Good day, ladies and gentlemen, and welcome to the SM Energy Third Quarter 2015 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, there will be a question-and-answer session and instructions will follow at that time. As a reminder, today's call is being recorded. I would now like to turn the conference over to David Copeland, General Counsel. Sir, you may now begin. David W. Copeland - Secretary, Executive VP & General Counsel: Thank you, Shannon. Good morning to all joining us by phone and online for SM Energy Company's third quarter 2015 earnings conference call and operations update. Before we start, I'd like to advise you that we will be making forward-looking statements during this call about our plans, expectations and assumptions regarding our future performance. These statements involve risks that may cause our actual results to differ materially from the results expressed or implied in our forward-looking statements. For a discussion of these risks, you should refer to the cautionary information about forward-looking statements in our press release from yesterday, the presentation posted to our website for this call, and the Risk Factors section of our Form 10-K that was filed earlier this year and our Form 10-Q filed earlier this morning. We will discuss certain non-GAAP financial measures that we believe are useful in evaluating our performance. Reconciliation of those measures to the most directly comparable GAAP measures and other information about these non-GAAP metrics are described in our earnings press release from yesterday. Company officials on the call this morning are Jay Ottoson, President and Chief Executive Officer; Wade Pursell, Executive Vice President and Chief Financial Officer; and Jennifer Samuels, Senior Director of Investor Relations; and myself, Executive Vice President and General Counsel. I'll now turn the call over to Jay.…

Our first question comes from David Tameron with Wells Fargo. You may begin.

Morning. Javan D. Ottoson - President, CEO, COO, Director & Executive VP: Hey, Dave.

Hey. So if I look at this, I was just looking at that slide you provided. And tanks for that. Slide 27, where it's got the DUCs versus, it's got the full completion schedule. And where I'm going with this is just obviously everyone's focused on what your production mix is, quote unquote. And it looks like there's a higher percentage of DUCs that are more oily if you will, than what you've got on the Eagle Ford. So if I just think about the next couple quarters and then think about 2016, it feels like you have to get oilier. Can you talk about that at all? You don't have to get oilier but it feels like your mix is going to get a little bit more oilier going forward. Could you talk about that and put any guideposts around that at all? Javan D. Ottoson - President, CEO, COO, Director & Executive VP: Sure, Dave. No question. If you look right now and you say, okay, what's the most economic thing to do in our portfolio, going to complete those DUCs is it. And we're going to be aggressive in going after those. Specifically, most of those DUCs are in the Bakken, where we had rig contracts this year that were expiring. So we've compiled up a whole bunch of Bakken DUCs there. So we're going to start completing those. I think we'll be starting in December some time to complete those wells. We're going to try to get a few of them done before the winter weather. Depending on how the winter looks we'll work through the winter or we might take a break in January sometime when it gets cold. But we're going to start those DUC completions during the fourth quarter. You know, we have always – I want to back up a little bit. We have always said that our mix in 2016 would look very similar to 2015. So we sold some gassy assets in 2015. So clearly we were anticipating the fact that as you kind of balance this out, the Eagle Ford's a big operating part of our business, that the mix would get slightly gassier in the early part here as we made this transition toward picking up Permian rigs and completing the DUCs. We've always, our budget, frankly our oil rates this quarter, were very close to our budgeted levels. We just made a lot more gas than we expected to. I think we will be down a little bit and then we start coming back up and as we start to grow toward the back half of 2016 a lot of that growth is going to be oily growth as we complete Permian wells and we get our DUCs completed, and our Bakken activity is basically going to be flattish, two rig kind of program for the year. So what we see here happening is that we do get oilier throughout the year of 2016.

Okay. No, I appreciate that. And then one follow-up on the Eagle Ford. Just based on these tests, or can you talk about if you have say, three rigs going into 2016 or whatever number, three to four rigs. Based on these tests, do you need more data from these tests before you start drilling everything on 450s feet or how are you thinking about the development plan for the next, call it two to three quarters? Javan D. Ottoson - President, CEO, COO, Director & Executive VP: You know, I think in that eastern area we're going toward 450s feet. That's where we're going. We still have a number of pilot wells to be drilled there. We've got some down spacing wells to drill or infill wells to drill and we have a number of pilots to complete, that when we move toward this development in that area, I'm pretty sure we'll be at 450s feet if not tighter. Frankly, I'm really excited about where this 312 foot offset test goes. And pilot #2 if you remember, is the infill test, which we have yet to have results there. So that's again, the very best geology and the play is that eastern area, and it looks to us like it's going to get tighter. So that's a good thing. I think we'll probably be at about three rigs in the Eagle Ford for most of next year. And a lot of that activity will be getting these pilots drilled and moving forward, starting to move forward on what happens from the results of those. So if you look at rig count, we're at seven rigs. I think in general if you're thinking three rigs in the Eagle Ford, two rigs in the Bakken. We're going to start out at one rig in the Permian, I think we'll maybe at two within a quarter or so. So that kind of seven rig number. We're going to be transitioning our rig out of the Powder River Basin early in the year. And again, I think that activity will end up in the Permian. So it'll be a kind of three rig Eagle Ford, four rig oily kind of program for most of next year.

Okay. I'll let somebody else jump on. That's helpful. Thanks, Jay.

Thank you. Our next question is from Welles Fitzpatrick with Johnson Rice. You may begin. Welles W. Fitzpatrick - Johnson Rice & Co. LLC: Hey. Good morning. Javan D. Ottoson - President, CEO, COO, Director & Executive VP: Good morning. Welles W. Fitzpatrick - Johnson Rice & Co. LLC: Two quick ones on the Eagle Ford. One, just for my own clarification. You guys, are you guys downshifting the operated Eagle Ford or is that just really the non-op that's allowing you to put a little bit more capital toward the Permian and the Bakken? Javan D. Ottoson - President, CEO, COO, Director & Executive VP: Well we've said, and I said yesterday we're going to go from four rigs to three rigs at the beginning of the year in the Eagle Ford. That's our current plan there. We only need to run about a 2.5-rig program I think to hold all the acreage and meet all our commitments there. So, about a three-rig program. And just to balance the capital out, in order to put the rigs in the Permian that we want and with the fact that we'll let the non op Eagle Ford is coming down, most of the caps are actually coming from there. That's how it will balance out, about a three rig. We'll probably have four rigs sometime maybe in the Eagle Ford during the year, but three rigs there and four rigs in the oilier stuff during 2016. Welles W. Fitzpatrick - Johnson Rice & Co. LLC: Okay. Perfect. And just one more. The 25% bump in location count that you guys talk about with 450-feet spacing, does that include infill drilling, like in test #2? Or is that just on relatively undrilled acreage? Javan D. Ottoson - President, CEO, COO, Director & Executive VP: That's just on undeveloped. I should always say that when I quote that number. The 25% uptick is just taking what we had currently had planned to drill at 650 foot, or 625 foot and 550 foot, taking those areas to 450 foot. And again, we still need to prove that in the northern area, but I'm pretty comfortable with that kind of spacing right now in the east, and again very encouraged about where this 312-foot offset testing might go as you stack stagger. I think what's really notable, as I said earlier, that the Upper Eagle Ford wells in that new pilot look as good as the Lowers. So, really encouraged by that result. Welles W. Fitzpatrick - Johnson Rice & Co. LLC: That's perfect. Thanks so much.

Thank you. Our next question comes from Subash Chandra with Guggenheim Securities. You may begin.

Hey, Jay. I'm just trying to think about the map here on infills. So when I see the 420-acre infills and possibly – foot, I'm sorry, possibly going to 300 and change, so that implies somewhere, 10 plus, maybe up to 10 to 14 wells per 640, just on the simple math there? But then when I look at the anticipated gas EURs out in the east, I believe that curve was six or seven Bs. And just tell me where I'm wrong here, but if I think about the type of total gas that you're expecting to recover on your 10 to 15 wells at six to seven Bs, it would be an exceptionally high recovery factor of gas in place? If I'm thinking of gas in place correctly, around 150 Bs per section, but – so I threw those numbers out there. Please correct me on where I'm not dotting my Is and Ts. Javan D. Ottoson - President, CEO, COO, Director & Executive VP: I don't know what you're using for, if the in-place numbers is the problem. We think we can get to 50% type recoveries in that area, in a gassy area. So I don't know what you're using for in-place numbers.

Okay. So... Javan D. Ottoson - President, CEO, COO, Director & Executive VP: What we've seen here, say, the Woodford where we had a pretty gassy kind of bias there in that production. We, well in excess of 40% type recoveries in that area. In oilier areas of these plays, you're going to be more like 10% to 20% recoveries. And that's frankly why these wells are so productive. You've just got a lot more throughput capacity inside the rock to be able to do this. So the gassy areas tend to get much higher recoveries. It's not as high as conventional numbers but they're pretty darn high relative to the oily parts of these reservoirs.

Okay. So as we adjust our expectations for the west, we probably need to adjust that, say, from I think the numbers – so 40%, 50% type recovery factors, you would think up to 20% in the oilier parts of the play? Javan D. Ottoson - President, CEO, COO, Director & Executive VP: Well, I think 10% to 20% is probably not an unreasonable number. And I will tell you the difference between 10% and 20% is a huge number. And a lot of that's going to depend on the success of these stack stagger tests. I think the low numbers that you hear from a lot of people, if you go to Permian or some of these other plays, you're more like 4% to 8%. But again, we have a little more gas drive here so I think you're likely to get higher recoveries. I think what we've come to the conclusion of, originally when we did the work in the Eagle Ford, we weren't sure the Upper Eagle Ford really had that much pay. It was really whether it was really reservoir or not. We know the porosities are lower. What we're finding out is it's actually productive. So I think our general feeling is that the recoveries are going to be higher than we had originally anticipated in some of this rock, just going through this stack stagger completions.

Got it. So you think throughout your Upper Eagle Ford there is a meaningful amount of self-sourcing taking place, rather than just migrative ...? Javan D. Ottoson - President, CEO, COO, Director & Executive VP: Yeah, and I'll tell you why I think that. We are seeing in some of these areas, higher yields in the Upper than in the Lower, which would tell you that the maturity is probably lower in the Upper, I think, which would imply self-sourcing. Right. So I think that all that tells you that that rock up top there, actually is a self-sourcing reservoir, did have – maybe didn't get heated quite as much but that it's not necessarily just a receptacle for Lower Eagle Ford production. It actually does self-source to some extent.

Got it. Okay. So then that's interesting. So we shouldn't then just assume that where you have dry gas Eagle Ford that you will have dry gas Upper Eagle Ford. Javan D. Ottoson - President, CEO, COO, Director & Executive VP: Well, I think in the dry gas section, that stuff's been heated up. It's not going to be materially different in terms of yield. But as you go north, I think there will be significant – and we have seen some tests where, at least on initial tests, you'll see significantly different yields between the Lower and the Upper. And the Upper is always higher. So that's one of those wild cards as we go through this testing for the pilot testing program and start really completing a lot of wells in the very upper portions of the Eagle Ford, what's that yield going to be? Generally, it's going to be higher. I don't know, again there's this balance between productivity and yield on the economics of these wells, that's really what we're testing here.

Right. Right. But do you think an offsetting characteristic versus yield and productivity, or versus productivity Upper Eagle Ford is just that you might have a better reservoir rock interbedded with the source rock, so it's easier to produce? Javan D. Ottoson - President, CEO, COO, Director & Executive VP: We know that some of the facies in the Upper are actually more brittle than the Lower and they frac easier, frankly, than the Lower does. Now the frac recipe might end up being little different in the Upper than it is in the Lower, so we may have to spend some time exactly getting that right, but we know the Upper Eagle Ford's productive. And doing the foot by foot kind of work we do, petrophysical work, there's a lot of really good brittle rock up in that Eagle Ford. So we've seen that Upper Eagle Ford wells that are every bit as productive as Lowers. And there's a tradeoff, I think between, the porosity is a little lower up there so the storage may be a little lower, but you may be able to make better completion. So at the end of the day what we're seeing, so far at least, is that the Uppers and the Lowers look about the same in terms of projected EURs. And so there's kind of a tradeoff there, I think between fracability, I'll call it, real technical term and storage that actually makes the well work out about the same. But I do think in general, the yields in the Upper are going to be higher.

Okay. And the final one for me on your lateral targeting. Is it specifically sort of the less shaley intervals of the Wolfcamp "B" that you you're targeting? Javan D. Ottoson - President, CEO, COO, Director & Executive VP: Well, it's the more brittle rock. It's really a mechanical properties issue. And there's probably, three different landing zones, I think that we've targeted within the Wolfcamp "B". Turns out that the lower one and the upper one perform better than the middle one. And that's probably as far into the technical details as I can get on that.

Okay. Good. Terrific. Thank you. Javan D. Ottoson - President, CEO, COO, Director & Executive VP: You bet.

Thank you. Our next question is from Michael Hall with Heikkinen Energy. You may begin.

Thanks. Good morning. Javan D. Ottoson - President, CEO, COO, Director & Executive VP: Good morning.

Just wanted to talk a little bit more about, I guess the DUC inventory and how you're thinking about the pace of pulling that down in the various areas in 2016. In the Eagle Ford you've got 64 DUC, 47 DUC in the Williston. Are you going to pull those down at a similar pace? Or will you have a regional bias early on with the Williston and then the Eagle Ford is later in the year? Javan D. Ottoson - President, CEO, COO, Director & Executive VP: Generally the pace is going to be faster in the Bakken. We're going to go after the oily ones early. The Eagle Ford, we always have a higher level of drilled but not completed wells there anyway and that'll be pretty steady through the year, but right now the most economic thing in our portfolio is to go complete Bakken DUC wells. And we're going to do that starting here right at the end of the year and try to get a few of them done before the weather turns bad and if the weather doesn't turn bad we'll just keep right on going. So I think we'll probably have most of our Bakken DUCs completed by mid-year.

Okay. And then in Permian, similar story? Javan D. Ottoson - President, CEO, COO, Director & Executive VP: Permian, again, a very similar situation. As we pick up the rig in January we're going to immediately start completing DUC wells and that'll be a very – we'll get those done, I would think, in the quarter, the first quarter.

Okay. Javan D. Ottoson - President, CEO, COO, Director & Executive VP: And then we'll be completing basically along with our drilling program. And I'm really thinking that the way this could work out is we end up picking up a second Permian rig, maybe second quarter. Just want to get – we want to start these rigs up one at a time and kind of get our feet under us there, but I think you could have higher activity levels in the Permian by the time we get into the second half.

Okay. And how should we think about, given the rig count numbers you provided, three rigs in the Eagle Ford, two in the Bakken, one to two in the Permian, what's kind of a normal backlog relative to those rig counts, would you say? Javan D. Ottoson - President, CEO, COO, Director & Executive VP: Well, we were pretty normal coming into this year with where we were. I mean we really didn't start building DUCs intentionally until the beginning of this year. So if you look at look at that DUC count at the beginning of that slide – which by the way those numbers changed a little bit just because we decided to track pad wells versus individual wells a little differently. But that count we had at the beginning of the year, which I think we count now as 60 DUC. Is that right, Wade? 60 DUC coming in the year? It was 40 DUC, the way we used to count them. A. Wade Pursell - Chief Financial Officer & Executive Vice President: That's about right. Javan D. Ottoson - President, CEO, COO, Director & Executive VP: Yeah. So that level is a pretty normal level for us and most of that is Eagle Ford, but that's pretty much where we would expect to end the year, in 2016.

Okay. Got it. And as you kind of look at oil volumes in 2016 you had a small sequential decline this quarter, seems like that probably happens again the fourth quarter, or potentially anyway. So how long until you get, you think, the oil volumes back up to the 2Q level would you say? Javan D. Ottoson - President, CEO, COO, Director & Executive VP: Well, again, when you start – we forecast overall our production is going down in the fourth quarter. We do have this big pile at the Eagle Ford coming on right now, so how much oil is generated by that in the fourth quarter is a little bit of a question. In general, I think what you'll see is our production in general is going to decline for the next couple quarters and then start back up. A lot of what – when we start coming back up, a lot of that will be oily because we're completing the DUCs and then we're getting back into the Permian. So when you get to the back half of 2016, our rate should be growing. A lot of that will be a little oilier than it is today. So again, year-over-year we think our mix on average is going to be about the same. I would agree I think we're going to be at sort of this little lower oily level here percentage-wise for a couple quarters and then it's going to start back up as we get those wells completed.

Okay. That's helpful color. And then in the Williston, looking at the DUC net to gross and the net to gross in the year-to-date completions, a bit higher than I think your average working interest typically in the Divide County area. Do you expect – I'm assuming there's some non-consents going on there. Do you expect that to continue? How should we think about that for 2016? Any indications from your offset partners on that? Javan D. Ottoson - President, CEO, COO, Director & Executive VP: Well, there's sort of a special situation there in that one of our partners is having financial difficulties in Divide County, and so I don't know how to project exactly what they will do. Certainly we're prepared to accept their interest in these wells and that's what we've been doing. To be clear, while we earn when we do that, is we pick up their interest up front and they get back in after like three times payout. I don't remember the exact number. So it's not like we earn their acreage, it's just – it's a well bore thing. It works out economically for us because these are good wells and I feel sorry for them, but they may very well, if they get their act together, start coming back in and participating at some point. So we're not – we're doing our budgeting based on the idea that some of that will occur, but not maybe as much as this year.

Okay. That's helpful. And then last I guess on my end, I was just curious, can you run through kind of what the current AFEs are running in the Divide, McKenzie, Eagle Ford and Midland Basin area, just as we think about, I guess, where you're allocating capital for 2016? Just trying to make sure I've got the most real time costs there. Javan D. Ottoson - President, CEO, COO, Director & Executive VP: Well, AFEs in Divide County are – I've got – actually, I have some really cool numbers here. All right. So let's see, Divide County is $4.6 million. That's our current projected well costs.

Okay. Javan D. Ottoson - President, CEO, COO, Director & Executive VP: Yeah, and I would say – is that with or without? A. Wade Pursell - Chief Financial Officer & Executive Vice President: With. Javan D. Ottoson - President, CEO, COO, Director & Executive VP: That's with plug/perf, yeah. Some of that, I will say that $4.6 million assumes we renegotiate our rig contracts, which we're doing. So right now, I think our well cost is probably right at $5 million. We will be at $4.6 million here as soon as – and those rigs will get done here before the end of the year. So Lower Spraberry type wells in the Permian, our current estimates there are about $7 million for a 7,500-foot lateral. I will say this, we pump big fracs here, a couple thousand pounds per foot, probably bigger than most people. We found at least in our Sweetie Peck area that that's very helpful. We would like to drill even longer. If we could, we'd drill all 10,000-footers. I think we'll be able to do some of that there, but generally, if you're using $7 million, that's a pretty reasonable number we think for our current estimates. And we're not drilling right now. We're bidding rigs right now and picking those up. And in the Eagle Ford East, our earliest well costs there are in the mid fives, $5.4 million for a 6,500-foot lateral. I mean, these numbers have come way down. So, very pleased with our cost performance in general.

Okay. Very good. Actually, one more if I might. In the DUCs in the Eagle Ford, do you know roughly how those are comprised, or like what the composition of that is relative to northeast, south? If not, I can follow up later. Javan D. Ottoson - President, CEO, COO, Director & Executive VP: Yeah. Well, most of those are in those pilots that you can see on that sheet. But if you look at those pilots and where they're located, you can pretty well figure it out.

Okay. Fair enough. Javan D. Ottoson - President, CEO, COO, Director & Executive VP: Most of those wells are drilled. It's just that they aren't all completed yet.

Got it. All right, thanks very much. Javan D. Ottoson - President, CEO, COO, Director & Executive VP: You bet.

Thank you. Our next question is from Mike Kelly with Seaport Global. You may begin.

Hey, guys, good morning. Javan D. Ottoson - President, CEO, COO, Director & Executive VP: Hey, Mike.

Hey, Jay. I was just hoping you could maybe kind of further frame and set expectations for all the tests that you're doing in the Eagle Ford. And I kind of think of it as three things going on, testing, spacing Upper Eagle Ford's viability and really what you're going to see from enhanced completions here. And I'm curious on really how long you think it'll take before you can lay out to the market, what all this work should translate to in terms of kind of updated EURs, project returns and really an ultimate inventory number in the play. And is this something that we should expect kind of being piecemealed out here over the next few quarters, or should we set a date for more of a comprehensive update? Thank you. Javan D. Ottoson - President, CEO, COO, Director & Executive VP: Well, I'll start with the last part first. I think you can probably expect it's going to get piecemealed over a few quarters. In a general sense, as I've mentioned earlier the gassy stuff is easier to get data on early because these wells come on pretty big early, they clean up fast. You need about 90 days of really good stable production before you can forecast EURs and get a real sense of how effective that was. The oily side wells, typically between that time period again end up need an artificial lift. It takes longer to get results. And so the northern stuff in the earlier parts of the plays, it takes longer to get the data. I recognize that's what everybody wants is that oily data, so do I. But it's just going to take us longer to get there. Inventory by itself this year is going to be an interesting thing. Obviously,…

Got it. Really appreciate that color. That's all I've got. Thank you.

Thank you. Our next question is from Pearce Hammond with Simmons. You may begin. Pearce Wheless Hammond - Simmons & Company International: Good morning, Jay. Thanks for taking my questions. Javan D. Ottoson - President, CEO, COO, Director & Executive VP: You bet, Pearce. Pearce Wheless Hammond - Simmons & Company International: Jay, previously you made the statement on 2016 that you thought you could grow production from exit rate 2015 to exit rate 2016, and that was keeping CapEx and EBITDAX aligned. Is that still the case? A. Wade Pursell - Chief Financial Officer & Executive Vice President: Hey, Pearce. It's Wade. I'll take that first, and let Jay add anything he wants. I guess the first thing I would say is I think we still could. But obviously since we made that comment prices have fallen, especially natural gas. That comment, the growing production part at least, that is more of an outlet of our program. As you know our priority is to maximize EBITDAX not production, and our capital plan is going to be very returns focused and returns based. So we're going to be working that hard over the next couple of months. And that's kind of where we are right now. Pearce Wheless Hammond - Simmons & Company International: Great. Thank you for that color. Then with the planned completions of some of these oily DUCs towards year-end 2015, will that result in some carryover CapEx into 2016? Or is that spending for completing the oily DUCs already in your 2015 capital budget? Javan D. Ottoson - President, CEO, COO, Director & Executive VP: Yeah. It's not that much money, Pearce. And again, I don't anticipate seeing overspending, what we've already said. The non-op Eagle Ford is slowing down, frankly a little faster than they…

Thank you. Our next question comes from Jeb Bachmann with Scotia Howard Weil. You may begin. Jeb Bachmann, your line is open. Please check your mute button.

Yeah. Sorry. Morning, everyone. Javan D. Ottoson - President, CEO, COO, Director & Executive VP: Hey, Jeb.

A couple quick ones from me, Jay. First on the Permian. Can you tell us what technology you're using to better land laterals and kind of what that's doing to the cost there per well if anything? Javan D. Ottoson - President, CEO, COO, Director & Executive VP: I'll answer the last part first. What we found is that the drillers never want to have a really tight landing zone because the argument is well, it costs more, you've got to work harder on directional. What we found is that in general we're able to do it with very little incremental cost because we're – tools are good enough now and we're good enough to be able to do that. The way we'd address landing zones is really we have taken a lot of core, we have done a lot of log core correlation and we're looking at this stuff foot by foot to look at what are the different facies in each of these different shales, which is not only true in the Permian, it's true in all these areas we're operating in. And we really look the mechanical properties of the rock across that whole interval, the porosities across that whole interval, all the good geologic data we can collect. And we target then which of these things is going to have the highest penetration rate and the best brittleness, I'll call it, on frac. And there is some tradeoffs in that. But in general in the Wolfcamp "B" there's about three different obvious landing zones there from top to bottom and what we found, and I think it's really interesting, is that if you're landing in the bottom or the top, you make – you have higher fee rates and better wells than if you land in…

Should we expect a down-spacing pilot test maybe in the Permian here in the next year? Javan D. Ottoson - President, CEO, COO, Director & Executive VP: Well, we've actually done some. We've drilled down to 660 feet already in the Permian and what you'll start to see from us is more of a stack stagger chevron development in some of this. Early on here in the first few wells we still have some non-pad wells we'll drill, but once we get the pad drilling you will start to see, I think when we pick up that second rig it will be when you probably start to see it. Some multi-well kind of pad development that would be sort of a staggered chevron type opportunity.

Okay. And then I guess the last one for me, just on the cost side. Do you guys see another 5%, 10% coming out of service costs at this point or do you think that you've seen as much as you're really going to get at this point? Javan D. Ottoson - President, CEO, COO, Director & Executive VP: Well, I think you'll see, if prices stay where they are you're going to see costs go down. No question. I don't know about percentages. But and you can look at, I think that plot, actually that we're showing there of our costs over the year is pretty instructive. Our third quarter costs are down from our average for the year still. We see a lot of pressure per cost to go down if prices stay low. If prices don't stay low, I think you'll see costs come back up fairly quickly. One of the best indications we have of what the service companies are thinking is they're not real excited about signing contracts that are much longer than six months to a year right now. Because I think they think things will get better. But in the near term I think costs are still on that downward trajectory unless prices change.

So I guess just this last one following on that. Just based on your comments earlier and kind of the slide deck, it looks like the Bakken has the best chance of keeping costs lower than the Eagle Ford maybe because you're seeing more internal operational efficiencies in the Bakken, is that fair? Javan D. Ottoson - President, CEO, COO, Director & Executive VP: No. I don't think that's fair. I think the issue with the Eagle Ford is we've been at a fairly high activity level for quite some time. We've driven, we are very efficient already there, so I guess from the standpoint of can we get better, faster in the Bakken, maybe there's a little more of that. On the drilling side, we continue to make really good progress in the Eagle Ford. On the completion side, we've been doing plug/perfs, cement liner completions for a long time and we're really good at it. It's hard to see us pumping a lot more stages per day versus what we're already doing. We're already doing a pretty spectacular job. So from that standpoint maybe you don't get a whole lot more efficient there. If we do go to these, for example, if we go toward this pilot where we're literally drilling 12 wells in a half section, I think you could anticipate some cost efficiencies associated with a more intense pad drilling environment that could benefit us, but that's probably more than a year out for us right now because we're still in the pilot stage.

Great. I appreciate it, Jay. Javan D. Ottoson - President, CEO, COO, Director & Executive VP: Yeah.

Thank you. Our next question is from Paul Grigel with Macquarie. You may begin. Paul Grigel - Macquarie Capital (USA), Inc.: Hi. Good morning, Jay. Just to follow-up on a point from earlier on, on the oil production in 2016 from exit rate to exit rate at current strip would it be fair to assume it's probably flat from exit rate to exit rate on the oil side with kind of a dip and then an increase in the back half of the year? Javan D. Ottoson - President, CEO, COO, Director & Executive VP: Yeah, that's probably within the range of accuracy that we can call at this point. That's probably fair. You've got the non-op Eagle Ford coming down some clearly and you've got us shifting capital at least that capital plus a little more to the oily stuff. I think it is going to be back-end weighted because of completion of the DUCs, but within the level of accuracy that we can predict things I think your characterization is probably fair. Paul Grigel - Macquarie Capital (USA), Inc.: Okay. And then on the northern test in the Upper Eagle Ford when we look at where those wells are, are they all fully completed and flowing back at this time or are you just accumulating data? Could you just give a little bit of color on maybe where they stand if we're still waiting on completion just realizing ...? Javan D. Ottoson - President, CEO, COO, Director & Executive VP: We just started our flow back, I mean literally within the last couple of weeks. It took a long time to get all the wells completed and so we're just getting the wells flowing back and I anticipate a significant period of time to get them cleaned up…

Thank you. Our next question comes from Matt Portillo with TPH. You may begin. Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc.: Good morning, guys. Javan D. Ottoson - President, CEO, COO, Director & Executive VP: Hey, Matt. Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc.: Just a quick question on the full year guidance, just wanted to make sure we're thinking about Q4 correctly. Jay, I think you previously talked about a couple percent quarterly decline in the back half of the year. So, just wanted to true that up with the Q4 numbers here. And I think you mentioned essentially going on a pretty solid frac holiday across all of your assets. And I guess a second follow-up to that question. Just as we think about your corporate profile, how should we think about the PDP decline rate? Because it looks like the Q4 number might be mirroring that to some degree. But just trying to get some context around that. A. Wade Pursell - Chief Financial Officer & Executive Vice President: Hey, Matt. It's Wade. I'll take a stab at that first. Our fourth quarter production number, if you go back to last quarter and do that math that you just said, taking out the Mid-Con, going down 2% or 3% each quarter, the number for the fourth quarter is pretty much the same. We've chosen not to change that number. We've raised the full year guidance based on the beat in the third quarter. And we're taking a cautious approach there. Activity has been reduced. The non-op Eagle Ford activity has certainly been reduced. So that's the approach we took to the fourth quarter guidance. And what was your second question? Matthew Merrel Portillo - Tudor, Pickering, Holt & Co.…

Thank you. Our next question is from James Spicer with Wells Fargo. You may begin.

Yeah. Good morning. Thanks for taking my question. I wanted to just revisit the maintenance capital question in the context of prices here. And just based on some of your responses in the Q&A here, it sounds like you believe you can hold production flat to year-end 2015 exit rate levels in 2016 spending within EBITDAX. Is that a fair characterization? Javan D. Ottoson - President, CEO, COO, Director & Executive VP: Well we specifically did not say that we would hold production flat in this particular case. We have said that in previous releases. I think what Wade said was we're going to focus all our efforts on returns and then on cash flow. We think there's a good chance we can keep production flat exit rate to exit rate or even up, but that's an – it's going to be an output of our allocation to the highest return projects. Clearly, as we shift from gassier to oilier, it's harder to make rate. Potentially it's better from a cash flow standpoint. So it's going to be within a couple percent either way.

Okay. No, I got you. I got you. And just to clarify, you're expressing these intentions in terms of EBITDAX, which of course is before interest expense. So when you're spending within EBITDAX, you're still outspending cash flow by the amount of your interest expense. Is that correct? A. Wade Pursell - Chief Financial Officer & Executive Vice President: That's correct. That's correct. Javan D. Ottoson - President, CEO, COO, Director & Executive VP: Correct.

Okay. Great. That's it. Thank you. Javan D. Ottoson - President, CEO, COO, Director & Executive VP: Thanks.

Thank you. Our next question is from Mike Scialla with Stifel. You may begin. Michael Scialla - Stifel, Nicolaus & Co., Inc.: Yeah, good morning, guys. Maybe a follow-up on that for 2016. You've given some pretty good guidance. It sounds like you're looking at maybe $800 million, $1 billion next year in spending. If oil and gas prices turn out to be lower than what you've been forecasting, just curious how you would adjust that spending. Would you not complete some of the DUCs or would you look at dropping rigs or are there any more assets you can sell? I just want to see what the flexibility in the 2016 plan is. Javan D. Ottoson - President, CEO, COO, Director & Executive VP: Let me start out by saying, Mike, we've never guided our CapEx for next year other than to say we're going to spend EBITDAX. And people are out there projecting numbers for what they think our EBITDAX are, and that – these people then come up with these numbers, and I don't think the range you've indicated is wrong, but I just want you to know we've never guided that number, okay? In general, if EBITDAX goes down, we're going to spend less money. But I will tell you if EBITDAX goes down, it's because prices go down and costs are going down too. So activity levels may not change that much. And I think we're pretty confident that across the range of opportunities we see, given where we think things can go, that we can essentially do what we're saying we can do, which will be very, very close. We'll focus on returns first, maximizing EBITDAX, and that will result in production that we think will be close to either a little bit above…

Thank you. I'm showing no further questions at this time. I would like to turn the call back over to Jay Ottoson for closing remarks. Javan D. Ottoson - President, CEO, COO, Director & Executive VP: All right. I don't know if anybody is still out there, but we really appreciate your time today. Thanks for all your questions. Have a great quarter. See ya.

Ladies and gentlemen, this concludes today's conference. Thanks for ... [Abrupt end]