Cimarex Energy Co.
Q2 2018 Earnings Call Transcript

Published: 8 Aug 2018

[Operator:]

Good morning, and welcome to the Cimarex Energy Second Quarter 2018 Conference Call. All participants will be in listen-only mode. After today's presentation, there will be an opportunity to ask questions. Please note, today's event is being recorded. I would now like to turn the conference over to Karen Acierno, Director of Investor Relations. Please go ahead, ma'am.

[Karen Acierno:]

Thanks, Rocco. Good morning, everyone, and welcome to the Cimarex second quarter 2018 conference call. As I'm sure, you saw an updated presentation was posted to our website yesterday, we will be referring to this presentation during our call today. As a reminder, our discussion will contain forward-looking statements. A number of actions could cause actual results to differ materially from what we discuss. You should read our disclosures on forward-looking statements on our news release in our latest 10-Q for the three months ended June 30 which was filed yesterday and our 10-K and other filings for the risk factors associated with our business. As always, we will begin our 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, COO, will update you on operations, including production and well costs. Our CFO, Mark Burford, is here to help answer any questions. So that we can accommodate more of your questions during the hour we have allotted, we'd like to ask that you limit yourself to one question and one follow-up, and then feel free to get back in the queue if you like. With that, I'll turn it over to Tom.

[Thomas E. Jorden:]

Thank you, Karen, and thank you to all who are joining us on the call this morning. Cimarex had a very good second quarter. We invested $375 million in exploration and development activities. Our net daily average production was 211,000 barrels of oil equivalent per day, which was above the high-end of our guidance. We are on track to deliver solid production performance during the second half of 2018 with a strong production ramp that will result from our Q3 and Q4 well completions. On a pro forma basis, adjusting for the Ward County sale, we project total production to increase 16% year-over-year with oil production set to increase 23% year-over-year. Furthermore, we projected our Q4 2018 oil production will increase 33% to 43% over Q4 2017. We reported adjusted net income of $152 million for the second quarter or $1.59 per share. We brought 23 high-rate wells online during the quarter. We are continuing to deliver a very good year in terms of return on invested capital. Our Permian and Anadarko Basin programs are both performing well despite some strong headwinds. These include widened basis differentials and modest cost inflation. We will comment more about these later in the call. As most of you know, we manage Cimarex through a lens that focuses on return on invested capital. We do not manage around growth targets nor do we manage around commodity preference. We invest capital with fully burdened rate of return as the guiding hand. We incorporate projected basis differentials and projected inflation in our go-forward capital allocation decisions. We also compare our opportunities to invest in our business against capital return opportunities and other options, all with a focus on delivering strong value to our shareholders. We built the company with this discipline and it guides all of our decisions. During the quarter, we announced the sale of our Ward County assets for $570 million. We are on track to close August 31. We expect to reinvest these proceeds in our business over the next two or three years which we believe will maximize returns to Cimarex shareholders. We're not making any changes to our 2018 CapEx as previously announced. As we look ahead into 2019, we will time any acceleration in our Permian program so that flush production takes place in the second half of the year when Midland-Cushing differentials should narrow as new oil pipelines come online. Getting this right could have a significant impact on our cash flow and on our returns. We will also remain opportunistic for asset purchases or consolidation opportunities that make sense. We will keep you posted as our 2019 plans unfold. As always, our board will continue to debate our strategy and tactics as conditions change all with a view on delivering sustained shareholder value. Cimarex has established a long history of returns based management, conservative balance sheet management, transparency in our communication with the investment community and focus on value. Our business is performing well. We are seeing excellent returns across our portfolio. We have the economies of scale to deliver increasing capital efficiency and maintain an industry-leading cost structure. Furthermore, we have great confidence that our assets and organization makes these results highly repeatable. We are well positioned for the environment ahead with decades of high quality inventory. We can compete with the best. As Joe will describe, we have seen some modest cost inflation during the year. Although it is less than we had forecast at beginning of the year, it has our attention. We are focusing on lowering our cost structure across the board. This includes drilling costs, completion costs, facilities costs, lease operating costs and the infrastructure costs associated with gathering and saltwater disposal. As always, Cimarex reports actual costs not target costs. During the call today, John Lambuth and Joe Albi will update you on some projects that are in various stages of completion. We are flowing back a number of development projects that are meaningful to us in making future development decisions. These include our Hallertau Wolfcamp development in Eddy County, New Mexico; our Snowshoe project in Reeves County, Texas; our Animal Kingdom development in Culberson County, Texas; our Shelly Woodford Shale development in Canadian County, Oklahoma; and our Steve O Meramec development in Kingfisher County, Oklahoma. In closing, what can you expect from Cimarex during the remainder of the year? We will continue to focus on well improvement, overall cost reduction, and optimal development design. More and more of our capital program will shift to multi-well, multi-pad development projects. We do not subscribe to any single philosophy on optimum development. Optimal development is a function of the investment capital cycle, reservoir interference, and facility design requirements. There is an inherent tension between optimizing rate of return and optimizing net present value when choosing the right project size. The right answer is partially dependent upon the quality of other opportunities within a portfolio. We don't subscribe to a one-size-fits-all approach. On these and all projects, we measure ourselves in a transparent, brutally objective manner. We occasionally stumble, but we adapt and innovate and improve. We're committed to exercise sound financial discipline and to be responsible to our shareholders. This includes a commitment to deliver top-tier fully burdened returns, maintain a strong balance sheet, and grow our dividend over time. We are also committed to clear credible communication on calls like this one. And, yes, we still explore at Cimarex. We are constantly on the hunt for assets that can augment our top-tier portfolio either in our existing basins or beyond. The bar is high, but we are continuously looking for new opportunities and bolt-on acquisitions. Continuous improvement is alive and well at Cimarex. Our goal is continuous, disciplined, profitable growth. With that, I will turn the call over to John for additional detail.

[John Lambuth:]

Thanks, Tom. During the second quarter, Cimarex invested $375 million in exploration and development activities, of which $322 million was invested in the drilling and completion of new wells. Year-to-date, 61% of our drilling and completion capital was spent in the Permian region and 39% in the Mid-Continent. We brought 23 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. We currently have six completion crews working across our acreage. Now on to some specifics about each region, in the Permian, we brought 13 net wells online during the second quarter including 6 wells in the Hallertau project, an Upper Wolfcamp spacing test in Lea County, New Mexico. These six 5,000-foot wells achieved a 30-day peak average rate of 1,295 barrels of oil equivalent per day, of which 783 was barrels of oil per day. This spacing pilot was designed to test 12 wells per section in the Wolfcamp A, with three of the wells landed in the upper most part of the A, an interval known as the Y sand, with additional two wells which were landed 50 feet below these wells in the Upper A shale, and the sixth well which was landed 225 feet directly below one of the Y sand wells. I will refer you to slide 39 of our slide deck for a wine rack view of this development. While we think 12 wells is the right number of wells for this section, after 90 days of production, we have observed a decline in the performance related to the five wells landed in the upper most part of the interval. Analysis of the production data show that the vertical separation between these two benches was too small, thus causing more rate-sharing than anticipated. The sixth well in this pilot is meeting our pre-drill expectations which, in short, corroborates the conclusion that 12 wells per section is optimal, given sufficient vertical spacing between the benches. Also, on the Wolfcamp section, we have two spacing tests in various stages of completion. In Culberson County, the Animal Kingdom infill development, which consists of eight 10,000-foot laterals in the Lower Wolfcamp, will be finished with their frac operations by the end of August. These wells are testing the equivalent of 14 wells per section by both decreasing the spacing between wells and the bench, plus adding additional landing zone in the top part of a Lower Wolfcamp, a zone that we used to refer to as the Wolfcamp C. These wells are planned to be on production by mid-September. Another important test in the Upper Wolfcamp located in Reeves County is the Snowshoe pilot where the first pad of three 10,000-foot wells are now producing. And the second pad with remaining five wells will be on production by mid-August. You may recall these wells are testing the equivalent of 18 wells per section. Stay tuned for results on these development projects later this year. Now, onto the Mid-Continent, completion operations are finished on the Meramec Steve O development project which consists of six 10,000-foot laterals stacked/staggered in two benches. This pilot, which is currently flowing back, is testing the equivalent of eight wells per section spacing. We have now also begun drilling on three additional Meramec development projects across our acreage position with first production not expected from these projects until early 2019. Another interesting well brought on production this quarter in the 14 North-10 West area was the Gresham Com 1H-1819X. This well is directly south of the recently announced Mike Com well and had an initial 30-day rate of 5,813 barrels of oil equivalent per day, of which 8% was oil, 31% NGL, and 61% gas. This well is a further confirmation of the strong production rates capabilities of the Meramec section across the 14 North-10 West area, and reinforces the kind of high after-tax rate of return development opportunities within the Meramec and Woodford section that Cimarex operates and the 14 North-10 West position. In the Woodford Lone Rock area, completion operations are finished with initial flow back underway on the Shelly spacing pilot. Furthermore, a second Lone Rock development project called JD Hoppinscotch is also finished with its completion and has initial flowback expected to begin by the middle of this month. With that, I'll turn the call over to Joe Albi.

[Joseph R. Albi:]

Well, thank you, John, and thank you all for joining our call today. I'll give you an update on the usual items, our second quarter production, our revised full-year production guidance, and then I'll finish up with a few comments on Permian takeaway as well as Mid-Continent takeaway, LOE, and then service costs. With reported net daily equivalent production of 211,000 BOEs per day, we had another solid quarter in Q2. The mark put us above the upper-end of our guidance range of 200,000 to 209,000 BOE per day and, once again, set a new record for the company. With our Q2 oil volume coming in about as we had internally modeled, our guidance beat was driven primarily by higher than forecasted NGL volumes. Stronger Permian NGL prices boosted the increase and drove our total company NGL production to a record 59,900 barrels per day, that's a 16% increase over first quarter. And as a result, our equivalent production ended up 3% higher than Q1 2018 and 10% over where we were in Q2 2017. We had limited completion activity during the second quarter. Our Q2 oil volumes came in at 61,651 barrels a day, that was on track with where our internal projections were pointing, and up 7% over Q2 17. We continue to see nice year-over-year production gains in both Permian and the Mid-Continent with our Q2 Permian equivalent posting of 121,700 BOEs per day, up 13% over Q2 2017, and our Mid-Continent volume of 88,900 BOE per day, up 5% from a year ago. Higher than projected NGL recoveries drove our reported Q2 Permian NGL volume to a record 32,865 barrels a day, that's up 33% from first quarter and 31% from Q2 2017. With the back end loading of our well completions this year, our Q2 Permian oil volume of 48,800 barrels per day was down just slightly from Q1 but was up 6% over Q2 2017. And likewise, our Q2 Mid-Continent oil volume of 12,500 barrels a day was down about 2,700 barrels a day from Q1, but again up 5% from our second quarter posting last year. So, with Q2 in the books, some slight shifting in the timing of our anticipated completion activity, and revised NGL recovery projections, we've increased the midpoint and tightened the band of our full-year guidance projection to 214,000 to 221,000 BOEs per day, and that's despite the sale of our Ward County properties, which, Tom alluded to, is scheduled to close at the end of this month. We have seven operated and three non-operated multi-well pilot projects scheduled to come online in late Q3 and into Q4. 70% of our full-year completion activity is planned for the second half of the year. And as such, we're projecting a total of 86 net completions in the second half of the year as compared to 38 in the first half of the year, with 49 of the remaining 86 net wells forecasted to come on in Q3. And with that, we're projecting the same steep production ramp from September and into December that we described last call. To put the completion ramp into perspective, we're projecting more net completions in August and September than we completed in the entire first six months of the year. And with the ramp, we're estimating our Q4 oil volumes of 75,000 to 80,000 barrels a day to be up 33% to over 40% based on a sale adjusted Q4 2017 oil volume of 56,500 barrels a day. With our current forecast, we're guiding Q3 net equivalent volumes to land in the range of 206,000 to 215,000 BOE per day, with our forecasted late year production ramp resulting in a full-year guidance range of 214,000 to 221,000 BOE per day. That's a 14% to 18% increase over 2017 after adjusting for the sale of our Ward County assets. A few update words on Permian takeaway. Our marketing team continued their efforts during the second quarter to ensure our oil, gas, and NGLs move out of the Permian Basin. On the gas side, we've now agreed to terms for the sale of 98% of our projected Permian residue gas volumes through December of 2019, while extending sale terms for 84% of our projected volumes through the first quarter of 2020. As we mentioned last call, our NGL production is linked to numerous processing facilities across the basin and with whom we've either purchaser-backed, firm or established long-term sale arrangements in place. And on the oil side, 70% of our Permian oil is on pipe with strategic partnerships and oil agreements in place to ensure flow through 2019 and beyond. That said, we continue to evaluate all options to ensure long-term flow of all products out of the basin. And although Permian takeaway is a strong focal point of the market, we remain equally concentrated on the Mid-Continent, evaluating all means to ensure near- to long-term takeaway for our forecasted Mid-Continent volumes. As we've discussed before, our goal in both the Permian and 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, Ann Arr (00

[Unknown Speaker:]

Thank you. We will now begin the question-and-answer session. Today's first question comes from Drew Venker of Morgan Stanley. Please go ahead.

[Drew Venker:]

Good morning, everyone. I was hoping...

[Thomas E. Jorden:]

Hi. Drew.

[Drew Venker:]

... if you could speak to the key drivers of the production volumes in the second half with that big ramp in completions and could we potentially see peak production from that big ramp in completions in first quarter and not fully see it later this year?

[Joseph R. Albi:]

Well, Drew, I'll answer that question. What we're going to end up seeing is the ramp starting in September and really starting to materialize itself as you get into November and December. As far as what we're talking about for 2018, we're still going to be increasing according to our modeling our equivalent oil production as we enter into December.

[Drew Venker:]

Okay.

[Joseph R. Albi:]

These wells come on, they take a little bit of time to clean up and they're multi-well pads. So, they're all coming on at once and they're all cleaning up at once, and they're all going to ramp at once.

[Drew Venker:]

And are you operating the number of frac spreads you need achieve these completions already?

[Joseph R. Albi:]

Yes. We've got five work in the Permian and one working in the Mid-Continent, and we bumped that about a month and a half ago just to accommodate these completion forecasts.

[John Lambuth:]

Drew, this is John Lambuth. To add a little more to what Joe just said. Of all of those pads, there's really only one major development left to be actually completed which is Triste Draw. All the others, for the most part, have been completed or just about done with completion with a number of them already were drilled out and starting to flow back. So, operationally, everything's gone very well from the standpoint of the timing and getting these wells on as we expected to come on. So, that's why I think we're fairly confident in the projections we put forward.

[Drew Venker:]

Appreciate that additional detail. Just one more on operations as a follow up. From what you've seen so far this year, can you speak to which areas have been outperforming your expectations and which haven't performed as well?

[John Lambuth:]

This is John. There are a number of places. Clearly, the Culberson, especially as we do more drilling on the western side, we're seeing very, very good results. We've talked about some of those wells in the past like the Charismatic, the American Pharoah. We have a number of other ones that are flowing back right now that, again, given sufficient flow back time, we will then elaborate upon. But Culberson itself is starting to step out as an area that – especially that Western side that we're getting very excited about. But I would also say up in Lea County, Lea-Eddy County particularly, but Lea, we've already talked about a number of our Avalon wells, earlier in the year the Coriander, Thyme. We have a number of additional Avalon wells that we're drilling. And then the Wolfcamp, we're just now starting to bring on some of our 2-mile Wolfcamps in Red Hills. And just frankly based on some offset operator wells and our expectations, we're very excited about what we'll see coming out of there. And then, again, you flip up into Anadarko. I made mention of the latest well in our 14-10 area, the Gresham well. I understand that that well has quite a bit of gas production. Not as much oil, but one must also take into consideration, that is the westernmost edge of our entire 14-10 block and that we've already kind of now bracketed that interval that, as we move to the East, we're going to see higher and higher yields and that just leads to better and better returns. And the significance of that well just shows that we're still seeing great productivity across all of that acreage. So, we're pretty excited about that area from a future development standpoint. So, that's just a few of the areas that I will highlight. There's many more, but those are a few.

[Thomas E. Jorden:]

Yeah. I just want to add to that. As all of you know, we don't manage Cimarex around quarterly numbers. We manage Cimarex around long-term investment and long-term quality returns fully burdened. And so, as we look ahead, although John can't talk about them because we don't have enough production, we've been testing a number of landing zones throughout our portfolio and it's got our attention. We have some really interesting results, and we're in a process of relooking at our capital program going forward. We'll adapt and emphasize some things that are working really well. We've got a few things across our portfolio that we're flowing back that – I'll just say this – really have our attention. So, it's given John a little heartaches. I'm in his office every morning saying, all right, how do we rejigger our future capital allocation to take advantage of these learnings? So, we're always adapting, always innovating. And John mentioned that Gresham well. That 14-10 area is a phenomenal project for us because not only does it have very high rate of return Woodford. But now it looks like we've got a pretty lights-out outstanding Meramec sitting right on top of it. So we're pretty upbeat about the prospects for our investment portfolio going forward.

[Drew Venker:]

Thanks for the color.

[Operator:]

And our next question today comes from Arun Jayaram of JPMorgan. Please go ahead.

[Arun Jayaram:]

Yeah. Good morning. Tom, I wanted to see if you could maybe elaborate on your commentary on 2019 and plans to maybe time some of the tills with when the basis differentials improve. So I was wondering how that could – how are you thinking about rig activity and your completion cadence as you articulate that view?

[Thomas E. Jorden:]

Well, that's a great follow on to my last statement, Arun. As we look at 2019, we are looking at maximizing our returns. Now that hopefully doesn't come as a surprise to any of our listeners. We don't manage our own production growth. I mean, production growth is a great consequence of a well-managed return portfolio. And so we're looking at just allocating capital around returns and to the extent that that has an ongoing bias for some of our Delaware projects, the timing of these things is something we're going to look at to try to bring that production on in the second half of the year. I mean, I know that maybe that's not what people want to hear, but it's the truth, that when we look at these basis differentials that are pretty severe on the oil side in the Permian Basin, the pipelines begin to come online in the second quarter, more and more of them come online in the third quarter, and you can look at the futures curve on that Mid-Cush differential and the market sees what we see, it will collapse. And so we'd like to time flush production in our Permian program. We take advantage of that flush cash flow with new wells. I mean, it's not – there's not really any major announcement here on redoing our capital program, it's just we always have to manage timing as well as capital allocation and the Permian has a rather unique opportunity around timing.

[Arun Jayaram:]

Right. And so, perhaps the till schedule could kind of look like 2018 where it's more back-end loaded.

[Thomas E. Jorden:]

Well, we haven't really – I mean, I don't know the answer to that as we sit here right now because we have two basins to allocate around. So, I'm just – my comments are specific to Permian.

[Arun Jayaram:]

Okay. Great, Tom. And my follow up is just what your thoughts, Tom, on utilizing the proceeds from the Ward County sale. I think that transaction closes later this month, early in September, but just thoughts on utilizing the proceeds from that divestiture?

[Thomas E. Jorden:]

Well, as I said in my opening remarks, our board has really put a lot of energy into that. And we looked at all of our options and look at what does it mean to a healthier, more profitable Cimarex which benefits our long-term owners. And exploring all of our options, the place where we've currently landed is reinvesting that cash over the next several years into our core business. And we're pretty confident that with the returns we're generating and the repeatability we're seeing that that's the best answer for the Cimarex shareholder. Now, I'm going to finish where I started and that's that this is constantly debated by our board. They're actively engaged in this topic. And as I've sat around the table with our board and listened to the debate around this, I'm pretty pleased with the open mindedness of our board and the focus on shareholder value. We'll grow our dividend over time. We're pleased and dedicated to a growing dividend. But right now, we're sufficiently confident in our core business performance that that's where we think the proceeds are best invested over the next few years.

[Arun Jayaram:]

Thanks, Tom.

[Operator:]

And our next question today comes from Mike Scialla of Stifel. Please go ahead.

[Michael Stephen Scialla:]

Hey. Good morning, guys. Tom, you mentioned in your opening remarks about potential bolt-ons. Just want to see, in general terms, how you see the landscape? We saw a lot of private companies bought out in 2017. How do you see the landscape now versus then? And how does the deal flow compare between your two core basins?

[Thomas E. Jorden:]

Well, the landscape is active. I think although there have been some large transactions announced, I don't know that we've seen the kind of chatter that we've seen in the marketplace the last few years, but we see some opportunities. I mean, we're – John can comment on it, but we're digging into some things. And in both of our basins and beyond, we've got a lot of energy applied to this. It's really a natural extension of our confidence in the returns we're generating and the repeatability. There are some things that are at or near some of our projects that we're looking at. Now, these things are always a long shot. But, boy, you have to be in the game in order to win. John, you want to talk about that?

[John Lambuth:]

Yeah. I think especially in light of – and Tom mentioned this earlier, we're constantly not just looking to develop our established zones but look for other upside within our current positions. And when we do that, we take that risk. We see that that leads to additional drilling opportunities, then we immediately ask ourselves, well, is that prevalent, or is that existing on adjoining positions that maybe we could go in and then make a competitive offer to try to bring that acreage in. It's not easy. I mean, still to this day, obviously, valuations are still very high. But if we think we have a potential opportunity to maybe enhance someone's acreage position more so than what another operator has done, then, yeah, hopefully, we can make a competitive bid and bring some of those in. But it's something we're always looking at. And that's just part of our business. We have to constantly look for those bolt-on positions.

[Thomas E. Jorden:]

One of the things I mentioned in prior call is that our initial motivation when we put Ward on the market was because we were looking at an opportunity and we were quite interested in it. And we were not successful in acquiring that opportunity. But one thing I will say on behalf of the executive team, we are deeply committed to, is that although we've decided to sell Ward and we're quite pleased with the price that we're getting for it, those assets will be – that cash will be deployed in a manner that is much more productive to us in our portfolio than those assets currently are, and we're committed to that.

[Michael Stephen Scialla:]

Right. Very good. I wanted to ask, too, about the Hallertau – I hope I can pronounce it. I don't think I can – but that spacing unit. It looks to me like – if I'm doing the math right – that you're really – you said you're testing 12 wells per section. But if all three of those zones would have worked, wouldn't that imply more than 12 wells per section? And I guess, what was the concept behind just 50-feet of vertical spacing there? Would you – were you're looking to see if you could fit three layers within the Wolfcamp A or, I guess, just trying to understand that better?

[John Lambuth:]

Well, yes. Yes, we were. I mean, this was an instance where going in, as I said, we were pretty confident that we had sufficient thickness and resource in place that we could easily develop that section and all of our other high prospective section around there at 12 wells a section. And yet we also had some information that I would say maybe there's enough resource in place to where you could bring those wells closer vertically. And if you had a very successful outcome, then indeed that would add an additional bench of drilling. What we have observed is that from those wells landing in the upper part, which is the 50-foot distance spacing, that we are seeing greater acceleration between the wells and what our pre-drill forecast would've expected. And so what's happening? Simply, we probably have our resource in place wrong. This isn't something that's easy to do. We worked very hard at it. We take whatever data we have to come up with that calculation from that. We then go forward and we test. I will point out that we kind of knew that going in here. I will also point out that's why we tested this particular section. These are only 5,000-foot laterals. It's not 2-miles. Thus, we thought from a capital investment standpoint, this was a worthy test to do. If indeed these wells perform better, then that would have really meant quite a bit of upside for us on the rest of our acreage where we do have 2-mile opportunities. So, we will do these types of test from time to time. And we learn a lot from the Hallertau we have. We, again with great confidence from those wells, feel very good about going forward with 12 wells per section throughout the area there in that Lea, Eddy County line area. And that's how we'll plan to go forward from now on, at least for the time being.

[Thomas E. Jorden:]

One of the motivations here, in hindsight, it may look differently than it did to us in planning this, but I will tell you that when we configured this project, we had recently observed from some Anadarko Basin work that suddenly stacked/staggering had a tremendous impact on productivity. And that we didn't need to put much vertical separation in order to get take advantage of that stacked/staggering. So, Hallertau was our attempt to try it in the Wolfcamp. Now, we knew it was risky. We knew that it's not just a layup transfer from an Anadarko Basin where you have a very different stress profile carrying it to the Delaware Basin. But based on our experience in Anadarko, we said, you know what, this is an experiment worth taking. And we learned a tremendous amount. And we learned that, you know what, it doesn't. That they were too close vertically. But if you don't try things you don't make progress.

[Michael Stephen Scialla:]

Right. But are you comfortable with the 12 wells per section which is (00

[John Lambuth:]

Absolutely. I mean, absolutely at 12 given similar thickness as the Hallertau section. Yes, we're very confident.

[Michael Stephen Scialla:]

Great. Thank you.

[Operator:]

And our next question today comes from Neal Dingmann of SunTrust. Please go ahead.

[Neal D. Dingmann:]

Morning, guys. My question I think is for John. John, when I'm looking on a couple of areas here either around the Tim Tam, here in Culberson or a couple of your plays in Reeves. I mean I'll just pick a couple, like Snowshoe or Dixieland. Your thought – on Pagoda State, you've got that now all the way up to 16 wells per section. And then I think if I recall that somewhere in Animal Kingdom you're closer to 14. Is there even more upside there? I guess my sort of long-winded question is, is there more upside in those areas to even downspace more? How do you think about sort of the – is it more like a cube development or more just on the spacing?

[John Lambuth:]

Well, I always hope there's upside. We always are asking ourselves how can we most effectively drain the total hydrocarbon system there. But specifically to your question as a follow up to Pagoda, that is why we've done the Snowshoe. The Snowshoe is at 18-wells a section. We took the Pagoda learnings and from that we actually went and added a third layer so we have three benches, and then we widened the spacing between individual wells. That was a direct outcome from Pagoda learnings. And I believe we do have a wine rack showing that particular development project. So, we are from Pagoda going to test even tighter with the Snowshoe. Likewise, when you go over to Culberson in the Lower Wolfcamp from the Tim Tam and the excellent results we had there, we became convinced that there was more resource there than just those wells with access. And that led us then to the Animal Kingdom design whereas again you pointed out we're tighter, we added an extra bench. And those are the two very significant pilots that, as I mentioned in my opening remarks, one of them is already flowing back, and the Animal Kingdom here will be coming on here by next month. We will be watching those projects very, very carefully. And like all of these development projects, we won't really high-five just after 30 days of production. We'll need 90 days. We have a lot of, I would just say, science in place to measure these wells, to assess how they are performing, and we'll feel pretty good I think after 90 days as to whether or not that type of tighter spacing is going to be kind of the next norm for us and, more importantly, if we could go even tighter, again based on what we see coming out of those wells.

[Neal D. Dingmann:]

Does that change as you go more into that lower – you're talking about over in the Animal Kingdom, some of those lower zones. Does that play into sort of how much the gassy nature or oily nature depending on how you start to target in those areas of the overall company, or is it (00

[John Lambuth:]

Well, the hydrocarbon type definitely factors into our decision-making on spacing. I would say first and foremost, just overall thickness of the hydrocarbon interval itself has the biggest effect in terms of how much is in place and how many wells do we think we required to drain it. But we definitely take into account whether were gas in the reservoir, oil in the reservoir, the initial pressure that we expect from those wells, all of that factors into ultimately how many wells per section we think we can put in there to both. And again, it's something we talk a lot about. It's that tradeoff of maximizing the overall return on that project while also achieving the highest PV possible. And again, we think in the Snowshoe and Animal Kingdom, we think those are designed, we feel, very fit for purpose for both those sections. Now, the proof again will be in the performance of the wells as they come on.

[Neal D. Dingmann:]

And last, if I could, Tom, just one for you. When you think about flow assurance, it's a pretty broad definition. Do you assume some people just think it's firm sales, others say it has to be firm transportation? If you think about having certainly what you call a sort of guarantee flow assurance, how do you think about that overall? Thank you.

[Thomas E. Jorden:]

Well, I don't know that I can give you a global answer, but you're asking Cimarex, I'll give you a Cimarex answer. Our flow assurance is we have contracts for sales with people that have flow and have themselves firm transport. It's also long-term marketing arrangements, and we're in a relationship business. So, we have a high degree of confidence that when we tell you that our product will flow, it will flow to market. As Joe has told you, these sales agreements are at index price, and although we do have hedges in place that mitigate a little bit of that sting, we are exposed to these differentials. We've talked about this in the past. We have chosen at this time, we re-evaluate this constantly, but at this time, we have chosen not to enter into these long-term firm sales contracts. We know these differentials will collapse and we think that we will be grateful at that point that we didn't enter into these long-term commitments. But even so, that's not a theology. We debate this constantly. But we are very confident that we have marketing arrangements and our product will flow to market.

[Neal D. Dingmann:]

Great details. Thanks, Tom. Thanks, John.

[Operator:]

And our next question comes from John Nelson of Goldman Sachs. Please go ahead.

[John Nelson:]

Good morning and thank you for taking my questions. There's been a real investor pivot to E&P spending within cash flow the last few years. Given your rate of return focus, what most – and you even just commented, expect to be a transitory weakness in Permian oil differentials and the substantial amount of cash you're going to have on your balance sheet post the Ward County sale, how are you thinking about balancing cash flow in 2019?

[Thomas E. Jorden:]

Well, we haven't obviously set out 2019 plans, but I think that the way we're thinking about it is that, as we look into 2019, we have a strong bias to be at or near cash flow. I don't think you'd see a huge outspend from us in 2019. Mark, do you want to touch on that one?

[G. Mark Burford:]

Yeah, John. I think even this year so far than the (00

[John Nelson:]

I guess, just a push on that. If your margins are going to be squeezed for kind of this transitory phenomenon, it would feel like your rate of return focus should kind of push you to look through that as opposed to ramping down, call it, kind of normalized activity in 2019. Is it just the confidence on pipelines coming on or wanting to be closer to spending within cash flow that's kind of important to you or I'm not sure we kind of see where I'm going with the question. But it seems like you should be – given your rate of return focus, Cimarex I would think would be more willing to kind of look through 2019 weakness.

[Thomas E. Jorden:]

Well, we do look through 2019 weakness. And we see this as a near-term phenomenon and, John, again, we haven't formalized nor announced our 2019 plans. But there's a fair amount of whiplash I'm getting here and that we hear a lot of competing voices out there. And we just focus on investing in our business and focusing on the returns. One thing I will tell you is that when we look at this widening differential, and I said in my opening remarks, we bake those differentials into all of our returns, so that we're not surprised by them and they're treated upfront and accounted for in my investment decisions. But I'll just finish, John, by saying, I don't think we'd be in a massive outspend in 2019. I think our bias is to be a little more tempered. But we haven't really made those decisions yet.

[John Nelson:]

No, that's helpful. And my second question I guess just on the 2018 capital spending guide. I just wanted to check that we still kind of feel good about that guidance range for the year. You noted that 70% of the completions are still going to happen in the back half. We've used 40% to 45% of the full-year budget in the front half. I know it's never kind of that simple with regards to spending outlays. But do we still feel kind of comfortable with the range for the year or could there be kind of more towards the top end or an upward bias?

[G. Mark Burford:]

John, at this point, the way we're modeling it, to tell you we do see that that range, we're very comfortable with that range in midpoint or even below the midpoint of that range. So, that's the way we see it at this point, John, so.

[John Nelson:]

Great. I'll let someone else hop on. Thanks.

[Thomas E. Jorden:]

Thank you.

[Operator:]

And today's next question comes from Paul Grigel of Macquarie. Please go ahead. Paul Grigel - Macquarie Capital (USA), Inc. Hi. Good morning. One quick maybe more theoretical question. As you guys kind of take the Ward sale proceeds, that was obviously at a fairly low cost basis historically and you roll that forward. You've previously commented about your operating groups needing to kind of bear the burden of any acquisition on a cost. If you roll those proceeds into another acquisition, does the operating group got to keep that lower cost basis is kind of an acreage swap, if you will, or is it reset at the higher cost of entry?

[Thomas E. Jorden:]

Well, the way we account for our dollars and the way our compensation systems for operating groups are configured, they would bear the incremental cost of the higher entry point. I mean, that's just the way we view the world. Now, Ward is a case in point as we've said. Although Ward are good assets, I really am highly confident that they're going to prove out, over time, to be very good assets as they have been for us. But they weren't competing for capital in our portfolio. And therefore, in a valuation standpoint when you look at our internal value for the discounted value of that future drilling opportunity award because we were under-investing in it that discounted value is suffering. And so, if we were to take those proceeds and roll them into a different asset, it would be because we were going to be investing aggressively in that asset. And I think you'd find that on a discounted value-to-discounted value comparison, the new assets would be much more valuable at Cimarex. And the way we count our money, we would fully burden it with the purchase price of a new asset. Now, I – please don't take this telegraph – me telegraphing it, oh, my goodness. There's something Cimarex is imminently going to buy with that money. But I'm just answering your question as asked. Paul Grigel - Macquarie Capital (USA), Inc. No. I appreciate that and understood. I guess as a follow-up in a similar vein, one of the elements you guys added to your proxy statement this year was examining shareholder returns via dividends, buybacks, various different metrics as a plan that was being internally looked at. Is there any update that you guys can provide just on where you're at? Again, maybe even a little more theoretically, but also with a good cash position there.

[G. Mark Burford:]

Yeah, Paul. This is Mark. We are continuing with that. As Tom mentioned in his opening remarks that we have an active discussion with our board regularly on that kind of a subject on the shareholder returns, dividend pace, and we'll continue to have those kind of discussions. And certainly, as we raise our dividend this year is an example of how we are trying to return more to shareholders, the board is definitely supportive of having a pattern of growing dividend over time as our cash flows and production grow. And again, as we look at our cash balances and looking at options to invest that cash balance organically in our business or other opportunities and return to shareholders, all continue to be debated that, as Tom said at this point in time, our asset investment is our principal focus at this point in time. We see that as being a superior for our long-term shareholders.

[Thomas E. Jorden:]

Of those three things you mentioned, dividends, buybacks, investing in our business, I'd like to put dividends aside because dividends are a separate case for us. We like paying a dividend. It enforces a discipline on us as a management team. It's a constant reminder that we work for our owners and returning that cash to our owners on a sustainable and growing manner is something that is healthy, and it affects our behavior every single day. Now, the other two in comparing, we're going to look at the metrics based on the long-term value as an incremental place to put cash. And obviously, proof is in the pudding. What I said in my opening remarks is our board under careful consideration has landed on our businesses as the best option from the analysis. Paul Grigel - Macquarie Capital (USA), Inc. No, that's good color. Thanks, Tom. Thanks, Mark.

[Operator:]

And our next question today comes from Doug Leggate of Bank of America Merrill Lynch. Please go ahead.

[Doug Leggate:]

Thanks. Good morning, everybody. Gents, I realize that you haven't put the 2019 plan together as such, as yet. But obviously this year has been quite lumpy by way of completions. And I think as you pointed out, the next month or two is going to be pretty active. I just wonder given that we're coming up in the middle of August I guess, can you give us a confidence level in your execution on getting those 80-plus completions done and maybe some idea how the cadence looks going through 2019 and maybe an exit rate going into 2019 particularly on oil production? And I've got a follow up, please.

[Joseph R. Albi:]

Yeah. This is Joe. I'll just try and answer that from a net well count standpoint. Operationally, as I think John mentioned earlier, we are set up to have all these completions come into play. For the most part – most of all the pilots have been drilled. It's just a matter of aligning the completion operations then with five – just pick the Permian with five crews to get the wells completed. That said, you could always run into an operational difficulty along the way. But all of that said, if I look at a profile without giving specifics of net wells per month that would be completed, the bulk of our completions are forecasted to transpire between August and October. And then for this year's program kind of taper off as you go into December. So, if you were to say, okay, does that give you any leeway, are we projecting a huge completion ramp into December, I'm going to tell you, no, it's happening in late Q3 and early Q4 and then, really, this is no different than we've been talking about all year. And to-date, our cadence has been relatively tight with what we've projected.

[Doug Leggate:]

So, as you look into – just to clarify, as you go into 2019, do we get the flat spots again or is the cadence more ratable as we go into that next year's program?

[Joseph R. Albi:]

Well, again, we haven't put our 2019 plan together. So, it's going to be hard to answer that specifically. But the fact of the matter is, if you have a program that consists of single wells and multi-wells, you will always have some degree of increases and decreases rather rapidly as compared to a single well associated with multi-wells coming online. And that's we're looking at this stuff by month or by quarter, in some respects, from our opinion, we look at this as more long-term than near-term. And it's all focused on rate of return and, heck, all it takes is a 10-well program that we forecast to come on on October 15. And if it came on on November 1, it's going to have a big impact on the third quarter and have a heavy impact on the fourth quarter. But the (00

[Doug Leggate:]

I guess my – it's really more. So, I don't want to belabor the point, but I guess there's a lot of focus obviously on the oil mix as you go forward. So, you're really just going to trying to get some kind of a handle as to how you see the exit rate going into 2019 with the cadence that you've laid out. So, that was the last kind of part of my question. I don't know if you care to opine on that.

[Joseph R. Albi:]

Yeah. The second quarter had – we saw higher than expected NGL recoveries. Walking into the quarter, we put together our guidance knowing that there was a likelihood of higher recoveries in the Permian but just had initial information which to base our forecasts. And as such, we put together an increased but conservative forecast for NGLs. And as the quarter then later transpired primarily because of some nice price strengthening in the Permian, we saw higher than anticipated recoveries coming out of our Permian program. The way we've modeled our current forecast, we're assuming those recoveries continued through the end of the year. And so, to the extent, what you're seeing in Q2 as far as NGL mix and oil mix and gas mix is concerned, assuming that prices stay where they are and assuming that recovery does transpire because we don't always get to pick, either our processor does or we do. And if we do, it's always an economic decision. Those could vary a bit. But as far as the ingredient built into our guidance, it's continuation of the Permian recoveries through the end of the year.

[Doug Leggate:]

Great so far. I realize we're at the top of the hour, so I'll jump off. Thanks, guys.

[Joseph R. Albi:]

Thank you.

[Operator:]

And, ladies and gentlemen, as we've reached the top of the hour, this concludes the question-and-answer session. I'd like to turn the conference back over to the management team for any closing remarks.

[Thomas E. Jorden:]

Yeah. I want to thank everybody for joining us today. I just reiterate our program is on track. We're very pleased with the returns we're delivering. And at the begin and end of the day, return on invested capital honestly and fully burdened is what we're all about. And we look forward to delivering what we have promised in this call today. So, thank you very much for your interest.

[Operator:]

And thank you, sir. Today's conference has now concluded and we thank you all for attending today's presentation. You may now disconnect your lines, and have a wonderful day.