Good morning, everyone, and welcome to the Cimarex Energy Second Quarter Earnings Conference Call. All participants will be in a listen-only mode. After today's presentation, there will be an opportunity to ask questions. Please also note that today's event is being recorded. At this time, I'd like to turn the conference call over to Ms. Karen Acierno, Director of Investor Relations. Ma'am, please go ahead.

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

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 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%…

Our first question today comes from Drew Venker from Morgan Stanley. Please go ahead with your question. Drew E. Venker - Morgan Stanley & Co. LLC: Good morning, everyone. Thomas E. Jorden - Chairman, President & Chief Executive Officer: Good morning, Drew. Drew E. Venker - Morgan Stanley & Co. LLC: 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? Thomas E. Jorden - Chairman, President & Chief Executive Officer: Well, I'll just make a quick comment and then turn it over to John for perhaps further obfuscation. We're just now flowing it back, I don't even think we have two weeks on that, and so it's really is 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 of 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 flowing back and as we get enough data in hand and hopefully here in the near future, we've got to talk about them. Thomas E. Jorden - Chairman, President & Chief Executive Officer: Yeah. One thing if I just tandem to, we're really fascinated. I mentioned in my opening remarks that it's 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 and that's – 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, it's – 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 that it's difficult – it's very difficult to really predict an ultimate EUR for some of these wells until a good four, five, 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. So, that's a good problem to have, quite frankly; but it just means it takes quite a while before we finally reach the point we feel really good about what that ultimate EUR will be for the well. Drew E. Venker - Morgan Stanley & Co. LLC: Yeah. The results are great, and I think they keeps surprising 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, how is the – what's your strategy for reaching that optimal well design to quickest? Thomas E. Jorden - Chairman, President & Chief Executive Officer: Well, one is 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 just gives us more laboratories. And 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 be surprised by that statement. But it's also 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 in 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 that and I still think there's a lot of potential there. Drew E. Venker - Morgan Stanley & Co. LLC: Thanks. I'll leave it there.

Our next question comes from Will Derrick from SunTrust. Please go ahead with your question.

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, I would just say, 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. Thomas E. Jorden - Chairman, President & Chief Executive Officer: It's really a changing story. (28:05) 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, surprise in 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's 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.

Our next question comes from Jason Smith from Bank of America Merrill Lynch. Please go ahead with your question.

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? Thomas E. Jorden - Chairman, President & Chief Executive Officer: 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 portion 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, 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, 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 if 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, 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 to going to 10,000-foot lateral. So, just imagine, taking the Cabinet State and taking it 10,000-foot lateral, it would be even that much 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 land those wells, and I think it's leading to the kind of results you're seeing as well. So, it's kind of combination – kind of sounds like a broken record, but both frac uplift and landing zone. Thomas E. Jorden - Chairman, President & Chief Executive Officer: 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.

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

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, 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 (35:48) 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 HBP acreage. The two rigs that are remaining the rest of this year, as well as going into next year is earmarked to holding 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 to shift in terms of 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 it was 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 is a lot of spacing pilots that are being drilled by us and our competitors. I think at last count, they were 10 of them, I believe. And quite frankly, we have an interest in most of them, so we'll be a avid watcher 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 – and then 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. Thomas E. Jorden - Chairman, President & Chief Executive Officer: Yeah. There is 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, 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 little differently, and we're pretty excited about the potential for us.

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

Our next question comes from Pearce Hammond from Simmons Piper Jaffray. Please go ahead with your question.

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 move down to $45 or likewise on gas, as it move, say, to below $3, just want to get your thoughts around that? Thomas E. Jorden - Chairman, President & Chief Executive Officer: Well, that's a great question. And I'll say this, certainly, this is a 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 really important part of the story. Our breakeven cost have come way down and that's through both in Anadarko and in the Delaware Basin. So I will say that Cimarex looks pretty, 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 be disciplined and keep 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 on our assets. And we think that if prices were to stable 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 organization was to figure out how to make a living in this environment, and I will say that our organizations respond to that call in every way, both in increased well performance and decreased cost 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? Thomas E. Jorden - Chairman, President & Chief Executive Officer: Well, that was my foot in my mouth. Joe said 12% to 17%. Joseph R. Albi - Chief Operating Officer, Director & EVP: You're in the middle. Thomas E. Jorden - Chairman, President & Chief Executive Officer: Yeah, that's the midpoint of our range. But Joe, why don't you handle that? Joseph R. Albi - Chief Operating Officer, Director & EVP: Yeah. That is quite simply a byproduct of a CNR, our infill project in the Permian come 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.

Great. Thank you very much.

Our next question comes from James Magee from GMP Securities. Please go ahead with your question.

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 and the deeper overpressure window versus the more shallow regular pressure window? And if you think the longer lateral seem to 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 oilier 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 have been in the pressure, 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.

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

Thanks very much. Congrats on a solid quarter. I guess – just curious, looking at the 4Q exit, the 4Q – implied 4Q 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? Thomas E. Jorden - Chairman, President & Chief Executive Officer: Mark, why don't you handle that. Mark Burford - Chief Financial Officer & Vice President: Yeah. Hey, Michael. This is Mark. It's a little early for 2017, put too much guidance around 2017, but as we've now changed our plans and going from three or 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. Joseph R. Albi - Chief Operating Officer, Director & EVP: 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…

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 reduced well costs going – at some point in the future. You know what I'm saying by that? Joseph R. Albi - Chief Operating Officer, Director & EVP: 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 prompt about, as a company, 21% more fluid and 12% more sand, yet our per well frac cost was maybe down 10%.

Right. Joseph R. Albi - Chief Operating Officer, Director & EVP: 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 cost do creep up, we're always going to be looking at for that job, what will it cost, what are the results 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 cost, we're constantly working hard to keep them low and we're constantly focused on rate of return. Thomas E. Jorden - Chairman, President & Chief Executive Officer: Yeah. That's a 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 rate of return on the investment it required. 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. Thomas E. Jorden - Chairman, President & Chief Executive Officer: Thanks.

Our next question comes from Dan Guffey from Stifel. Please go ahead with your question. Mr. Guffey, your line is live. Is it possible your phone is on mute? Daniel Guffey - Stifel, Nicolaus & Co., Inc.: 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? Thomas E. Jorden - Chairman, President & Chief Executive Officer: 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 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 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, an area that we didn't think would be that prospective. And we are quickly looking at it and asking ourself, 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. Daniel Guffey - Stifel, Nicolaus & Co., Inc.: 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 its 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 frosty (55:45) development, 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. Daniel Guffey - Stifel, Nicolaus & Co., Inc.: Okay. Great. And then, I guess, Tom in the past, you – and on this call as well, talked about Meramec variability. I guess, after the two new successful results and a flurry of successful competitor wells, I'm just curious, how has your thoughts evolved on variability across the play? And, I guess, obviously, you have increased confidence with adding a second rig in there. But expectations in terms of variability as you move to different areas of the play, how have those changed and evolved, I guess, since last quarter, and then really since last year? Thomas E. Jorden - Chairman, President & Chief Executive Officer: Well, I think, we still see the Meramec as highly variable. Perhaps one of the evolutions is that we think you have a great chance of overcoming that variability with landing zone and proper stimulation. One of the things that, I think, we've learned in the last year is that you cannot settle on a landing zone and carry that six miles or eight miles, and land the well in that same stratigraphic interval and expect comparable results. That said, what we're finding is the Meramec, because it is a series of prograding wedges, if you put yourself in a different wedge and find the right landing zone, you can find that you can overcome that variability. So, yeah, we still see it as a highly variable play. I think, there were some announcements out of our competitors that suggested that. But we're soldiering on, and we really like it. John, you want to add to that?

Yeah. I think, what it means is, we are getting more comfortable with the variability and how we adapt to it. And then change the recipe, so to speak, in each area. I think, what – really, in our vernacular, what it means is we will tear it differently. We'll have some areas – there will be a certain part that we'll look at it from a way we want to drill it and frac it, and other areas will be different. It's not like our – I would argue, our Woodford shale, it's a very consistent frac design, we wanted to pull it across all of that shale. It's a very homogeneous interval. That's not true in the Meramec. In the Meramec, you've got to adjust. And I think, over time, we're understanding what's required to get the kind of returns that we like across the breadth of our acreage. And again, the story will continue to evolve. And I am sure, based on what I'm seeing, I think our results will continue to get better, as we get better understanding of this rock, and what's going on here. Thomas E. Jorden - Chairman, President & Chief Executive Officer: And I think, it's important, we're speaking for Cimarex here.

Yes. Thomas E. Jorden - Chairman, President & Chief Executive Officer: And some of our own style is overprinted on this. I think some of our competitors have spoken about it as being a more uniform play. And we don't mean to contradict that. I just – they may be talking about different issue than we are. If you're saying it's a play where over broad areas it's developing top-tier economic returns over broad areas, you can drill and get really good results on average, yeah, it's a fairly uniform play. But I'll contrast the Meramec with the Woodford Shale. The Woodford Shale, we – fairly early on and particularly with our new stimulations got to a point where we think we understand the regional consistency. We can drill a well anywhere in our asset and fairly, accurately predict the yield. And we're fairly comfortable at a fairly high level making decisions. When we go to the Meramec, I will tell you that John and I get pretty into the weeds on looking at that stratigraphy, looking at landing zones, talking about completion styles, because it is very variable. And as far into this as we are, it is still, in our opinion, a fascinating and challenging scientific project.

I agree. We have very stimulating meetings with every Meramec well we drill. And there is – every Meramec well, in some ways, we – there is no one template. We – every one, it's different, and how we landed is different, how we fracked it. And I think that's going to continue for quite a while here until, finally, we settle in, in different areas or tiers as to what's best practice. And I thought we're getting there. And I think that's what you're hearing from us, is that we're getting more confident in how to plan those wells now going forward.

Our next question comes from David Deckelbaum from KeyBanc. Please go ahead with your question.

Good morning, Tom, John, and Mark. Curious, I saw the – with the rig addition this year, in the past, you guys have kind of outlined goals, and you alluded to that before of how quickly you want to learn some of these things. I guess, one, and this is really kind of a two part question, is the five rigs – does the five rigs sort of adequately answer what you would like to learn in early 2017, if not, what sort of shortfall is there? And two, how do you sort of marry that now? I don't see incremental activity going to the Cana just yet, and you do have a premium gas asset now with the strip well above the three into 2017. How do you marry an asset that's ready for full field development with attractive economics now versus trying to find all this knowledge in your other plays?

This is John. Well, it certainly keeps us busy trying to juggle everything you just described. In regards to Cana, I'm just going to tell you. I'm extremely excited for our future drilling activity in Cana from the standpoint of the kind of returns especially now that we look at it as a long lateral development. And, again, keep that in mind, everything up-to-date in Cana has been 5,000 feet. But given the continuity of our acreage, we along with our AMI partner, Devon, have – we, together, are starting to have those discussions over long lateral development. And indeed, I think you'll hear from us in the coming quarters start talking more about where that next development will take place for us. This road we're about to bring on is pretty exciting. It's more liquid rich part of the Cana-Woodford Shale. I'm also excited, because our partner there, Devon, has drilled two-mile laterals, so we'll get a chance to see those in a development phase, how they look. And we have a wonderful position between the two of us, just north of that, that we call the 13-8 area that we definitely see a long lateral development. It's just a question of the two of us coming together at some point and planning that out. And then, we'll see when that starts. So, you're absolutely right. Cana looks very good, but it's also a matter of how do you get that funded versus everything else that we're trying to answer in the Meramec and in the Wolfcamp and every other play we have. The other comment I want to make real quick is, we really did a lot early in this year with our spacing pilots. And yes, we don't have a lot to talk about them just yet.…

Yes.

Appreciate all the color, guys.

And our final question for today comes from Arun Jayaram from JPMorgan. Please go ahead with your question.

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? Mark Burford - Chief Financial Officer & Vice President: 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, himself, 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 don't – 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, 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 you 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.

Yeah.

All three targets within the same...

Sure.

(01:08:00)

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 there on that acreage. And again, this latest Avalon well just shows that.

Great. Thanks a lot for your comments. Thomas E. Jorden - Chairman, President & Chief Executive Officer: Thanks, Arun.

And ladies and gentlemen, at this time, we've reached the end of the allotted time for today's question-and-answer session. I'd like to turn the conference call back over to management for any closing remarks. Thomas E. Jorden - Chairman, President & Chief Executive Officer: 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.

Ladies and gentlemen, that does conclude today's conference call. We do thank you for attending today's presentation. You may now disconnect your telephone lines.