Alpha Metallurgical Resources Inc (CTRA) — Q2 2016 Transcript

Good morning. Thanks, everyone, for joining us this morning. Yesterday afternoon, an updated presentation was posted to our website. 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 in our latest 10-K, and other filings, and news releases for the risk factors associated with our business. We know it's a busy week, so we're going to try and keep our prepared remarks short today, so that we have plenty of time for Q&A. We'll begin with an overview from our CEO, Tom Jorden; followed by an update on drilling activities and results from John Lambuth, EVP of Exploration; and then Joe Albi, our COO, will update you on our operations, including production and well costs. Our CFO Mark Burford is also here to help answer any questions. And so, that we can accommodate everybody's questions during the hour that we have allotted for the call, we'd like to ask that you limit yourself to one question and one follow-up. Feel free to get back in the queue after that, if you like. And so, with that, I'll turn the call over to Tom.

Thank you, Karen, and thanks to everyone who's participating in today's call. As always, we appreciate your interest and look forward to your questions during the question-and-answer portion of the call. On the call today, John will walk us through our recent results and describe our progress on some of the delineation projects that we have underway. This will include results from delineation in the Meramec and completion modifications that have further improved our results in the Lower Wolfcamp. In the Meramec, John will discuss results from two recent 10,000-foot horizontal wells that are significant in their performance and encouraging in the manner in which they're delineating our acreage. In the Wolfcamp, John will discuss some recent results from completion optimization, including an outstanding recent 10,000-foot well in Lower Wolfcamp in Culberson County. We're making great strides in improving our well results across our portfolio. Additionally, we are confirming our optimism regarding the uplift we see from 10,000-foot horizontal wells. Not only are these wells delivering outstanding 30-day and 180-day rates, they're exhibiting surprisingly low decline. Joe will follow John with an operational overview, including some of the steps we have taken to improve field efficiencies. As Joe will describe, he and his team have made great progress in getting our lease operating expenses down. There are many components to the progress that Joe will report, including smart, well-engineered water management; personnel and equipment efficiencies; lift-off optimization; compressor optimization; and others. The savings from current and future lease operating expenses are significant to Cimarex. We reported another production beat this quarter, driven by continued improvement in well performance. Our total company production was 974 million cubic feet equivalent per day for the second quarter, which exceeded the high end of our guidance. Gas production was up, while oil production was down slightly. As we had forecasted, this was due to fewer well completions in the Permian Basin due to the timing of our infill and spacing pilot completions. As we pick up the pace in our Permian completions during the second half of the year, we expect our oil production to trend upwards. Combined with oil production expected from the Woodford completions in East Cana, we expect oil production to be up approximately 15% in the fourth quarter versus second quarter levels. Operating expenses, with the exception of G&A, came in within guidance, resulting in a strong quarter overall. G&A was slightly above guidance, as we recorded the cost of an early retirement package offered to employees in the first quarter that was finalized in June. We also announced an increase in our 2016 capital budget. We have raised our guidance from a range of $650 million to $700 million of exploration and development capital to $750 million for 2016. This includes $600 million earmarked for drilling and completions, up $100 million from the high-end of our previous guidance. The increased capital will be used to further delineate the Meramec formation in the Anadarko Basin, push the completion of Woodford infill wells forward, and add a handful of new wells to our Delaware Basin program. Our bigger, more effective stimulations are also adding to our capital. This is money well spent, as shown by our well results. We now see our operated rig count holding at five rigs for the remainder of 2016. And with that, I'll turn the call over to John to provide further color on our program.

Thanks, Tom. I'll start with a quick recap of our drilling activity in the quarter, before getting into some of the specifics of our latest results and more color on our remaining 2016 plans. Cimarex invested $156 million on exploration and development during the second quarter. About 65% was invested in the Permian region, with the rest going toward activities in the Mid-Continent region. Companywide, we've brought 34 gross, 14 net wells on production during the quarter. We had an average of nine operated rigs running during the quarter. These rigs were busy working to hold acreage in both the Wolfcamp and Meramec plays, as well as drilling spacing pilots in both the Delaware Basin and Mid-Continent. That activity is winding down, and we are currently running five rigs, three rigs in the Permian and two rigs in Anadarko, an activity level we intend to maintain through the rest of 2016. While a lot of focus is put on the number of rigs Cimarex is running, completion of the wells has the biggest impact on both well cost and well performance. We are continuing to push the envelope on well completions. On page 30 of our presentation, we illustrate the evolution of completion size, as measured in pounds of sand per lateral foot drilled. As you can see, completions are evolving across the company. We have several other slides in our presentation that illustrate the uplift we've seen in several of these plays, including the Upper Wolfcamp in Culberson County and now the Lower Wolfcamp as shown on slide 12. Our most recent Lower Wolfcamp well, the Flying Ebony 19 State A #5H, was completed with 2,400 pounds of sand per lateral foot and had an average 30-day IP of 3,127 barrels of oil equivalent per day, of which 23% was oil, 46% gas, and 29% was NGL. On average, that IP is 36% higher than previous completions. The success of the frac design used on the Flying Ebony is more than just a pound of sand per foot increase. It is a direct consequence of Cimarex developing a strong understanding of the geology and rock mechanics for this interval, which in turn leads to design changes not just in the amount of sand pumped, but also in the type of sand, cluster design, cluster count, stage spacing, along with the type of fluid. This type of detailed frac design is taking place internally for each of our prospective zones in both basins, which is leading to the strong well performances that we have been achieving across the board. Regarding our New Mexico Avalon Shale program, Cimarex drilled and completed the 5,000 foot Triste Draw 25 Fed #7H late last year, implementing an upsized stimulation design, in order to determine that we could achieve improved performance for this interval as seen in other Permian shale intervals. As shown on slide 17 in our presentation, the results for this well have been outstanding. The well achieved a 30-day peak IP rate of 1,811 barrels of oil equivalent per day, of which 59% was oil, 20% gas, and 22% NGL, with a very impressive 180-day rate of 1,317 barrels of oil equivalent per day and a 180-day cumulative of 230,000 barrels of oil equivalent. This kind of result certainly raises the Avalon program to top tier for us going forward. Capital to be invested in the Permian in the second half of 2016 will be focused on completion activity and acreage obligations across our Wolfcamp position in both Culberson County and Reeves County. The total capital ascribed to acreage holding in Delaware Basin is just over $230 million in 2016. We currently have three rigs running in Delaware Basin and expect to keep them active through the remainder of 2016. Now, on to the Mid-Continent. You will recall that we began drilling the latest Woodford development project on the east side of the Cana core in the fourth quarter of 2015. This development covers six sections, of which Cimarex operates two sections. This infill project consists of 47 gross, 22 net wells. Drilling is finished, and completion of the wells has again been moved up and is now scheduled for early September versus October, as was discussed in our last call. This change in scheduling was a contributing factor to our increase in capital expenditures for 2016. As for the Meramec, we continue to drill wells to both hold our acreage and delineate our acreage position. Of note are two of our most recent Meramec results, the Peterson and Sims long laterals, whose location can be seen on slide 19 of the presentation. The Peterson 1H-2821X, located in the northwest part of our Meramec acreage position, achieved a 30-day peak average rate of 19 million cubic feet equivalent per day, of which 54% was oil, 30% gas, 16% NGL, while the Sims 1H-2017X, located in the southeastern part of our Meramec acreage, achieved a 30-day average rate of 12.8 million cubic feet equivalent per day, 29% oil, 46% gas, 25% NGL. These two bookend wells on our acreage are good confirmation of our ability to adjust both the landing zone and frac design to achieve very good rate of return results across the breadth of our Meramec acreage, and is why we have chosen to keep two rigs running throughout the remainder of the year, holding Meramec acreage. Finally, to better understand the multi-zone potential for this area, we have recently finished drilling an eight-well stacked/staggered spacing pilot in the Meramec and Woodford formations. See slide 21 for an illustration of this design. These wells are scheduled to begin completion operations later this month, with first production anticipated in the fourth quarter. Results from another Meramec spacing pilot were recently announced by our partner Devon. The Alma pilot wells had an average IP of 1,400 barrels of oil equivalent per day, of which 60% was oil. The completion of these wells was influential in the stimulation design for the Meramec wells in our stacked/staggered pilot, with the final Meramec design using 2,600 pounds of sand per lateral foot. Cimarex holds a 46% working interest in this pilot. 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 the usual items, our second quarter production, our Q3 and full year 2016 production outlook, and then finish up with a few comments on LOE and service cost. As Tom mentioned, we had yet another great quarter for production, with stronger-than-expected base property and new well performance really driving the quarter. Our second quarter volumes came in better than anticipated. Our reported Q2 total company net equivalent production of 974 million a day, beat our guidance projection of 935 million a day to 965 million a day and was up slightly from our Q1 reported volume of 973 million a day, rather than down, as we had anticipated last call. As expected, with the accelerated completion activity and increased processing capacity during the second quarter, we saw a nice boost in our Permian production, with the addition of a second frac crew in May. We completed nine Permian wells during the quarter, as compared to just three wells in the first quarter. As a result, our second quarter Permian equivalent volume came in at 509 million a day. That's up 32 million a day or 7% from the first quarter. In the Mid-Continent, continued strong well performance from our Cana-Woodford project, which came online in late fourth quarter last year, supported both our Q1 and our Q2 Mid-Continent volumes. And with that support, our second quarter Mid-Continent equivalent volume averaged 463 million a day, that's up 44 million a day or 11% from Q2 2015. But as expected, with only five new wells in the Mid-Continent coming online during the quarter, our second quarter Mid-Continent volumes decreased $30 million a day as compared to Q1. So, as we look forward into the last half of 2016, we're projecting a further acceleration of completion activity in both our Mid-Continent and Permian programs. And as a result, we're projecting a total of 72 net wells to come online during the year, as compared to the 60 net wells we projected last call, with seven wells of those additional wells located in the Permian and five wells in the Mid-Continent. In the Mid-Continent, we've moved up the start date for our Cana infill development project to September, as was previously stated, again, versus a previous estimate of October. And in the Permian, with the planned addition of a third rig in August, we've also accelerated our completion activity, for the most part, in the fourth quarter for both of our Bone Spring and Reeves County Wolfcamp programs. As a result, we now anticipate having 22 net wells waiting on completion at year-end with 11 net wells in both the Mid-Continent and the Permian. And that's down from the 46 total wells that we had waiting on completion here at the end of Q2. With our strong first half performance and our planned acceleration in completion activity, we've increased our total company full-year production guidance to 0.98 Bcfe to 1 Bcfe per day. That's up from our previous guidance of 940 million a day to 970 million a day to and would put us, in essence, flat to 2% higher than our 2015 average of 984.5 million a day. More importantly, our planned acceleration – accelerated completion activity gives us very strong momentum going into 2017, with our forecasted Q4 exit rate in the range of 1.02 Bcfe per day to 1.07 Bcfe per day. That's 3% to 9% higher than the 986 million a day we posted in Q4 2015. Our oil production plays a big role in our projected Q4 exit rate, with our Q4 Permian and Mid-Continent net oil volumes forecasted to be up 12% to 17% from the volumes that we reported in Q2. For Q3 2016, with 10 net Permian wells and three net Mid-Continent wells expected to come online during the quarter, we're guiding our total company net equivalent volumes to be in the range of 950 million a day to 980 million a day, flat with the second quarter. As we move into Q4, our completion activity really picks up steam with 15 net Permian wells and 26 net Mid-Continent wells planned to come online in the fourth quarter. Shifting gears to OpEx, we had a nice guidance beat with our second quarter LOE, and we owe it all to our production group's continued and dedicated efforts to optimally reduce our overall operating cost structure. With their focus, we once again saw sizable cost reductions during the quarter and similar components as in quarters past: saltwater disposal; compression; rentals; contract labor. And as such, our Q2 lifting cost came in at $0.65 per Mcfe, well below the low end of our guidance, which was $0.80 per Mcfe to $0.90 per Mcfe, down 19% from our first quarter average of $0.80 per Mcfe and down 22% from the $0.83 per Mcfe we averaged in 2015. So, after incorporating our continued cost control efforts and also taking into account the fluctuating nature of workover expenses, we projected our remaining year lifting cost to be in the range of $0.60 per Mcfe to $0.75 per Mcfe. I'll take a moment just to say we're extremely proud of our entire production ops team for their success in safely and effectively reducing our LOE. The progress is sizable. Since prices began falling back in 2014, we've seen our absolute monthly net LOE drop approximately $9 million a month, which on an annualized basis, has essentially freed up over $100 million a year that we can direct to our drilling program. And finally on service cost, some very similar comments to our last call with regard to drilling and completion cost. Most all of our drilling cost components have remained relatively in check, while we have seen some modest reductions in per unit completion cost primarily in the Permian. On the drilling side, we have kept our focus on efficiencies as illustrated with our average 2016 Bone Spring spud to rig release drill time of 10 days, down from 12 days in 2015 and 14 days in 2014. On the completion side, we've seen continued cost reductions in the Permian, both from a frac cost standpoint, as well as in the cost to source our water, which has really helped to negate the additional cost of pumping larger jobs. As we continue to increase our frac size, completion dollars continue to dominate our total well cost, representing up to two-thirds of the individual total well cost for each well. As in quarters past, we've been able to offset the cost of the larger fracs with lower per unit pumping costs. And as such, most of our generic AFEs have remained somewhat in check compared to last quarter. An exception, however, is our Permian Bone Spring program, where both drilling and completion efficiencies have reduced our current one-mile lateral AFEs to $4.7 million to $5.1 million, down 6% from the $5 million to $5.4 million that we quoted last quarter. In the Wolfcamp, with larger completions, our current generic two-mile lateral Culberson AFEs continue to run in a $10.2 million to $11.2 million range. That's like the last call, but down 5% from where we were in Q4 and down 23% from that program's AFE back in late 2014. With our larger frac design, our Cana core one-mile lateral Woodford AFE is running in the range of $7.1 million to $7.5 million, up from the $6.6 million to $7 million range we previously quoted with the smaller frac, but right in line with the $500,000 to $600,000 anticipated increase that we quoted last call, should we adopt and implement the larger fracs, which we are. But even with the larger frac, our current Cana one-mile Woodford well is down 10% on a total well cost as compared to late 2014. As we drill more two-mile lateral Meramec wells, our current AFEs are running in the range of $10.7 million to $11.4 million, all the while we continue to experiment with various frac designs and land depths and so on. In closing, we had another great quarter. We made tremendous strides reducing our overall operating cost structure. We're staying focused on efficiencies to reduce and optimize our drilling and completion costs. And we continue to make good progress maximizing the productivity and profitability of our wells. So with that, I'll turn the call over to Q&A.

Good morning, everyone.

Good morning, Drew.

Tom, I was hoping you could talk a little bit about the Upper Wolfcamp pilot in Culberson County, realize it's still early but any – even just geologic information you obtained so far in that pilot?

Well, I'll just make a quick comment and then turn it over to John for perhaps further details. We're just now flowing it back; I don't even think we have two weeks on that, and so it's really too early to tell. That's an area that we have very high expectations for. It's a great geologic target, and I think that we have lots to learn in terms of well density there, and certainly all the optimizations going on throughout our organization will be used in refining our next test, but that particular pilot, Drew, it really is too early to tell.

Yeah. Drew, this is John, and I'll just echo what Tom just said. I mean, it is very early and the flowback of the wells are just now cleaning up. I'll just say operationally, everything went just fine from a frac standpoint. Everything looked good, so we'll just – time will tell as we flow back and as we get enough data in hand, and hopefully here in the near future, we've got to talk about them.

Yeah. One thing, if I just add to that, we're really fascinated. I mentioned in my opening remarks that there are two things we're seeing with a lot of these Wolfcamp wells. One is the enhanced well performance, but the other is the lower decline from our longer laterals. I don't want that to be lost on observers. It’s really a remarkable result, and it takes some time to watch that and see it stabilize. In fact, some wells we have that have been on for six months are still surprising us. And so, we'll talk about it as soon as we can make conclusions.

And I guess I’ll follow up with Tom. He's absolutely right, and it's difficult – it's very difficult to really predict an ultimate EUR for some of these wells until a good four, five, or six months out that we finally start seeing some form of decline, so we can then model what it's ultimately going to end up at. That’s a good problem to have, quite frankly, but it just means it takes quite a while before we finally reach the point where we feel really good about what that ultimate EUR will be for the well.

Yeah. The results are great, and I think they keep surprising us to the upside. I guess, it kind of begs the question of how do you progress through this completion design evolution? You have obviously a ton of projects that you want to execute on, and it seems like the more and more you test bigger and more complex completions, you keep getting much, much more return than the capital you put in. So, what’s your strategy for reaching that optimal well design the quickest?

Well, one is to pick up the pace in our capital, and that's a significant reason and justification why we decided to keep five rigs going and accelerate our completions; it just gives us more laboratories. I'm very proud of our organization and the degree of innovation that they're undertaking. We study our competitors hard. I think you all know us well enough not to be surprised by that statement. But it's also a strength of Cimarex to be in two of the most active basins in the country, to be in the Delaware Basin and the stack play means that we have two independent laboratories, and we can draw and bring best practices from one play to another. And that has also been a really big part of our success, and we're just getting warmed up there. We have lots of things on our list to try, and many of them are things that have been tried in one basin but haven't been tried in the other.

And, this is John, I think the only other comment I'd make is we put a lot of debate internally on these frac design changes and we involve all disciplines when it comes to that, and then we measure ourselves quickly. Like you've pointed out, there's incremental capital involved that does drive up our overall total cost. And so, we're asking ourselves, what type of improvement justifies this, what should we be looking for early in the life of these wells that say, this is a good investment decision, keep moving forward with it. And quite frankly, once we achieve that, in the middle, we're asking ourselves, okay, can we go even further, what's next? And that's what I'm kind of proud of is that we are not resting on our laurels here. And as much as I really love the landscape right now, what we've achieved and what it looks like from a rate of return perspective, we are not going to just sit pat and say, okay, this is it; we're going to keep pushing. Because there is still so much that we're learning about these rocks and these frac designs, and I still think there's a lot of potential there.

Thanks. I'll leave it there.

Good morning, guys. Nice quarter. I guess, first question, looking at the stack and everything you got going around there and Canadian County specifically, curious what your thoughts on those initial wells are and what your plans are for activity going forward there?

Will, this is John. I guess you're referencing in particular Canadian County where we have drilled a number of Meramec wells, including the latest one we just talked about, which is our Sims well. That area has been a little bit more of a challenge for the Meramec than necessarily, say, more of the Blaine Kingfisher, but that's why we're really proud of that Sims result in that part of the play. I think that's also why we've decided to add a little bit more capital because now we feel a little bit better about that area, but it's also one that's going to take a little bit more drilling as we get more comfortable with landing zone and frac design. And again, I want to stress that there is no one recipe here in the Meramec, say, in one area that works best across the whole play. We're definitely changing things up and adapting to results. And again, I'll just emphasize, that's why we really like that Sims result. That one really has given us a little bit more – definite more encouragement toward that part of the Meramec play.

It's really a changing story. You hear us keep talking about the variability in the Meramec. Even around that Sims well, we had some results from us and some competitors that led us to think, oh, should we drill this well or not? And we tried some different things, and it's a stunning and surprisingly positive result, and that tells us, you know what, it's not over until it's over. This Meramec really is a function of landing zone and completion design, and that section has lots of surprises left and, thus far, surprises on the upside.

Could you quantify the differences in completion that you've had in Blaine County versus on the Sims well?

Well, this is John, and I'm going to – in broad brush strokes, maybe, the differences. Clearly, there is always the amount of sand we pump. There are going to be differences in the cluster design, cluster spacing, and quite frankly, there are differences on whether or not we use diverters. And all of those are kind of in our bag of tricks to look at. I will just say right now, state that again, the Peterson design was way different than the Sims design, and what we're trying to do now is go out there and check on that, do a couple of more wells and see does one work better in one area than one in the other, and then we'll continue to progress from there.

Great. Thanks, guys.

Hi. Good morning, everyone and congrats. Tom, I just wanted to ask on capital allocation. It looks like you guys have a – looks like a pretty good problem, given all your impressive results across multiple geographic areas. So just, how are you thinking about prioritization of capital by both geographic area and zone? And I guess what I'm getting at is what gets the first call, and how do you rank your plays right now?

No, it's a great question, Jason. And it is a challenge, and it's a pretty high-class problem to have. We have two outstanding plays, and we have outstanding acreage positions in both plays and acreage positions that allow for 10,000-foot long horizontal wells. You sum all that together and it's a real dilemma on how we allocate capital. Now, I will say, as I've said in the past that some of our best well level returns are in the Bone Spring in the Delaware Basin, certainly the 10,000-foot long Wolfcamp wells are fantastic and getting better and, as John said, the Avalon is really roaring to compete heads up with everything I've just mentioned. I would say that Delaware at the well level rate of return is at the top of the pack, but that Anadarko story is evolving and not very far behind. If some of these new landing zones and new stimulations, if the Sims, Peterson, and some of the wells announced by our competitors, if these results are repeatable across large portions of our 115,000 Meramec acres, then it's going to really give us angst on how we allocate capital, because there is also science and delineation we want to do. So, we're always balancing what's the absolute high rate of return on our next investment with looking 5 or 10 years ahead, what information do we want and when do we want it. So, in terms of capital allocation, we are going ahead with three rigs in the Delaware and two rigs in the stack play. And we think both those rigs – both those programs are designed to give us a lot of information, including both landing zone, completion optimization, and geological delineation. And so, we're fairly comfortable with that three-rig Delaware, two-rig Anadarko right now. If prices were to improve materially, I think it's a function of whether oil or gas improves. But right now, the Delaware is probably the strongest voice for incremental capital, if we were to increase above and beyond that.

Thanks, Tom. And I guess my follow-up is, one thing you guys didn't really discuss in the prepared remarks was Reeves County, where the Cabinet State well also looks really strong and on a shorter lateral. So, can you maybe just talk about that well, what you guys did, and does that maybe drive you guys to flock more toward shorter laterals in that play?

Well, this is John. Yeah, shame on me, the Cabinet State is an outstanding well and we're very, very pleased with that result. And the reality is, I wish I could have made it a 10,000-foot lateral, but that particular case, we were landlocked to where to hold that acreage was a 5,000-foot lateral. And in that particular play, we clearly, in our own minds, had demonstrated the uplift of going to 10,000-foot lateral. So, just imagine taking the Cabinet State and making it a 10,000-foot lateral, it would be even better. I think what you're also seeing at Cabinet State is again, and Tom does a nice job of talking about this, just us leveraging frac design changes, say, in the Upper Wolfcamp and Culberson over to Reeves and back and forth, and that's a good example. Along with we have our major development there next to the Big Timber, where we're about to start fracking with the Wood wells. We're clearly taking that frac design that we implemented over on the Upper Wolfcamp pilot there over to those wells. So, we're seeing really good results there throughout that part of Reeves County, and we're very excited about it, and we got a lot of drilling to do there for the remainder of this year and the next year. And then finally, when I think about it, the things also that's changing there and we talk a lot about is landing zone. We are definitely getting much more comfortable in Reeves as to where we want to land those wells, and I think it's leading to the kind of results you're seeing as well. So, it's kind of a combination – kind of sounds like a broken record, but both frac uplift and landing zone.

Yeah, and Jason, the true answer to that is, this has been a real active week for earnings release amongst our competitors, and we're sensitive that you all are living on one hour of sleep and Red Bull, so we decided to keep our prepared remarks short.

I appreciate that and congrats again, guys. Thanks.

Good morning, and congratulations on the strong quarter. Regarding the Avalon, can it attract a rig to itself in 2017, or does it need to be part of a more regional strategy?

Well, this is John. I got a lot of people in Midland who'd love to have a rig on the Avalon, and, again, we have certain priorities that we need to meet no matter what. We still have acreage we need to hold in the Wolfcamp, and that will clearly be something we will fund. But I will tell you, this well result has definitely caused us to ask what's next, and I would not be surprised if we go back up on that acreage and push the envelope again in terms of our stimulation design and with a long lateral. That's the one thing I think, our next step we'd like to take in the Avalon is get a long lateral under our belt with this type of stimulation and then really see what kind of rate of returns we can achieve. And then probably the next step for us is then spacing. We've already announced before that we did spacing pilots in the past in the Avalon. We feel very good at eight wells per section for an individual interval. And again, there are multiple intervals in the Avalon. We probably won't need to go out there and test tighter spacing, but we're also blessed that we have a lot of competitors in and around our HBP acreage who are doing just that. So, we're not in a vacuum there. So, we'll learn a lot from looking across the fence, but yeah, I think it's safe to say we'll at least get a little bit more capital, at least I'm going to argue for that, for some wells next year to test further within that play next year.

Thank you. That was good color. I'd like to ask a little bit broader question for my follow-up. I was wondering what the Meramec updip versus downdip drilling strategy might be over, say, 2017 and 2018, and to what extent, if any, this might be influenced by the multi-zone potential that you showed on slide 21?

This is John. As far as – let me just address first updip, downdip. I mean that's a nice little display we put out there, but in no way does that influence where we go with the rig. Right now, honestly, that rig is going to hold acreage. The two rigs that are remaining for the rest of this year, as well as going into next year are earmarked to hold the acreage, and some of that acreage is both updip and some of it is downdip. Again, what's nice is we are achieving very good returns in both areas that we want to justify that capital, which is why we're keeping the two rigs. So, I don't know that we make a huge distinction in terms of shifting that in terms of where we would send the rig because, again, we're trying to hold acreage. And then – I'm sorry, what was your second part of that? I'm sorry, what?

Well, I guess, really, what I was really thinking is, I mean, sort of thinking simplistically and trying to look at what a greater number of wells over the play as a whole. It seems like the updip tends to be oiler than the downdip, but the Alma pilot is pretty impressive. You got a pretty impressive work out there and I'm wondering if there's any influence from having two zones producing there as opposed to, say, targeting the Meramec kind of theoretically oiler area?

Well, all I'll say there is, there are a lot of spacing pilots that are being drilled by us and our competitors. I think at last count, there were 10 of them, I believe. And quite frankly, we have an interest in most of them, so we'll be avid watchers of those results as well as our own pilot, that we'll be starting completions on here soon. I don't know that we ourselves fully understand the full stack potential of this play, I guess, to use that acronym. We just don't know yet. We feel pretty good where we put our Leon-Gundy that there's enough thickness there to justify the two layers within the Meramec with the one layer in the Woodford, and we're very – we have high expectations for that pilot. Beyond that, I don't know how much more you can go beyond that, and time will tell, and as you can also argue how will it vary based on maybe that's what you're driving at versus the hydrocarbon component that is, as I get into more oiler window, can I stack more or not or vice versa. Those are things we just don't know yet for this play.

Yeah. There are a lot of variables here: updip, downdip, oil, gassy pressure, non-pressure. We will study every well on the trend and I will tell you that we keep a fairly evergreen list where we look at every well and rank them by the rate of return. And we focus on the rate of return. And that's what we're going for. And so, we've talked in the past that we have a bias towards pressure, we have a bias towards deliverability, but our real bias is towards the rate of return. And if we were to look at the rate of return, this map would be contoured a little differently, and we're pretty excited about the potential for us.

Thank you. I appreciate it. That's great color.

Thanks. And Tom, with these very strong well results, do you see this lowering your threshold oil and gas price necessary to move beyond five rigs, if you wanted to add some? So, essentially, if that oil number, say, was $50, as it moved down to $45, or likewise on gas, as it moved, say, to below $3, just want to get your thoughts around that?

Well, that's a great question. And I'll say this: certainly, this is an evolving story, and you can go back what we said a quarter ago or two quarters ago, and the world's changed just in the last three or six months. Certainly, with our performance improvements, our cost reductions, and certainly, LOE reduction is a really important part of the story. Our breakeven costs have come way down, and that's through both in Anadarko and in the Delaware Basin. So I will say that Cimarex looks pretty good in the mid-$40s, $2.50 to $3.00 gas environment. We have tremendous returns throughout our portfolio, and we are achieving fully burdened results that are historically high within our program. So, it's not much – in answering your question, it's not so much about price as it is stability. We want to manage our balance sheet, we watch our cash flow, and we are absolutely committed to being disciplined and keeping the health of this company second to none. And so, what we're looking for isn't necessarily an absolute price signal as it is price stability. And ramping up our capital as we did is probably, to us, a strong vote of confidence in our assets. And we think that if prices were to stabilize at $45 and the $2.50 to $3.00 gas range, we've got a great landscape ahead of us. And I've said in the past, we're not waiting for the rescue boat to save us; our challenge to the organization was to figure out how to make a living in this environment, and I will say that our organization has responded to that call in every way, both in increased well performance and decreased costs in lease operating. So, we're in pretty good shape if we see stability.

Excellent. Thank you. That's excellent color. And then my follow-up is just to make sure I heard this correctly in the prepared remarks. So, you're targeting 15% growth in oil production from Q2 to Q4, and that's based on your acceleration?

Well, that was my foot in my mouth. Joe said 12% to 17%.

You're in the middle.

Yeah, that's the midpoint of our range. But Joe, why don’t you handle that?

Yeah. That is quite simply a byproduct of CNR, our infill project in the Permian, coming on here in Q3 and in Q4, as well as the oil that's associated with our Anadarko Basin completions. Now, the real wildcard there is the timing because, in late Q3, early Q4, we've got a fair number of wells scheduled to come on, and a week or two slip here can really impact those numbers. But the way we forecasted it, we could be anywhere from 12% to 17% higher combined in our total oil production.

Good morning, everyone. Congrats on the quarter. I appreciate all the color you've provided on the production differences between the short and long laterals in the stack. And I know it's still fairly early on, but I was wondering if you think there will be any material differences in overall returns between the longer laterals in the deeper overpressure window versus the more shallow regular pressure window? And if you think the longer laterals will make sense in both areas?

This is John. I guess I'll take a stab at that. In general, we do believe that incremental capital you spend on a longer lateral is well worth it relative to the rate of return we achieve, and we've demonstrated that throughout our portfolio. But again, it’s fair to say, the majority of our portfolio is in pressured rock and that's where most of our experience. We do not have a lot of experience in drilling long laterals in lower pressured – close to normal pressured type rocks. And something else also happens, we talk a lot about this. Once you move up in that normal pressure part of the play, more oily play, you're also talking about a part of the play where it's shallower, so your cost to get there, the vertical part of it is very inexpensive. You don't need that extra string of pipe; you drill it very quickly. And a lot of times when we think about long laterals, we love them because it’s pretty expensive for us to get there, to get to the target, so once we're there, we want to stay there as long as we can. In fact, I would argue our drilling department wants to know why we stop at 10,000 feet, and in some ways, internally, we talk about that. But the big difference is when you go updip, it's pretty cheap to get down there, to get to the zone. So, then you got to ask yourself, operationally, does that extra 5,000 feet really gain you a lot or not? And we just don't have a lot of experience with that; I'll be honest with you. All our experience has been in the pressured, but we're watching it very, very carefully ourselves. As Tom said, we're always looking across the fence and asking ourselves maybe, maybe in that shallow where normal pressure, maybe 5,000 feet is a better way to go than 10,000 feet. I don't know that answer right now; we'll see over time.

Perfect. Thanks for the response.

Thanks very much. Congrats on a solid quarter. I guess, just curious, looking at the Q4 exit, the implied Q4 rate, just thinking about that level as well as the commentary around the oil growth to the fourth quarter. What sort of activity levels would you say are required to keep those levels at least flat as we look towards 2017? And is your anticipation at this point, given the current strip, that you would actually still be pressing to grow those levels?

Mark, why don't you handle that.

Yeah. Hey, Michael. This is Mark. It's a little early for 2017 to put too much guidance around it, but as we've now changed our plans and going from three to five rigs, staying at five rigs through the remainder of the second half of 2016. As you go into 2017, the five to seven rigs I would call is a pretty good place; we could be flat to growing slightly into 2017. Again, lots of work still needs to be done. We still need to get comfortable with where the commodities are at and all those kind of caveats, Michael. But five – we're exiting in a very good pace into 2017, and I think a five- to seven-rig program would keep us flat or grow slightly.

Yeah. This is Joe. What I might elaborate on there is that our Q4 projection puts us at a pretty high level company-wise going into 2017. So, there's a couple of ways of looking at it. On a year-over-year comparison, certainly what Mark's talking about is doable, but we're going to get these oscillated production profiles with a lot of these infill projects. So, for us, it always, and we talked about this in I think our first quarter call, a lot of these perceptions that your exit rate has a lot to do with what your next year's average is going to be, I think we all need to take a little bit of caution in that because we're going to see highs and lows and highs and lows as some of these big projects come online.

One of the challenges we face is we're in a constant inflection point with quality in our assets and also, as Joe said, timing. Truth of the matter is, we're just not that good at forecasting on things that are difficult to forecast, and improved well performance is the biggest of them all. But with our asset quality, we had the wind at our backs on that. So, we're pretty optimistic as we look ahead.

Great. That's helpful color. I appreciate it. I guess my follow-up, just kind of bigger picture, you have a pretty compelling slide there, I think it was slide 30 or so, where you outlined the progression of proppant loading over time. I'm just curious, as we think about a reacceleration of activity from the industry over the coming years, I guess, in theory anyway, if oil prices go up. How would you think about proppant loading as cost inflation comes back into the picture, meaning, is it harder to carry such high proppant loads without the big benefit of cost inflation that we've seen from the cyclical pressure? Does that make sense?

Yeah. This is Joe. I'm not sure I fully understand the question; are you saying as far as availability?

Like, would you not have increased proppant loading to the extent that you have were it not for the cyclical benefit you've gotten from improved pricing from service vendors, such that as things move the opposite way and, theoretically, we expect some inflation down the road, will proppant loading be an area where you would reduce well costs going – at some point in the future? You know what I'm saying by that?

I think so. With regard to well cost, we have been very fortunate that the market has been such that we've been able to increase our job sizes at the same time, that our total overall cost had come down. As an example, if you just look at Q2 versus Q1, in Q2, we prompted about, as a company, 21% more fluid and 12% more sand, yet our per well frac cost was maybe down 10%.

Right.

It all comes down to what John just said earlier, it's going to be a matter of the economics. So, if these prices do creep up or the costs do creep up, we're always going to be looking at that job, what will it cost, what results do we expect to achieve pumping that job, and does it merit going at the larger job or should we deviate somewhere plus or minus from there in design. So, it's kind of a tough question to answer other than to tell you that we're constantly looking at current costs; we're constantly working hard to keep them low, and we're constantly focused on rate of return.

Yeah. That's the last point I want to jump in on. Joe does a great job of tracking – just yesterday, we were looking at our total well cost as measured by cents per pound of sand that we're pumping, and it's remarkable how far that's come in the last couple of years. But we've got the right lands, and I'm very confident we have the right lands and after-tax rate of return. And so, yes, in answer to your question, some of the aggressiveness that we've had in adding to our proppant load certainly has been facilitated by how low our cost structure has been; and if we have pressure either through commodity pricing or service cost, we're going to look at that on a rate of return basis and try to find the optimal solution. We don't look at production rates and say the highest production rate is our best solution. We always, always, at Cimarex, look at the rate of return on the investment it requires. So, I have a lot of confidence in free markets. If market forces cause us to find a different path forward, I think our focus on rate of return is exactly the way to navigate that.

That's super helpful color. Appreciate it. Congrats, again.

Thanks.

Hi, guys. Sorry about that. Congrats on a good quarter. And for Tom and John, I guess I'm curious, you guys have drilled a Meramec well in the oil window in Kingfisher. Also, you've gone all the way down on the gas window in the southwest portion of the play, and then obviously in between the two extremes. I guess, Tom, based on the running list of operated, non-operating results and then the associated rates of return for all of those wells, what portion of the play do you feel consistently is at the top of the list based on rate of return?

Well, I'll – yeah, I'll answer that, and then John will jump in. As you look on slide 21, certainly, there is a little area where a lot of stars cluster. It's right about where our pilot project has the arrow going through. It's near the Alma pilot. It's nearly on Gundy pilot. That is a tremendous little sub-area within the play. Cimarex has some outstanding wells in there; other operators do as well. And that's certainly a really, really attractive part of the play, comparing the play overall. Now, I will say, if you go up to where we've got our Peterson well, that is emerging as a really, really nice part of the play. Similarly, you've seen the Peterson results. I will say we're very pleased with our acreage position. Our team's done a nice job of building a position up there, so we have really, really nice exposure there. But, John, do you want to comment about the play in general?

Just to follow up on what Tom said, early on, that kind of intersection of the three counties there, Kingfisher, Blaine, Canadian. We had a number, as well as our competitors had a number of really good wells. And that area still holds up as a very good area. But without a doubt, this more western Blaine area, where our Peterson well is, and some of our competitors' wells have recently come on, it's starting to rise right up to the top there. It's an interesting area. And I'm really, really proud of our team, because that's an area where early on in this play, we got out there and grabbed some really good acreage at a really good price. That's really given us that nice yellow position we have there, where the Peterson well is located. So, that's kind of, in a broad way, where most of the best returns that we see so far. But I don't think this story is done. I think there's still – I'm fascinated every day another well comes on, and we are surprised. Just the other day, another well came on, in an area that we didn't think would be that prospective. And we are quickly looking at it and asking ourselves, okay, what's going on there? So, there's a lot of chapters of this story left to play out here in the Meramec for sure.

Thanks for the details. I guess, as a follow-up, since you mentioned it, can you kind of walk through the geologic differences between where that good Peterson well was and the Alma pilot, and what you know today? I understand it's evolving, but kind of where you're at today?

It's just kind of hard to describe. You are in a little bit different geologic setting for the Peterson, where you are with the Alma. You're in a little bit thicker part of the Meramec with the Alma than you are in the Peterson. You're more in a – what we call, a more updip position. But – and yet, we are seeing some really good results in and around that Peterson area, which is leading to these really high IP rates we're seeing and leading to the kind of results. So, you may be sacrificing a little bit. I don't see that as a stack, meaning, multi-layer area in Peterson versus say our Leon-Gundy or even Alma area, but you're not as thick. But boy, the rock looks pretty good there though.

Yeah. There is a lot of variability there: updip, downdip, oil, gas pressure, non-pressure. We will study every well on the trend and I will tell you that we keep a fairly evergreen list where we look at every well and rank them by the rate of return. And we focus on the rate of return. And that's what we're going for. And so, we've talked in the past, we have a bias towards pressure, we have a bias towards deliverability, but our real bias is towards rate of return. And if we were to look at rate of return, this map would be contoured a little differently, and we're pretty excited about the potential for us.

Thanks, gents. I had just a couple, very quick questions. But can you give us some more details on the eastern core infill development? I know it's now going to come online or start fracking in September; how many wells is that? Then, you could talk a little bit about the completion design around that program?

Well, as I said earlier, it's – for us, it's 47 gross wells, 22 net wells. And we operate the western-most two sections. We will be coming into it with one frac crew in September. Devon will – matching up with one frac crew. Very quickly, we'll then have two frac crews to finish up our two sections. And then Devon, I think, has plans to bring in a second frac crew a little bit later in the year, so they can get theirs done, although I think theirs extends into next year. I'm not sure – I don't recall, does it, Mark?

Yeah. I think it does, Joe, yeah.

I can also tell you that when we look at it, it is definitely more liquid-rich than, say, what we experienced in our previous drill development. In fact, I asked the team the other day, when we hit peak production – the net production we expect off that row at peak will be at about 49% gas, 34% NGLs and 17% oil, so kind of on a gas liquid basis, it's almost a 50-50 split. And so, again, that's why we're very encouraged. We think we're going to get very good returns out of this row. And then as far as the completion itself, I think Devon will speak to their wells, but for our wells, we are moving forward with the design that we deployed on the Armacost section. I think, if you refer to page 30, we talked about that, where we were up at 3,500 pounds per foot. We really, really liked the results from the Armacost. In fact, we didn't even talk much about that, but we have a really nice slide showing how Armacost wells are behaving, just as well as our other sections. And yet, we put an additional well within that section, a new well. So, we're able to get an extra well and yet still get similar results, meaning we're more reserves per section out of that section. So, we feel really good about that frac design, and that's what we intend on using going forward on our two operated sections.

That's a great color. And just my final question, obviously, an expanding opportunity set when you think about the Avalon. As you think about your Delaware Basin position, do you have a sense of how much of your acreage could be prospective for the Bone Spring, Avalon, and the Wolfcamp?

You mean all three targets?

Exactly.

Sure. I would tell you that, certainly, all acreage that we allude to on slide 17, as far as the 13,700 net acres of Avalon, have already Bone Spring, in fact, a lot of them already have Bone Spring wells on them that we've drilled in the past; some of them do. And, certainly, have Wolfcamp potential as well – without a doubt have Wolfcamp potential. And so, that area alone, and in that part of Lee County definitely has all three zones and is not just limited to just three zones. There are multiple zones within each of those, both in the Wolfcamp and the Avalon, and potentially in the Bone Spring. So, it's a very, very target-rich acreage position we have there that, again, if HBP is not going anywhere, and yet we recognize that there's a lot of potential on that acreage. And again, this latest Avalon well just shows that.

Thanks, Arun.

Yeah. I just want to thank everybody for joining us. I know it's been a busy week, and we appreciate your support and hope to continue to deliver good results in future calls. So, thank you very much.