucking backlog. I don't think of it, as Joe has described, we don't view it as necessarily a distinction on basin takeaway.

But your other question on physical constraints, I'll let Joe address that..

Yeah. Joe, we have not been bottlenecked or pinched back on either the NGL, oil, or gas side as a result of the concerns about tightness..

Okay. That's helpful. And then as a follow-up. On slide 12, I know you described it a little bit. But could you describe this more fully, we see the Gen 4 wells and we see the Gen 4 infill wells. My impression is that those Gen 4 infill wells are not the child wells to Gen 4 parent wells.

My understanding is that those Gen 4 infill wells are child wells to some of the parent wells you drilled in prior years. I think specifically actually the Gen 2 wells. And yet the last bullet on that slide seems to say that your infill wells are 90% of the parent wells.

So, could you just help us figure that out a little bit better?.

Yeah, this is John. You are correct in that the infill wells that we're showing on that chart, the parent wells within the same section are not of the same generation, that is a true statement.

However, we would actually say it's rather encouraging the productivity of those infill wells, because we would argue that that older generation frac design was quite frankly not very efficient from an infill standpoint, in a way what I mean by that is the older generation we believe was a) probably not as well designed in terms of the cluster spacing just leaving unstimulated rock along the lateral.

So instead it was probably pushing further out from a frac grappling standpoint. So, in some ways, I would argue that, because these infill wells are performing as well as they do, that just attributes to how good our Gen 4 design is.

And yeah, we would have every expectation that when we go to develop infill wells next to a Gen 4 parent well, we would still achieve for the same spacing that type of result.

Another way I think about it is, with this later generation design, again, we think that we've eliminated most of the unstimulated rock along the lateral, so we don't see it as much as acceleration as much as we see it as new rock being stimulated, which is why, again, we think it's very important that we're achieving that kind of result so far.

The last thing I'll say is, of those infill wells, I think the other reason we like that number is you have to keep in mind one of those projects was testing very tight spacing, maybe probably beyond what we would normally do in that particular section and yet still we were achieving 90%, and let me be clear, 90% of similar stimulated parent wells, even in the same proximity, which we would say same kind of geology.

So no, I think there's a very encouraging chart from what we've seen so far..

Yeah, Joe, your observation's spot on, though. When you look at that slide 12, the parent wells associated with those infill, those infills are better than the parent wells. It's just that those parent wells were older generation.

So, all we did in making this slide is we looked at the entire population of Gen 4 wells and we separated out the parent from the infill in that population..

Yeah..

And there's been a lot of questions about that, the optimum infill-to-parent child ratio we're looking for, we could spend the rest of the call on that. That's a subject of intense scrutiny here at Cimarex..

So, if I could just clarify, so that 90%, does that refer to infill wells that are child to parent that are also Gen 4?.

Yeah. The 90% is basically as you see from the chart, the 90% cum is of the infill 2, all of the parent wells of the similar generation frac. But let me be clear, a lot of these parent wells are in the same proximity as these infill projects.

So it is somewhat relative in terms of, you know there's expectation but again, it's also dictated by the ultimate spacing that the infills were drilled at.

And right now, given what we have done to date, 90% at least from our observation is a pretty good outcome from a development standpoint, especially when we start factoring in, as I said, some of the cost savings that we realize when we go to infill with the multi-pad drilling zipper fracking, this is a very good economic outcome..

All right. It's all very helpful. Thank you, guys..

The next question comes from Neal Dingmann with SunTrust..

Good morning, all. Maybe my first question is for John. John, looking at the slide 22 you guys, certainly, have a large amount of that as you pointed out here the stacked opportunities between the Meramec and Woodford.

Could you talk about that a little bit more how are you going to continue to tackle that? Will you do some sort of stacked laterals? Or maybe just talk about, number one, where do you see the best prospectivity for that and then how you're going to go after that?.

Yeah. What you see on slide 22 is a representation of our prospective drilling window for both Woodford in the blue outline and Meramec in the orange. And there is a nice overlap there and indeed we are fortunate to have a large acreage position, in an area that we call 14N-10W where we see very significantly pick Meramec and Woodford.

And as we have announced, I think last call, have demonstrated successful results with our Wolfcamp NIV, we're able to stack multi Meramec landings with Woodford Landings. So, that area particular one is where we'll do some additional testing to get more comfortable what the ultimate spacing will be.

But if I back up a minute where we're really at, especially with Meramec is as I said in my prepared remarks, we ourselves are just now moving into development in the Meramec with the Steve O project and with a number of other projects we have scheduled for later this year.

We have benefited greatly from all the other spacing pilot projects that have already been brought on, there is a large learning there. And we're feeling pretty confident now that we think we can design the appropriate spacing for the Meramec, based on essentially in-place volumes, hydrocarbon type pore pressure.

It will not be one-size-fit-all in the Meramec. We're very much convinced of that. And as I said, I think even last earnings call, we see variability in the Meramec such that development may range anywhere from four wells maybe up to 10 or 12 wells a section, that's still for us to be decided and that some of the things we'll be testing this year.

Coupled with that again is, we will be testing some more stacking of Woodford and Meramec to where we can gain confidence to what that ultimate development looks like for 14N-10W, because it's a pretty daunting challenge.

It's a large, large acreage position, large capital commitment on our part, and we want to make sure when we move forward with it that we get it right. I hope that answer your question..

No, no, that was very good. And then, Tom, might just one follow-up I had, you all have the benefit of having two great players and you know, again, having the optionality to go either with the Mid-Con or the Perm.

When you see sort of temporary blips, and as you called it on, dips as you're seeing right now in the Midland Basin, does that cause you to sway and maybe allocate more resources towards the Midland Basin – or I'm sorry towards the Mid-Con, or do you just not want to get in that game?.

Well, I'd love to get into that game, all I need is clairvoyance. The differentials have exploded so fast that – had one of you on the call tipped me off, we might have redirected capital 12 months, 18 months ago.

But this is a longer-term game and these short-term swings they pass and as we've talked about in the past, three markets work efficiently here, we're seeing a lot of projects that are going to collapse these differentials.

And although, yeah, I wish we had perfectly predicted them and steered our capital to perfectly mirror the right basin to be bringing incremental volumes into. We just don't have that degree of clairvoyance..

Point taken. Thanks, Tom..

The next question comes from David Deckelbaum with KeyBanc..

Good morning, Tom, John. Appreciate the time for the question..

Hi, David..

Just curious so far, it sounds like with the agreements in place that you have on the marketing side and the flow assurance, that basis or logistics have not yet changed, how you're thinking about bringing wells online, or timing, or where you're allocating capital to, is that fair?.

Well, it is fair. No, I said in my opening remarks that we're looking at this situation closely. And we're managing our balance sheet, we're managing our cash flow, we're managing our capital expenditures. Right now, we're holding firm. But we've got some flexibility..

Okay, I appreciate that. And I wanted to ask some questions about the in-basin sand savings that you're projecting right now, especially in the Delaware.

How are you going to be deploying that, is it going to be ubiquitous across like some of the larger projects, or is it going to be more like in a couple of wells here and there and more of a pilot stage? And are you going to be completing those wells differently than you would with some of the legacy sand?.

This is Joe. I'll take that one. The intent of the agreement was to and I can't get into the definitive terms in great detail. But to provide us with assurances as to volumes that we felt we would need for the majority of our Permian program, whether it was an Avalon well, Bone Spring completion, Wolfcamp well.

And what we ended up doing was come to an agreement on what that volume would – annual volume commitment would be through our service provider and what our commitment would be on the other side of that.

And with those volumes, I would say a comfortable range to feel that we could utilize 4% local sand versus other would be about at least 80% of each well sand based on our current program right now. Sand needs would be provided through local sand sourcing. And so, that's where I came up with the numbers that I quoted earlier in the call.

So, it wouldn't be one type of well or another. It's for the Permian program in general..

Does that agreement allow you to take another source of sand if you deem the results to be inadequate?.

Yeah. We had always had that flexibility..

Thanks, guys..

The next question comes from Mike Kelly with Seaport Global..

Hey, guys. Good morning. I wanted to....

Hey, Mike..

I wanted to go back to slide 12 and take a look at this kind of infill well performance here. I got two questions on this.

One, do you expect the performance delta between the parent-child wells to stay at this kind of 10% level, or could you see further divergence as you get one year to one and a half years out? And then two, I wanted to get your sense of just how you think about potentially just mitigating the parent-child degradation all together by bringing on these mega pad completions that some are doing, and if that even does mitigate the potential degradation and if you're interested in that? Thank you..

Well, in regards to our expectation going forward, I would fully expect that if we were to here recently go develop another section with a Gen 4 parent well in that section and develop it with the same spacing that these particular infill wells we drilled at that we would probably achieve about the same ratio from parent to infill.

That would be my expectation. And yeah, I do expect that to hold up. Now that's for the same spacing, same thickness, same hydrocarbon in place. And so, what is fair to say, is we ask ourselves all the time what is the appropriate spacing, and we look at those economics carefully.

I'm not sure that one argument can be that infills should be equal to parent. But then you could run into a problem where you are arguing you're leaving some resource behind. So, we do and have always argued there should be some small amount of acceleration between infill wells.

But we also recognized that you can go too far, and if you go too far, you can see major degradation in your overall project returns. And so again, this one snapshot here has given a representation from what we've done to date. I would say we're getting close to what we think would be an optimal type of result for an infill to a parent.

I think your other question dealt with the megaprojects, which I think is trying to address just the idea that you don't even have parent, you try to go straight to development and boy in a perfect world, yeah, we have many of us say it'd be great if I can go straight to my acreage and just immediately start developing that and never have to worry about a parent-child relationship.

But then reality sets in for the vast majority of us, we have lease expirations. We have commitments that we have to do in order to perpetuate and to hold that acreage, which requires us in many cases to drill that parent well to then get that acreage to an HBP status.

In those circumstances where we don't have to do that and yeah, we feel like we probably benefit a little bit more by not having that initial parent well there, but let me also say that we internally have spent a lot of time looking at this parent-child relationship, and we recognize that it's very, it's quite variable both across all the different intervals that we develop, as well as one of the biggest factor is time, time that the parent well has been producing relative to when you get back and develop.

And then finally, the type of stimulation you put on that parent well, has a major impact in terms of that ultimate parent child relationship.

I think we have moved very aggressively in our understanding such that even if we have some sections with parent wells, I think we feel pretty confident what our ultimate infill wells will do, relative to that parent well. And Tom, I don't know if you want to add anything..

The only thing I want to add to that is to comment on these megaprojects. I know there's a lot of different philosophies circulating out there on the best development scheme. And we listen to them all. We have a lot of respect for many of the players that are espousing particular philosophies there.

We're not of a one-size-fits-all motif, you heard earlier in the call, Joe mentioned that, we've gotten a lot of tons of questions about why's your well count down? Well, our well count is down because of one side track on one well that backstops the development program and it shifted everything back one month.

And so, when you get these megaprojects, you do run the risk of timing delays because of any kind of mechanical interruption that cascades through the whole project. You also have long delays between first investment and first production.

And so, as John said we're big fans of megaprojects, because, yes, they do indeed help you manage the parent-child issue, but they also come with their own set of problems. So, we really look at each one in an individual lens and we'll make decisions based on the individual project. So, it's good question and we won't have one answer for our assets..

Yeah, that's fair. I appreciate the discussion. And just follow-up for me on the marketing front. The near-term strategy seems pretty clear, it's focused on flow assurance and you've checked that box. But Tom, I'm curious in the longer-term strategic front here.

Has that evolved at all, or any change how you think you'll kind of approach marketing out of the Permian long-term? Thanks..

Well, we're debating that, we debated all the time. We're going to sound like a broken record here.

We really like flexibility and long-term marketing commitments limit your flexibility, if you have long-term volume commitments in a fluctuating commodity price environment, you can find yourself in a situation where your cash flow can fluctuate down and yet you've got these volumes you have to deliver.

I mean you don't have to look very far into the landscape of our peers to see stories where people have been caught in that wedge, and we would seek to avoid that. So, we typically want to preserve our flexibility and we'll avoid long-term commitments..

Understood. Thank you..

This is Joe. I want to follow-up on that too, that to the extent we do make them, we methodically look at projections of production, either oil or gas depending on where we may be locking into, to understand with a start-stop drilling program if needed for capital or price reasons.

What volumes we would feel comfortable in committing and we have in the past committed volumes under that type of basis – or under those terms..

Got it. Thanks..

The next question comes from Doug Leggate with Bank of America Merrill Lynch..

Good morning. This is John Abbott on for Doug Leggate, it looks like Doug hopped on to another call. Just a couple of questions for us. First, in the Permian you have sales agreements in place for 98% of your gas through October 9, 2019. You apparently have contracts still in place beyond that.

What happens to your outlook, if pipeline such as Gulf Coast Express, which is expected to come online at the end of 2019, were say delayed for some reason for by half of the year?.

Well. This is Joe. We mentioned October 2019 in our press release and in the call, but we're looking into 2020 as well for these agreements.

And I think I mentioned earlier in the call that, this is kind of the day-to-day business for our marketing group to try and get out ahead 6 months to 12 months, with any of our take-in-kind arrangements to sell residue to these utilities. And so as we creep ourselves closer into 2019, we're not just going to say, no, we can't go past October.

We're going to keep perpetuating that. As you know, there are – every day you turn around there's yet another potential proposed project at Waha, last I saw there were eight or nine of them with over 15 Bcf a day of in cum takeaway out of Waha. And we're looking at all those. We're talking to those players to look out past 2019 as well..

Appreciate the color. Then our second question is on slide 13 where you talked about the returns for the Culberson long lateral Wolfcamp wells. Compared to 4Q results, it looks like your returns to the upper Wolfcamp have increased and our understanding is that is you're incorporating type curves from your western acreage.

As you look out over a three-year to four-year horizon, how reflective are these returns on your go-forward plans?.

Well I think first off what you're recognizing is indeed a type curve change due to performance on those wells, we've announced in the past on the western side of our Culberson acreage. It's – quite frankly, we've even been pleasantly surprised just how good and robust those wells have been over there.

But there's still a lot to do over there in terms of what does ultimate development look like on the west side of Culberson relative to the east side. We've done a lot of development now on the east and southeast part of our Culberson block with some outstanding results. But as we go to the west, it's a little bit different.

It is a little bit gassier, but it has great deliverability, which is leading to the outstanding results we're seeing.

The other thing we're recognizing on the west side is it looks like we may have even additional landing zones to explore and I think I've mentioned that in the past where we're moving further up the section into what has been called the X and Y sands, and we'll soon have some wells that we'll be able to talk about in that.

All that will ultimately lead to what our final major investment decision will be on that side and how we'll go about developing that..

But I would add to that, when we look at any capital allocation and we discussed this on our last call in some detail, when we look at any capital allocation, one of the things we ask ourselves is how repeatable is that program, and how confident are we in that repeatability.

And our upper Wolfcamp program we went back and looked at the last two and a half years, three years. And those are years where our program kind of found its rhythm with longer horizontal wells, and we've achieved excellent repeatability.

And when I say that I mean, we measure ourselves on actual to expected, IP-30 rates, actual to expected IP-90 and 180-day rates, actual to expected costs and the actual expected estimated ultimate recoveries. So, there's lots of things we cannot control, commodity pricing being one.

But with respect to things we can control, our program particularly in the Wolfcamp is highly repeatable and so we think these returns as evidenced by slide 13 are our go by..

Thank you very much, very helpful..

Now those – just let me say before we move off this topic.

These are well level returns, that's our incremental data when we make an incremental drilling decision, and I think everybody knows that we, internally when we grade ourselves and look at that repeatability, we're looking at fully burdened returns with all other costs that are associated with prosecuting a program..

And it's really meant to show just sensitivity to changes in price more than – it's a blended type curve that represents more than one type curve in the area..

The next question comes from Jeffrey Campbell with Tuohy Brothers..

Good morning..

Hi Jeff..

Thinking about the slide 12 discussion in a different way. Slide 16 says that Reeves County, Wood State wells are producing 28% better than parent wells and Pagoda State 16% above parent wells.

So how do we compare and contrast the slide 12 analysis that we've had a lot of discussion of with the outperformance in slide 16?.

Well, the answer to that is simple. The parent wells that are being referenced on slide 16 are older generation parent wells. And so, that is not the comparison that we meant to illustrate on slide 12. Had we compared infill wells to their actual parent wells, slide 12 would look much more optimistic.

But what we're really trying to illustrate on slide 12 is a completion evolution and not an analysis of infill to parent ratio on any particular project..

Okay. Well, and just to follow that up, I think, John, a number of times mentioned the spacing was also important to the discussion of slide 12. Just wondering do these – does the Wood State or the Pagoda State have perhaps less aggressive spacing than some of the – he was making some allusions to in slide 12.

Is there anything more optimal about spacing there?.

This is John, I think right now when we look at the Pagoda States and the Wood States, we feel very good about the Wood State results, very, very good about it from a spacing standpoint. We're still looking at the Pagoda States where we tested 16 wells per section and given that particular frac, the Gen 4 frac. We're watching those carefully.

I don't know if that is optimal from a rate of return standpoint, but again that's why we do it. That's why we go in and test those type of spacings. Early time, it looks good, but as we've often said, the proof is over 180-day or even longer and see what the wells ultimately perform at.

That's why, again, I'll reference that to show infill results of the same generation frac design that are coming in at that particular percentage, it's rather encouraging.

Now again, the proof will be when we go in and infill one of our next sections where we have that similar frac design right next to it and what does that show and that will certainly be some of the things we'll be doing here in the coming years for sure..

Okay. And I wasn't sure if I was going to ask this question, but you brought it up with Pagoda. So, I'm not to be nitpicky, but I noticed that the Pagoda State parent well outperformance dropped from 20% in the fourth quarter slides to 16% in the current slides.

And it's still a significant outperformance, but I wondered what your take was on it? Does that have maybe to do with the spacing you were talking about?.

Well, yes, I mean, I would again stress that in the case of Pagodas, we were testing limits there in terms of what that ultimate spacing would be. Now, I'm not here to tell you that if we had to do it again 16 will not be the obvious economic decision we would make.

But I would say that would be at the very high end for sure based on the performance of the wells so far and again based on our expectations, say of what a Generation 4 parent well would have looked like in that same section. But it's something we're watching very carefully..

And If I could sneak one, real quick one in I just wanted to ask you those two Avalon, Lea County wells that looked so strong.

First of all, is Triste Draw testing Avalon as well, or is that a different zone?.

Yeah. No, no same..

Okay.

And how does the spacing of those two Avalon wells that you announced in this quarter compare to the spacing on the Triste Draw?.

Yeah. No, the two wells that we announced, you would call parent wells, but they were not a spacing test as much as they were drilled on two different sections..

Okay..

The significance of those two wells is we were testing different stimulation design as well as a particular landing zone that we chose.

You know the devil's in the details, there's a lot – believe it or not there's quite a bit difference in those frac design between those two wells, from a standpoint of cluster spacing, and what we're trying to determine.

The outcome of those two wells as I said in my comments have given us a good confidence in terms of what type of fracture design now we want to deploy on the actual Triste Draw pilot, which we'll be stimulating here very soon..

Okay, great. Well I appreciate the color on that. Thank you..

The next question comes from David Heikkinen with Heikkinen..

Hey, guys, thanks for taking my question. I think your commentary on program being flexible is interesting.

And then you have the cadence of wells by quarter, with differentials and kind of when you bring wells online, is there any long-term value creation for deferring completions through these temporary blips or any major impact of rate of return if you were to choose to push things three months, six months, 12 months? And then the follow-on would be, when you think about the big program, it seems like that could cause a cascade in the whole program as well as opposed to just that the micro level of the individual well, just curious how you think about that decision-making process?.

Well, we – look, David, I'm going to answer it maybe a simpler answer than your question was asking for, but we're looking at managing our balance sheet, our cash flow and our capital throughout the year and we say, okay, what levers do we have to pull and that's the first thing we ask.

Often when we commission these projects, we have the rigs in locations and that drilling lever is pulled a year ago and so that ship has sailed. But to the extent that we wanted to adjust our capital down, for example, our completion is a lever we have to pull.

So we could indeed defer completions a few months or what have you, and have them roll into the next year, that's we've decided at this call that that's not what we're going to do, but an answer, a full disclosure of your question, I believe you're asking, that is a lever we have to pull.

Now what we would do in a case like that is we would look at the futures market and the basis differential, we would look at the economics of deferral, we would look at the differing rate of return between completing a well now and completing a well later and we would also look at our corporate model and how that over printed on our overall corporate growth and out year cash flow, so it's a fairly complex set of inter relationships.

We typically have found and we have typically made the decision that we want to complete a well and get the cash flow as soon as possible coming in the door. That's why Cimarex has never had a big DUC inventory and we've never had a strategic DUC operating philosophy, but that's how we'd look at that.

And so when we say we have flexibility, those are our levers. But as of right now, as steady as she goes, our program is our program..

No. You summarize it the same way I would have. That's helpful. Thank you..

The next question comes from Jamaal Dardar with Tudor, Pickering..

Good morning, everyone..

Good morning..

I had a quick question on the Culberson slide once again. You mentioned a few more developments this year. Just wanted to see if we can get some details on what spacing that would pursue, given the consistent performance we've seen on these tighter spacing tests? And then I just wanted to get some clarification on the shallower (59:39) sands.

If that was pervasive throughout the position, or is that more isolated on the western half?.

Yeah, this is John. I can tell you that we have made a decision on spacing on our next upper Wolfcamp development which – given the area where we're going, I'm pretty sure that one's going to be an eight wells section. But again, it is – it's not a one-size-fit-all-across all the acreage.

I think if you were to speak in general terms we feel very good at a base level of eight. And then leaning more toward higher counts, where the thickness and hydrocarbon place will allow us to do it. So, I'll just say that the next one certainly is at eight. We have not made a final decision on the one after that.

In fact, we have a review coming up on that one here soon to decide what we'll do there. As far as the opportunity shallower, at least the maps that I've seen the way we're approaching it, I couldn't sit here and say that that it's ubiquitous across all our acreage there.

I think it's most obvious to us and parts of the areas where we're testing it which is more on the western side and maybe the southern side.

But I will also tell you that as we gain experience in drilling in that interval and understanding, say, an X, Y performance then that in itself changes our maps and then we reassess it and more than likely might open up new areas.

It's just the way it always work for us that we go to where we think it's the most logical place and then from learnings, we're constantly surprised that what then opens up based on well results..

All right, thank you. That's helpful.

And then just quickly on the gas gathering systems you outlined on your slides, just want to get a sense of the volumes there? And also, at what point do these assets not become strategic to hold onto longer-term?.

Yeah, this is Joe. The Triple Crown is our biggest system and we're moving over 300 million a day off that line or off that system and Reeves's a bit behind that.

As far as the value of the systems, I think that ties into your question as do you keep them or do you not? Right now, what we see is the true value to those systems or they really do two things. They allow us to have market flexibility, which is certainly panned out here over the last quarter and are securing these takeaway arrangements.

And also gives us control of infrastructure where we can start, stop, slow down, move to the left, move to the right with our development over time. So, we see it as a valuable part of our development.

And as far as monetizing them or whatever, that is something that we constantly challenge ourselves with, but we always balance that with the benefits of owning the systems. Tom, I don't know if you want to..

Yeah. Listen, this is subject of active debate and I think it's a good question. In a perfect world, if we could get perfect service and multiple marketing outlets, we would probably choose not to own these assets.

But right now, we've got a really nimble responsive operation group that's seamless between producing the wells and managing our midstream assets. I think if you look at the Cimarex asset and you could see the level of detail that we see, you'd understand the operational efficiencies that owning these gathering systems gives us.

We own and operate our own Gas Lift System, Central Gas Lift. Our wells have high runtime, high compressor runtime, we flare very little volume and we can also adjust our capital on demand.

One of the challenges when dealing with the midstream partner and we talked on this call about commitments is they need some assurance ahead of time to make these capital commitments and they're going to want you to backstop them with long-term volumes. And so, we've made the decision at the present time to hang on to them.

But we re-evaluate that more frequently than our operating group would certainly like us to where it's a constant argument and it's a good question, but right now, we think there's a lot of benefit to our profitability with our current structure..

All right. Thank you. I appreciate that..

The next question comes from John Nelson with Goldman Sachs..

Good morning, and congratulations..

Hi, John..

Hi, Tom, and congratulations on the strong operational start to the year.

I guess just a follow-on to the firm sales agreements, I kind of curious, were these recently put in place and you're just now disclosing because of a kind of recent investor focus, or have these agreements that you've had – the marketing departments kind of had as normal course operations for quite some time?.

This is Joe. If I recall correctly, I think last call, I mentioned that we were looking into assurance of flow by trying to work sales arrangements with entities that did have firms. So, I thought I may have mentioned it back then. It certainly was a focus at that time. We saw it as the focus when we saw things tightening up.

But more importantly, at any one point in time, we would have a percentage of our take-in-kind volumes under anywhere from 6 months to a year-type-term sales agreements. In many cases, all we did was perpetuate those for longer period of time, and then add on to those existing agreements.

So hopefully that answers your question, but it was ongoing and it was finalized this quarter..

That's helpful. And I'm sure you can't go into specifics, but given this is a topic de jour now.

Can you talk about, given it seems like a decent amount of that was kind of contracted recently, did you find the terms to be that materially different as you kind of went through this more recent contracting, or were service midstream providers still pretty accommodative in getting you that firm sales capacity?.

And maybe it's by virtue of the nature that we've had a strong marketing team in place for many, many years with a number of relationships. We did not have problems getting the capacity in any way, shape or form. And the price basis upon which we obtained the contracts was not exorbitant.

In at least one particular case, we took on the firm transport that that purchaser was going to need to take on as part of our price. But surprisingly enough to me, I felt like if things are this tight, it was rather easy for us to line up these contracts..

I'll just say furthering Joe's point. We believe in relationships, we believe in good relationships with our long-term owners. We believe in good relationships with many of you on this call over time and that we want to be clear, credible and pretty transparent with you on our business and how we manage it.

And our marketing group, certainly, exhibits that with good long-term marketing arrangements. And so, I was very impressed with our marketing group's ability to extend those relationships.

And as Joe said, we feared that this was a herculean task and it's – they'd probably cringe for me to say they made it look easy, but it was really relationships that we've established over time so..

That's helpful. And then just as a separate question.

Have you guys seen any disproportionate widening of condensate realizations in the Permian, as the kind of overall basin dip has weakened?.

John, this is Mark. Yeah, I'm not aware of additional condensate widening. Are you talking about API type deducts, John or.....

Yeah, exactly..

Yeah, not that I'm aware of John. Our realizations in the first quarter were very strong as we continue to move through the year and we'll continue to monitor that. Obviously, all the basin price moves, there could be other ramifications. But through the first quarter, there's been a very strong realizations in the Permian.

We're just monitoring that Mid-Cush differential, obviously..

Yeah, if you look at our API gravity throughout the basin, certainly our widest is in Culberson, and we've got pretty good contracts there in place. So, we watch that, but so far so good..

Great. Congrats, again, on the quarter..

Thank you..

Thank you..

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

Well, I just want to thank, everybody, you've asked some great questions this morning as we always expect. We're having a good year. We look forward to continuing to execute as I said in my opening remarks. That's where the rubber meets the road. There is a lot of companies out there that have top-tier assets, Cimarex is, certainly, one.

And operational capability and consistency of execution is, certainly, a goal we set for ourselves and the goal we expect you to set for us. So, thank you for your good questions and look forward to our conversation next quarter..

This conference is now concluded. Thank you for attending today's presentation. You may now disconnect..