Welcome to the Cimarex Energy Second Quarter Earnings Conference Call. All participants will be in listen-only mode. Please note, this call is being recorded. I would now like to turn the conference over to Karen Acierno. Please go ahead.

Thanks, Amy. Good morning, everyone. Welcome to the Cimarex second quarter 2015 conference call. Last night, an updated presentation was posted to our website. We will be referring to this presentation during the call today. As a reminder, our discussions 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. Today's prepared remarks will begin with an overview from our CEO, Tom Jorden; followed by an update on our drilling activities and results from John Lambuth, VP of Exploration; and then, Joe Albi, our COO, will update you on operations, including production and well costs. Paul Korus and Mark Burford are also here in the room to help answer any questions you might have. With that, I will turn it over to Tom. Thomas E. Jorden - Chairman, President & Chief Executive Officer: Thank you, Karen, and thanks to everyone who's participating in today's conference. We appreciate your interest in Cimarex. I'd like to take a few minutes to share my thoughts on the current environment before turning it over to John and Joe for the details of our first quarter results and our plans for the rest of 2015. During this call, you'll hear about new wells that are outperforming our expectations, leading to another production beat. We now have 18 long laterals with over 30 days of production in the Delaware Basin Wolfcamp, several of which have been online for more than six months. We're gaining a much better understanding of the production characteristics and potential of these longer horizontal wells. The data we've gathered has strengthened our enthusiasm for the long-term potential…

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 planned activity increases. Cimarex invested $190 million during the second quarter drilling and completing wells. 66% was invested in the Permian region, and the rest went toward activities in the Mid-Con region. Company-wide, we brought 45 gross, 33 net wells on production during the quarter. Our Permian operations are in the Delaware Basin, where we brought on 16 of those 23 net wells during the second quarter, meaning we have now worked our way through the backlog of completions we had built up at year-end. That backlog was caused by some severe weather in the second half of 2014 and in addition to a lot more activity overall. We had 18 rigs running in the Permian region at 2014. We then dipped to a low of two in the second quarter, and are now operating three rigs with plans to add more. I'll share some of those details a little later. But first, we continue to have exceptional results drilling second Bone Spring wells in the Culberson White City area. We've drilled several wells using a larger, 15-stage completion with very favorable results, of which you can see in the presentation on slide 17. Cimarex recently completed a 7,000-foot lateral in the second Bone Spring sand section called the Klein 33 Federal Number 5H. This well had an average 30-day peak IP of 2,753 barrels of oil equivalent per day, which included 1,870 barrels of oil per day. This outstanding well result gives us greater confidence that a combination of our upsized completions along with the extended laterals in the second Bone Spring can generate superior rate of returns.…

Thank you. Our first question comes from Drew Venker at Morgan Stanley. 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 just provide a little more color on when we would get to that 16 rig program? Is that by January 1? And then if you can provide maybe just some bookends, general thoughts on volumes for 2016, whether we – should be accelerating growth somewhat similar to 2015? Could you help us there? Thomas E. Jorden - Chairman, President & Chief Executive Officer: Well, partially, yes. The rig ramp we have, all that John commented on, were – we had a plan there to ramp up so that we'd be essentially at 16 rigs as we enter the year – but we're obviously working our development projects and it's a flux issue. John, why don't you comment on that?

Yeah. As Tom said, we're not talking, of course, single individual wells now. We're talking lots of wells that we have to plan for. I think our latest schedule will have us at 16 rigs right pretty much at the beginning of February next year. But that can slide and move forward just depends on how well we put those plans together. But that's what it will show right now as of today. And then Mark Burford's here. I'm going to let him comment on production next year.

Yeah, Drew. Just in terms of production, with the fact that, as we mentioned, in the Permian, half our capital is going now transitioning from single wells, individual wells, and half our capital now will be going to infill development. And if you look at Culberson County itself, specifically the Wolfcamp D in Culberson County, three-quarters of our capital will be attributed to those infill development projects. So, we had a major shift in the complexion of our capital compared to 2015 to 2016. And as we point out on slide 16 of our presentation, those two secs – that six-section development – the first completions don't occur on that until June of 2016 and the northern sections don't complete until the first quarter of 2017. So, we definitely have a mixture change in the complexion of our programs, so the efficiency – previous capital efficiencies probably don't hold true going into 2015 as we transition to infill development. And production is delayed in those areas and even in Reeves County where we have infill development in Reeves County. So, our overall Permian program, half of it now is infill development. So it does have the impact, the major production are more lumpy and more backend-loaded. Joseph R. Albi - Chief Operating Officer, Director & EVP: This is Joe. Just a couple of comments there, too. When we have these development projects, depending on how many wells per section and how many sections, we won't begin completion operations typically until all the wells are drilled and completed. And Cana Row-4 is a great example of that. We drilled those wells all throughout the first half of this year. We're not going to see the production until the tail half of next year. To the extent that our development program becomes…

Yeah. This is John. A lot of debate, I would say, internally. I mean, what's nice is as I mentioned, we have those two spacing pilots. In addition, we have that stack pilot. We've incorporated those results. In addition, we have a lot of individual parent wells that have been landed in different zones within the D itself as well as the C. When we take all that information, we come away with a model that would clearly suggest to us that we have plenty of room within the D itself to stagger and stack, which is what we intended to do to start with, and feel very confident with that initial design, again, based on our spacing pilot results and based on leveraging that – the 7,500-foot laterals – that we're going to achieve very nice rate of returns. The way this schedule sets up then is we will get those online; we'll get early production from it. If it's meeting our expectation, then that just gives us even greater confidence to move forward to even more tighter, as you see in those follow-up sections. So, I would say that the two sections we call Sunday Silence, Silver Charm are somewhat dependent on the result of Assault and Sea Hero and that's why we built that schedule that way. But again, we really are looking at the results of those pilots and looking at our landing zone results from a number of other parent wells, and come away very convinced that this initial design is going to work very well for us in this interval. Thomas E. Jorden - Chairman, President & Chief Executive Officer: Yeah. I just want to remind you that this Wolfcamp is a really thick zone. And every play is different and has its own attributes. But in some plays, you worry about resource in place and the overall storage capacity. That's not the concern here in the Wolfcamp. The Wolfcamp is really a mechanical issue and what's the best way to poke straws in there, frac the wells and space them to recover it. So, we're – based on our experience – we're highly confident that this rock can support this development plan. Drew E. Venker - Morgan Stanley & Co. LLC: Just wanted to clarify again, I know in the past you had done a C and D stack test. Have you tested two laterals stacked or staggered in the D as of yet or is this the preliminary test of that?

Well, maybe I – let me just put it this way. I guess I would love that we go forward, that we don't even call it the C, D. We just call it lower Wolfcamp. Really, we don't – C and D is more of a geologic marker. What you really should think about is it being a very thick, over 500-foot to 800-foot thick interval, and that going forward, we're going to start with initial stack of two wells that we feel good about. And then based on results, then potentially add a third level to it with the next set of development. That's really what we're talking about here. Thomas E. Jorden - Chairman, President & Chief Executive Officer: Drew, we have tested stack in the Wolfcamp A in Reeves County.

Yes. Thomas E. Jorden - Chairman, President & Chief Executive Officer: And so that the analogy is direct here and John is absolutely right. In fact, our technical team is discouraging us from even using the nomenclature C, D. It really is one large section. Drew E. Venker - Morgan Stanley & Co. LLC: Thanks for the color, guys.

Our next question is from Brian Gamble at Simmons & Company. Brian David Gamble - Simmons & Company International: Hey, guys. Maybe we can jump to the other exceptional results for the quarter in either the Bone Spring or the Wolfcamp A, whichever one you want to tackle first. But I guess, specifically on the Bone Spring well, huge oil cut there. Anything other than the stages going up that you did differently in that well?

This is John. No. That one made use of what would be equivalent of a 15-stage for 5,000-foot lateral. The difference being is it was 7,000-foot. It's just an outstanding well and it's just – it's a replication of what we've been able to do in other areas with that particular design. I think what's exciting to me is we don't think we're optimized. We still think that there's perhaps still room to go with that frac design. And so, we do have further wells planned in the area to go in and test the limit of that design. So, it's just – the way I look at it is, again, a nice confirmation that we can take it and go a little bit longer with the lateral and still get a very good result. Brian David Gamble - Simmons & Company International: So essentially confidence in the repeatability is pretty high. Is that what you're saying essentially?

In this immediate area, yes, we feel very good about our acreage position and the well results there. Thus, why that was the first incremental rig we added was immediately to this type of drilling program. Brian David Gamble - Simmons & Company International: Great. And then, same thing kind of on the Wolfcamp A, you mentioned trying to more landing them in the upper part of the A. Was this the first landed in the upper or was this just the first long lateral landed in the upper part of the A?

Yeah. This would be our first long lateral, but I will remind you that we did have our spacing pilot which was the ANACONDA which was a stacked/staggered pilot where we had upper A and lower A. And right away, from those results, we could tell that that upper A zone was giving us superior performance to the lower A, even as you recall, we've talked about some issues with the landing the lower A. But even in the wells where we did not feel we had an issue, the upper A was clearly performing. But I will tell you than when we plan this well, we had high expectations for it, to the point that we even worked very hard as a collective group to make sure our production facilities, everything was in line for this well, because we had high expectations and it's met those expectations. We've been very pleased with that well result. We have a nice, large, contiguous acreage position there where this well is. And yes, we have plans now to go and see if we can't duplicate this result with a few more long laterals. Thomas E. Jorden - Chairman, President & Chief Executive Officer: But like the C, D, it's not either/or. I mean that A is a very fixed section and I anticipate multiple landing zones in the development scenario. Brian David Gamble - Simmons & Company International: And then, one last one from me, guys, the kind of extrapolation of your comment, cash flow plus $630 million and/or using the 16-rig count. That puts your capital up, by my rough math, at least 30% next year. Is that a reasonable starting point year-over-year?

Brian, this is Mark. I'm sorry, 30% what, increase in... Brian David Gamble - Simmons & Company International: In total capital.

Total capital from year to year. As you probably know, we constructed eight-rig program – actually it's based on a $50 oil price deck and a $3 gas price deck. And even at that price level, those price decks, we'd expect to have some remaining cash in the neighborhood of $100 million in excess at the end of the year. So, the $630 million, right now, the eight-rig program doesn't contemplate quite using all the equity proceeds. We expect to have some remaining cash at the end of the year and fund that program from cash flow. So, the absolute capital, we still would like to maintain some flexibility in that. But the eight-rig program at $50 and $3 price deck, we wouldn't expect to quite use all the remaining proceeds. Brian David Gamble - Simmons & Company International: That's helpful, Mark. Thank you.

Our next question is from Philip Jungwirth at BMO.

Hi. Good morning.

Hi, Phillip.

Good morning.

So, the Wolfcamp C, D development section you laid out in the presentation, I noticed it's focused in the northeast corner of your acreage block there in Culberson County. I know in the past you've talked about how the (38:00) you move west. So, as development eventually does move west and south, do you think this configuration of laterals and spacing is going to be applicable across the position or is it going to vary and can you provide some preliminary thoughts around that?

Yeah, this is John. It will vary. I mean, as you pointed out, we do recognize yield variations, and that will have to factor into both our rate of return and PV calculations as far as the development plans. The overall thickness itself is pretty consistent at least on that entire eastern side of our block, and then we do thin a little bit as we go to the west, but not to the point that I think we would lose a row necessarily. Again, I think it'd be more a matter of economics because, I mean, it is fair to say we do tend to lose our yield a little bit as we go to the west, but that would just be a decision we'd have to make at that time. I guess that would be how I'd answer it.

Okay. And I think you've talked also in the past about the C bench in Culberson being a bit lower return than the D or the A. So, is there a reason that the C's included in the initial infill development as opposed to a D/A development? And then, can you still come back at a later time and target those A bench reserves?

Yeah. I'll take a stab at that, and I know Tom's itching to answer it, too. Let me just make clear that from our well results, the Wolfcamp A in Culberson is mutually exclusive from the lower Wolfcamp C, D. So we can come back at any time and layer in wells and, say, in these developed sections in A and not worry about any type of impingement on those wells. So, that we've clearly have established from our drilling program. In regards to the C, D, it is fair to say that our well results do indicate that Cs tend to have a little bit lower rate of return, but we are fairly convinced that if we were to develop, we wouldn't need to do it all the same time. And so, that's why we have the plans you see there with those upper northern sections that we'd like to move forward with that and demonstrate to ourselves what kind of returns we would generate, and that full development pipe scenario, because I don't think we're convinced that we could come back and necessarily go in with the Cs at a later date. So that's why we're stepping into this the way we are with this plan. Thomas E. Jorden - Chairman, President & Chief Executive Officer: Yeah. The challenge here, as John mentioned, is we've really pushed our organization to say we want to take a long-term view of how we optimally develop this asset. And so to the extent that we can't go back later and get a layer, even though it may have a lower rate of return, we don't necessarily want to orphan it and abandon it for all time. And so, we're making those decisions on a case-by-case basis, but we're really trying to develop this asset with multi-year look so that we don't find ourselves in a position five or seven years from now looking back and saying, boy, I wish we had done this differently. And so, that requires a lot of forethought, a lot of planning, but we want to get that while we can.

Okay, great. And can you talk about the reason why the Culberson B/D development is going to be based on 7,500-foot laterals as opposed to two-mile laterals? Do you think medium-length laterals are optimal for development or did this just have to do with the acreage configuration?

No. This is strictly based on the way that our JVA was set up such that these particular sections were just three sections. So, for long laterals we have to divide it up in a section-and-a-half, nothing more than that. Our plans for the rest of the acreage is 10,000-foot. This is just a matter of just geography, just the way the sections laid out.

Great. Thanks, guys.

Our next question is from Irene Haas at Wunderlich.

Yes. My question has to do with the Reeves County, Upper Wolfcamp A. Is this a typical shale or are you really kind of looking for better porosity streaks within the Upper Wolfcamp A? And if yes, how continuous would the interval be?

This is John. This is a – it's a shale – the Wolfcamp of course is a shale with interbedded carbonates. The way we see it, there is some definite variability to it but for the most part I would say, in immediate area from our well results, we tend to see some consistency in well results from section to section. So, we do expect some repeatability. When we make a good well in a particular landing zone, if we are to move a section over, our expectation would be that we would still be able to achieve that type of result. As far as the Upper A itself, you know what, I'm just going to say, we do a lot of work with our rock data, our log data – and coupling that with frac design and well results – that help us internally get more comfortable with that Upper A, B and A an attractive target. And I'll just leave it at that.

So what do you see in specific that makes these wells so much better?

Well, to be honest, I'm not really going to answer that question. That's something we do internally. I mean, we work very hard with our technology to understand this, and so, I'll just sat be happy with our result and leave it at that.

Okay. I understand. Thank you.

The next question is from Jason Smith of Bank of America. Jason Smith - Merrill Lynch, Pierce, Fenner & Smith, Inc.: Hey. Good morning, everyone.

Good morning. Jason Smith - Merrill Lynch, Pierce, Fenner & Smith, Inc.: So, on the Avalon, can you just talk about the tests you performed there and the results you've seen so far? And I guess, I'm trying to see if there's a significant difference, particularly between the 6- and 8-well sections, that you guys have tested?

This is John. We did update our slide. For those who have the presentation, slide 19, although we didn't have comments in our opening remarks. But we're very, very pleased with the results from our pilots that we've drilled in the Avalon. And as we've mentioned, we tested a variety of spacing to help the Avalon. And I would just tell you that, on a go-forward basis, based on these results, we are very comfortable with eight wells per section within an individual bench. And in fact, see multiple benches as being opportunistic on quite a bit of our acreage. So we're very happy and pleased with that play. As we've mentioned several times, our acreage position is HBP [held by production]. There's no obligation drilling we have to do there. And it's a really nice thing to have in our back pocket that if we need to, we can throw rigs at it at any time. Thomas E. Jorden - Chairman, President & Chief Executive Officer: Well, I think, I might add there that in testing and delineating optimum spacing, there's an approach that says, you test it until you break it.

We haven't broken. Thomas E. Jorden - Chairman, President & Chief Executive Officer: We have not broken it yet. So there is a debate that eight wells is not tight enough.

That is a fair comment, Tom, that eight is a minimum at this point. Thomas E. Jorden - Chairman, President & Chief Executive Officer: Eight or more.

Yes. Jason Smith - Merrill Lynch, Pierce, Fenner & Smith, Inc.: Got it. So maybe, John, just to follow up on that, I mean, in your comments on HBP, I understand that. But your mix of CapEx, I think, for 2016 shows nothing at least at this point for the Avalon. Are you guys doing anything in the balance of this year? And as you said, I mean, what changes your opinion there? What makes you kind of go back to work and ramp in that area relative to somewhere else?

I will say we do have plans for another Avalon test, where we're once again going to land with a pad well and test a newer frac design that we think could even leverage better rate of returns. And outside of that, again, I think it's nice to have that flexibility of having that acreage sit there because quite frankly, not everything goes as planned. And so, it's nice to be able to throw rigs over to it when we need to or more importantly, if we need to deploy more capital. It's sitting there waiting for us and that's kind of how we look at it right now. Thomas E. Jorden - Chairman, President & Chief Executive Officer: Yeah, Mike. So, the way it looks from my desk is, as we manage our capital expenditures and come up with our overall capital plans, these development projects take a lot of capital. And so, not every great project is getting funded. So, please do not infer from the fact that Avalon doesn't have a bigger slice, that it means that we're – we like it any less. So, it's just you prioritize and these development projects are our top priority right now. Jason Smith - Merrill Lynch, Pierce, Fenner & Smith, Inc.: Thanks, Tom, I appreciate that. And on Ward County, I feel like I get to ask this question every quarter. Given the improvements you've seen in Reeves County, what, if anything, are you thinking about implementing there? I think you guys have mentioned where you have some HBP requirements in 2016. So, is there any capital going there or is that something that maybe you'd consider letting expire?

Well, as of today, we've really not come up with a way to achieve sufficient rate of returns in Ward County. It's just as simple as that. We always constantly monitor; there's still wells being drilled there by competitors. We keep a close eye on what they are doing relative to frac design, landing, length of lateral. But I – to be honest – we just haven't been able to come up with the right recipe to date that makes that an attractive rate of return for us. So, unless we see a major breakthrough somewhere, there's a good chance that we will not be able to hold that acreage next year. Thomas E. Jorden - Chairman, President & Chief Executive Officer: I want to just add to that, and Ward County is our poster child for why we want to do forethought on the development. Ward County, a lot of our acreage was developed in that Third Bone Spring; we had drilled horizontal wells prior to the ultimate potential of that Upper Wolfcamp being understood. Had we not done that, I think we would be developing Ward County. Had we not done that, I think we would be developing Ward County and we would be developing a Third Bone Spring in at Upper Wolfcamp. The problem with most of our Ward County position is we're drilling into a depleted fracture network in that Third Bone Spring. So, it's not to say we're disparaging the Ward County, we're not. If we didn't have that Third Bone Spring there, we'd be having a whole different conversation. Jason Smith - Merrill Lynch, Pierce, Fenner & Smith, Inc.: I appreciate the color. Thanks, guys.

The next question is from John Nelson at Goldman Sachs. John Nelson - Goldman Sachs & Co.: Good morning, and congratulations on a great quarter. Thomas E. Jorden - Chairman, President & Chief Executive Officer: Thank you, John. John Nelson - Goldman Sachs & Co.: Also, congratulations to Mark in his new role, and I guess best of luck to Paul. For my first question, is you guys talked about transitioning into 2016 into a development program, I'm just curious if there's any guidance on how we should think about infrastructure spend, either over the back half of 2015 or as we move into 2016? Thomas E. Jorden - Chairman, President & Chief Executive Officer: Well, I'll let Joe comment on that specifically, but we're studying that long and hard. And there's a lot of issues around infrastructure with gathering systems, how you develop your facilities and how you handle your water sourcing and water disposal. And we're looking at the full-cycle model in trying to really optimize the return on these projects. We're very wary of paving the future with gold bricks on infrastructure. We want to balance having the efficiency of taking advantage of the development and not overspending on upfront costs. So it's a bit of a balancing act and we haven't decided where we're going to land there, but we're trying – I will say this – we're trying to optimize our capital efficiency and minimize our infrastructure spending wherever we can. And Joe, you can comment on that. Joseph R. Albi - Chief Operating Officer, Director & EVP: I think, Tom, you hit it right on the head. In many, some ways, it's a matter of where we develop in these areas. And a majority of the big dollar infrastructure items have already been put…

Yeah. This is John. When we quote 2016, that's 2016 operated. So, it's fair to say we definitely anticipate quite a number of non-operated partner wells in the Woodford as we always have. Typically, they've been running around six rigs here recently. So, that certainly factors into our capital model as well in terms of what they plan to do in addition to what we will do. John Nelson - Goldman Sachs & Co.: Great. I'll let somebody else hop on. Congrats on the quarter.

Thank you.

Thank you.

The next question is from Ipsit Mohanty at GMP Securities.

Hey. Good morning, guys, and congrats, Mark, in person. Just a quick – I couldn't help but notice comparing slides of 1Q over 2Q that you're Permian was a tad gassier than – in 2Q than 1Q. Could you comment why?

Yeah. I'll take a stab at it first. I think you're just seeing, number one, if I think about the different programs, quite a bit more drilling in Culberson and the Wolfcamp, especially Wolfcamp D. And so that does tend to be a little bit more gassier than, say, Reeves County or other areas. Secondly, even the Bone Spring for us, traditionally a lot of our Bone Spring wells were more in New Mexico in terms of Lee, Eddy. We're still in New Mexico, let me be clear about Western New Mexico, White City and Culberson. They tend to be a little bit more gassier. But I will tell you, they're far better wells from a rate of return standpoint in terms of the type of productivity we get from those wells. So, I think that's just what's driving that slow change you're seeing and getting a little bit more gassier. It's just where the nature of our rigs have been on that western side of the Delaware Basin.

Okay. And then, I think you alluded to this in a separate question. But when you look at slides seven and eight – 2015, 2016 over 2015 – you said the Avalon would be missing because you have HBP and you have that description going into 2016. But when I look at Meramec and Bone Spring, two of the regions that you've highlighted in your presentations and seeing improvement, you see them sort of shrinking as a percentage of capital allocation. Is there something to read into that? Thomas E. Jorden - Chairman, President & Chief Executive Officer: Yeah. Development versus single well.

Yeah. I think number one, again, as we keep saying, when we go to development, whether it be Wolfcamp or Woodford, that's a major investment from a standpoint of deploying 17 wells or 20 wells. The Bone Spring itself, I think, from a capital standpoint, I don't think it's that much different from year-over-year. You're seeing just at our capital, the pie is bigger. We still plan to have a similar type healthy drilling program. The Meramec, I would say, yes, it's going to slow down because we've reached the point where we delineated, we think we feel comfortable where we have good rate returns from an individual well standpoint. But as I said in my comments, now we need to understand how do we develop it. And so, we have a number of major pilots ongoing between us and our partner, spacing pilots, stack/stagger pilots so we can better understand on our acreage how do we develop the Meramec concurrent with the Woodford. And so, that's why, prudently, we'll be slowing down some of the Meramec while we get those pilot results and understand how we move forward to get that acreage properly developed. Thomas E. Jorden - Chairman, President & Chief Executive Officer: I also want to add that this is a snapshot in time, and we want to give you color directionally as to where we see the remainder of 2015 and 2016 going. But it's by no means set in stone. And, for example, there is a chance that in this Woodford development, we may have a layer of Meramec to add to it. And so, we may increase Meramec along with the Woodford development. But we're still working our way through that, but we wanted to give you our best read today on the direction. We maintain a lot of flexibility as we work our way through this.

All right. Appreciate it. And then, seems like as you go over quarter-over-quarter, having followed you, it seems you've gotten very comfortable with the longer laterals across your asset base. Is going on from here, as you go forward the remainder of 2015 and 2016, what percentage of your drilling are longer laterals, just across Bone Spring, Wolfcamp and Woodford?

I'll take a stab at that. This is John. Essentially, all the Wolfcamp is extended laterals, I mean, pretty much where we can. I think the lone exception might be the occasional pilot where we find that we can achieve the answers we need from a capital standpoint through 5,000-foot instead of 10,000-foot. But outside of that, almost every Wolfcamp well, if the acreage allows us, is an extended lateral at least 7,500-foot to 10,000-foot. Woodford, traditionally, we have been a 5,000-foot lateral developer. But I will tell you, because of our comfortableness with drilling 10,000-foot, a lot of our future development plans that we review now incorporate 10,000-foot as our go-to for development. Now, that's not going to happen right away. But as Tom mentioned in his comments, we are looking at some areas, probably mid to later next year, that we will move toward long lateral development even in the Woodford. And again, I think that just speaks to something you mentioned. We're getting very comfortable with our ability to drill and complete and flow back those wells. Thomas E. Jorden - Chairman, President & Chief Executive Officer: And we've taken a little different approach than some of our competitors. To the extent that we're delineating or we're testing spacing, we prefer to do that with 5,000-foot long horizontal wells, get the results a little quicker and spend a little less per well while we're doing experiments. In particular, if you look at our Meramec program, Cimarex – our wells are dominated by 5,000-foot wells. Many if not most of our competitors, have chosen to go straight to 10,000-foot wells. We're fairly confident that that was the right decision for Cimarex.

Thanks. Congrats on another great quarter.

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

The next question is from Jeanine Wai at Citi.

Hi. Good morning, everyone. Thomas E. Jorden - Chairman, President & Chief Executive Officer: Good morning.

In your prepared remarks, you mentioned that you built your 2016 program around rate of return given that you don't have a crystal ball on future prices. So I was wondering if you could just give us an update and rank in order of rate of return in your plays. I know in the current presentation you gave an updated 78% rate of return for the Culberson Wolfcamp D. So how can we slot in the other programs like the Wolfcamp A, Reeves A, Bone Spring, Cana Infill, et cetera?

Yeah. This is John. I think before I answer that, again, there are so many moving parts that go to building that program, that clearly, yes, rate of return is one of the first things we look at. But there are obviously other mitigating factors such as takeaway concerns, obligation drilling to hold acreage. So there's many things that go into that program. So, I just want to be clear about that, but rate of return is certainly one that we focus on strongly. From a program perspective, right now, first and foremost, White City, Culberson, Bone Spring wells generate by far superior rate of returns, and we're very pleased with where we are with that program. Once you step from there, the long lateral Culberson program, as you mentioned, is very healthy, looks very strong for us going forward, both in the A and in the D, which we've gotten very good results recently from the A now. So, we literally have two different intervals generating very strong results. I would argue now with the latest results from Reeves, with the well we just spoke about, if we can continue to duplicate that type of result in that Upper A, then Reeves becomes extremely competitive relative to Culberson with that type of result. And then finally, you get to Woodford, where Woodford, right now, are very, very good rate of return results. I think what excites us about the Woodford is what I mentioned earlier, when we start thinking about it from a long lateral standpoint. When we look at Woodford and we look long lateral, then those returns all of a sudden get to a point we get very excited about relative to, say, a Culberson long lateral. So, that would be just my take on it, based on the current commodity price and what we see going forward. Thomas E. Jorden - Chairman, President & Chief Executive Officer: And then, I also want to add and I think everybody knows this. When we talk about rate of returns, to the extent we quote a number, those are what's being called half-cycle returns. Those are drilling-only returns. They're not burdened by all the other things that make up a true investment profile. But there'd be incremental decisions that we make every day.

Okay. Great. That's all for me. Thanks very much. Thomas E. Jorden - Chairman, President & Chief Executive Officer: Thank you.

Our last question is from (01:03:42).

Good morning, guys. Just a few on the Meramec, just wondering – there's, I guess, a pilot, doing an 80-acre downspacing test that you guys had an interest in, if you had any kind of feedback on that result yet?

This is John. No. We have no comments to make about that pilot as of yet. We're carefully monitoring but no comments.

Okay. And then, John, I guess the location of those downspacing and stack tests in the Meramec, are those going to be in the up-dip or down-dip sections?

They are in the up-dip, as far as the spacing pilot, as well as the stack test, they would be in what we have called the up-dip. Yes, that's where they're located.

All right. And then just last one for me. There's been some talk about the variability of the geology in the Meramec across the play. Just wondering if you guys think that your acreage is going to be fairly consistent on the characteristics?

Well, this is John. I would say again, to date, we've been very pleased with the results of our wells. But I will point out that we have 10 wells that go into our average. It is fair to say that of those three new wells, one of them was quite a bit of a step-out for us. And yes, it underperformed relative to the rest of the wells. That's what happens when you try to delineate your acreage. And so, there's no surprise that we have reached a point where at least with that well, we would start to think that maybe that particular area is not as prospective as others – from a 5,000-foot standpoint – let me be clear. We do recognize there's a variability to this, but I would also again point out that we've been pleased with the overall consistency of our results to date. Thomas E. Jorden - Chairman, President & Chief Executive Officer: But the – John mentioned the three new wells – two of the three were choked back during a significant portion.

Yes. So, to be clear, of the three new wells, one of them was a significant step-out that definitely underperformed relative to our average. The other two wells, just to give you a little color, are wells that are in an area that we consider very prospective. We upsized the fracs quite a bit on both those wells and because of that, we're trying to manage the flowback on those wells from a standpoint of both water and sand control. Those wells were conservative on their choke settings, thus, we didn't achieve the same kind of 30-day average rates that the other wells have. But we're very pleased with those well results, those two wells, based on what we're seeing to date.

All right. I appreciate it.

This concludes our question-and-answer session. I would like to turn the conference back to management for closing remarks. Thomas E. Jorden - Chairman, President & Chief Executive Officer: Yeah. I want to thank everybody for joining us. And in closing, I'm glad it was mentioned in our call, I want to congratulate Mark Burford on becoming our CFO. He's ready for the job and will just do a fantastic job. But I especially want to commend Paul Korus for the contributions he's made to this organization over time. Many of you on this call know Paul well. We're going to miss him deeply. It would be impossible for me to overstate what he's meant to this organization, to our shareholders, and to the building of Cimarex. It's with a lot of bittersweet that we let him go. We're going to miss him. And part of the great contribution that Paul has given us is grooming and choosing his successor. But Paul's contribution is something that we're very grateful for. And I know many of you share me wishing Paul all the best and just deep, deep gratitude for the role he's played as a founder of this company. So with that, I want to thank him very much. Paul Korus - Outgoing Chief Financial Officer & Senior Vice President: Thank you.

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