Welcome to Devon Energy's first quarter 2015 earnings conference call. At this time, all participants are in a listen-only mode. This call is being recorded. At this time, I'd like to turn the call over to Mr. Howard Thill, Senior Vice President of Communications and Investor Relations. Sir, you may begin. Howard J. Thill - Senior VP-Communications & Investor Relations: Thank you, John, and I'd too like to welcome everyone to our first quarter 2015 analyst and investor call. Also on the call today with me are John Richels, President and Chief Executive Officer; Dave Hager, Chief Operating Officer; and Tom Mitchell, Executive Vice President and Chief Financial Officer; along with a few other members of our senior management team. If you haven't had a chance to listen to the management commentary, you can find that, along with the associated slides and our new operations report at devonenergy.com. Additionally, we have included our forward-looking guidance in our earnings release. I hope you've had a chance to review all these documents, as today's call will largely consist of questions and answers. Finally, I'll remind you that comments and answers to questions on this call will contain plans, forecasts, expectations, and estimates, which are forward-looking statements under U.S. securities law. These comments and answers are subject to a number of assumptions, risks, and uncertainties, many of which are beyond our control. These statements are not guarantees of future performance. See our 2014 Form 10-K for a review of risk factors related to our business and any potential forward-looking statements. And with that, I'll turn the call over to our President and CEO, John Richels.

Thank you, Howard, and good morning, everyone. First quarter was an outstanding one for Devon and arguably one of the best from an operations perspective in the company's 40-year-plus history. Before we jump into Q&A, I'd like to highlight just a few key messages that I hope you'll take away from our earnings materials. First, our premier asset portfolio is really hitting on all cylinders. We're seeing significant operational improvements across the portfolio, with improving type curves and increasing inventory, and we're achieving meaningful capital and operating cost efficiencies. The strong operational momentum translated into top-notch first quarter performance. We exceeded our production guidance for the third consecutive quarter. We did a great job of accelerating cost savings across our portfolio, with field level operating costs coming in well below our guidance. We expect this level of excellence to continue in upcoming quarters. As a result, we have significantly raised our 2015 production outlook while at the same time reducing our full-year capital and LOE guidance by more than $400 million in aggregate. And, finally, we have a terrific balance sheet that continues to get better. When you combine the additional cash flow from our improved production outlook, our lower cost guidance, and the recent EnLink-related sales proceeds, we've enhanced our cash flow outlook by over $1 billion in just a few months. So, in summary, our focused asset portfolio is generating differentiating results and returns for shareholders. As many of you know, this will be my last quarterly call as CEO, with my planned retirement at the end of July. And I'm confident in saying that Devon has never been in better shape than it is today. We have a great set of assets, we have a very capable and experienced management team, and a rock-solid balance sheet. These winning qualities clearly offer investors a unique opportunity in the E&P space, and I firmly believe that Devon's best days are still ahead. So thanks again for joining us today, and with that I'll turn the call back to Howard for Q&A. Howard J. Thill - Senior VP-Communications & Investor Relations: Thanks, John. To make sure that we have enough time to take as many calls as possible, we'd ask that you limit yourself to one question with associated follow-ups to that question. You may reprompt to ask additional questions as time permits. So, John, with that, if you'll queue up the calls and questions, we'll go from there. Thank you.

Certainly. Our first question comes from the line of Evan Calio from Morgan Stanley. Evan Calio - Morgan Stanley & Co. LLC: Hey, good morning, guys, and great results today. A lot of new details, so I may jump into a more detailed question here. You introduced a Meramec type curve based upon the initial 12 wells you participated in. If I look at the map, it looks like your acreage includes oilier updip and the gassier downdip sections. Is the type curve representative of blend, or can you discuss how we should interpret that?

Hi, Evan, it's Dave Hager. Yeah, this is based more really on the results that we have to date, which is more in the oilier updip part of the play. We are going to be evaluating some as we move further down to the gassier part of the play. But the type curve you've seen is so far based on our results. We've seen the 12 wells you talked about as well as about 20 industry wells in the area. Evan Calio - Morgan Stanley & Co. LLC: And that's where your activity will be focused for the balance of 2015?

The bulk of the activity is going to be focused in the oilier updip part of the play. I think we're going to draw a handful of wells down to evaluate a little further downdip, but the bulk of it is going to be in the oilier part. That's the best economics at this point. Evan Calio - Morgan Stanley & Co. LLC: That's great. If I could slip just one more in. I know your DeWitt County Eagle Ford are performing – I think it's about 25% over the curve that you lifted just one quarter ago. Is that a function of coring up, enhanced completions? Can you kind of help just to kind of parse through that to understand the broader application on your locations?

Well, the two big things I would say are really around the enhanced completions that we're doing and then really the production optimization techniques that we're using. And so both of those we're very proud of. We think we are adding significant value to this asset with our contribution to the completion design, as well as the production enhancement techniques that we're using, coil tubing cleanouts, automation, choke management, et cetera, so the field is just performing outstanding, but those are the two big drivers. Evan Calio - Morgan Stanley & Co. LLC: Great. Great results, guys.

Our next question comes from the line of Arun Jayaram from Credit Suisse. Arun Jayaram - Credit Suisse Securities (USA) LLC (Broker): Good morning, gentlemen. I was wondering if you guys could comment a little bit more on the Bone Spring and talk about the economic returns that you're seeing in the basin area, or location, versus slope. I believe the drilling costs are cheaper on the slope. I just wondered if you'd maybe comment on the relative returns and where the program's going to be focused in 2015.

Yeah, this is Dave again. The bulk of the program is going to be based in the basin part of the play. We have 10 of our 13 rigs working in the basin part right now. We get good economic returns in both parts of the play. So I want to emphasize that. They're just a little bit different. The slope is more a channelized deposition environment. It is more normally pressured. The well costs tend to be lower. Where, as you move down into the basin, it's a little bit deeper, it's more overpressured, and we're really – we're seeing some benefit from these enhanced higher sand concentrations up on the slope, but we really see the greatest improvement down in the basin part of the play. That's where about two-thirds of our opportunities lie. But I don't want discount the slope part of it, either. It's a good economic play. It's just a little bit different than-- it's a little lower cost and a little bit lower rate than the basin part of the plays. But the bulk of it is going to be concentrated down in the basin part, and not only in the Bone Spring, the lower part of the Bone Spring, but I'm sure you noted also the A Sand wells that we had. We talked about a second well in there, and we're really encouraged by the results we're seeing in this A Sand or upper sand in the second Bone Spring. So, Tony, do you want to add anything to that? Tony D. Vaughn - Executive Vice President-Exploration & Production: You covered it really well, Dave. Arun, I'd just remind you that we really started a lot of our activity on the slope initially and then moved into the basin. But, when you go back and look at the results that we've had in the slope, probably about a third of those results have been at the type curve that we just announced for the basin. So we have a lot of upside on the slope type activity, and we think as we de-risk with those three wells, we'll set ourselves up for a continued development there. So we feel very positive about going back into the slope with more development type work. Arun Jayaram - Credit Suisse Securities (USA) LLC (Broker): It sounded like from your ops report you could see a potential for the inventory to increase a lot in the Bone Spring. My follow-up is just regarding the Eagle Ford. You guys talked about maybe in Q2 being a little bit facilities constrained. Could you just talk about steps that you have under way to maybe relieve some of that midstream – call it bottleneck or whatnot? And when will you have more room to continue the strong growth you've had?

Okay. I'm going to have Darryl Smette talk about this. Darryl G. Smette - Executive VP-Marketing, Midstream & Supply Chain: Yeah, I mean, there's a number of things that we're working on with our midstream provider and with our partner out there in order to increase the capacity. A lot of that has to do with operating efficiencies. That includes getting more uptime on the stabilizer that's out there. I know currently that stabilizer has a nameplate capacity of around 170,000 barrels a day. And, historically, that has been running about 140,000, 145,000. So we're working with our midstream provider to see if we can increase that operational time. We're looking at additional compression in certain areas. We're also looking at, on the truck side of the equation, putting in delivery stations that are closer to the location so we can increase our truck activities so they don't have to drive so far. So there are just a number of things from an operational perspective that we're looking at. We also have had discussions with our midstream provider and with others about providing enhanced capacity out of the area, and those discussions continue on. But nothing has been finalized. Arun Jayaram - Credit Suisse Securities (USA) LLC (Broker): Thank you very much.

Our next question comes from the line of Scott Hanold from RBC Capital Markets.

Hey, thanks. Congratulations on the quarter and good luck, John, on your retirement.

Thank you.

You bet. My question is a quick follow-up on the Permian Basin. You take a look at that increase to potentially 11,000 gross unrisked locations, which is obviously meaningfully higher. When you look at that in the various formations you've identified, is that fairly – should I assume that it's fairly prorated to what you already have out there on a risked basis? Or is there more upside in specific formations like the Bone Spring?

Well, let's talk through the – there are several areas we see upside. We see significant upside in the Bone Spring as we do these downspacing pilots that we highlighted in the operations report. We also see upside in the Bone Spring from this upper sand, this A Sand that I've been talking about, where we talked about the first two wells. So when you combine those two, there is significant potential inventory expansion because of those two factors. Additionally, in the 5,000 risked that we've been talking about historically, compared to the 11,000 unrisked number, we haven't been including anything from the Wolfcamp. We see probably four members of the Wolfcamp that are potentially prospective across Lea and Eddy counties. So that's a big driver also. Then, to a lesser degree, we do see some upside also on the Leonard and the Delaware Sands. But the two big drivers, I would say, would be the increase of potential in the Bone Spring, which again, we think is the most economic opportunity thus far in the play, and then in the Wolfcamp.

Okay. Appreciate that. And in the Eagle Ford, you did touch on – obviously the upper Eagle Ford is looking encouraging. And, Dave, what is your view on the play right now based on what you've recently seen? And if you do get more excited, is there more acreage acquisition opportunities targeting that trend?

Well, we probably don't talk too much about acreage acquisition opportunities. There may be some out there, but we're not going to get into detail on that too much. But I would say, from our mapping, we see the thickest part of this really being in DeWitt County over our existing acreage. We're very, very encouraged what we're seeing so far. We've had encouraging results to the northeast in Lavaca County, and as we're starting to move more into DeWitt County, we're seeing better well results. We're also learning better how to complete these wells. I think you've seen even as you can go way to the southwest beyond our DeWitt County acreage, you've seen another operator talk about encouraging results. I think they call it the Austin Chalk. And it's really the same marl formation as what we are talking about here. So we're very encouraged with the results thus far, and we still don't think we've necessarily drilled the best part of it. And so we think it is going to be a very economic play. It's a little different. It's not necessarily a shale. It's more of a marl, which is more like a limestone, really. And so your spacing may be a little bit wider. We don't know for sure. We're thinking maybe 160, but it's too early to say for sure. But we're very encouraged with what we've seen so far.

Okay. So the way I'm hearing your comments, you are increasingly becoming more optimistic at this point?

Absolutely.

Thank you.

Our next question comes from the line of Doug Leggate at Bank of America Merrill Lynch. Doug Leggate - Bank of America – Merrill Lynch: Thanks. Good morning, everybody. And let me join – echo my congratulations. And, Dave, we're looking forward to seeing your impact, more so than you've already done already. A couple questions if I may, fellows. But maybe going back to the Eagle Ford. I guess BHP as operator has raised some concern that they wanted to kind of slow things down a little bit. I'm guessing that the infrastructure is going to kind of do that for them. But what my question really is, how do you change your capital allocation in light of the 400-odd unrisked locations in the upper Eagle Ford? And you've obviously got a much bigger opportunity set than your partner. So that's kind of my first question. I've got a second in the Permian, please.

Well, what we're trying to do right now, overall, Doug, is to match our activity with the availability of capacity with our infrastructure. And now we're trying to expand that capacity, and Darryl highlighted that. If you look at it, at the end of Q1, we had about 130 wells that were currently uncompleted. So we have an inventory to work through. We are staying active with drilling in the area. We have decreased the rig count a little bit, but we're getting also more wells, we're getting increased efficiencies. So we're getting more wells out of a slightly lower rig count. And so we have plenty of wells to be completed. And that's not the limiting factor. The limiting factor at this point is just solving some of these infrastructure issues, which we're confident we're going to be able to do. We are so far concentrating the bulk of our activity in the lower Eagle Ford, but we're talking to BHP about the upper Eagle Ford and plan to do some upper Eagle Ford tasks as we move into the heart of the play, which we think would be over the acreage we have with BHP in DeWitt County. Doug Leggate - Bank of America – Merrill Lynch: I appreciate that. Thank you. But my follow-up in the Permian, obviously that's a more than potential double on your inventory. I'm just curious if – on the downspacing I guess in the Bone Spring – I'm curious, does that upside include the delineation or testing on the Wolfcamp? Or is that still ahead of us? And if so, again, how does (17:27) capital allocation go in your Delaware position? And I'll leave it there.

When we look at the table that we've referenced in some of our previous disclosures, Doug, we've included no locations for the Wolfcamp. And we've been focused on the second Bone Springs, again because of the returns are higher in that particular pay horizon than others. But we still have a lot of industry activity in and around our position in the Wolfcamp. So we're optimistic. We're building out the technical plans for a rig line right now in the Wolfcamp, and we'll probably drill – out of the 150 gross wells that we'll drill in the Delaware, about half a dozen of those will be in the Wolfcamp this year, and another half a dozen will be in the Leonard. But the focus again continues to be the second Bone Springs just because we're trying to maximize returns in this environment. Doug Leggate - Bank of America – Merrill Lynch: Just to be clear, that greater than 11,000 mentioned in the ops report, is there any Wolfcamp in there or not?

There is on the gross expected locations of 11,000. There's not in the net risked count that we've disclosed. Doug Leggate - Bank of America – Merrill Lynch: Got it. All right, thank you.

Your next question comes from the line of Charles Meade with Johnson Rice. Your line is open. Charles A. Meade - Johnson Rice & Co. LLC: Yes, good morning, gentleman, and congratulations also from me to you, John. If I could just bang a little bit more on the Bone Springs results, because this really so tantalizing. Dave, if I remember, about a year ago, I think, when you guys were expanding your – or one of the many times you expanded your inventory in the Bone Springs, at one point you described the logs out here as just like railroad tracks, like it's hard to see what makes one zone different from the other. And, as I'm looking at this now, can you give a bit of a narrative on why it is that you're looking at the upper now, and what's appealing to you? And I guess that would also go for the third Bone Springs, which is – you're going to do in one of your pilots. And what led you to that? And what could be in the future?

Yeah, I remember giving that description. I think that the short answer is that you have to test these wells really to know how successful you are going to be. And that's what we've – we decided to do some tests in the upper Bone Spring, and we're continuing to appraise other areas, but it does take testing to really understand just how good they are. So, Tony, you want to expand on that? Tony D. Vaughn - Executive Vice President-Exploration & Production: Sure will. Charles, I think the technical guys are doing a lot better job now of calibrating all the surface data we have, and of course we're getting a lot more control points as we continue to test. They're looking at micro-seismic results, and we're trying to understand what kind of a stimulator rock volume that we contact when we do our frac work there, and I think that what we're generally seeing is that while we're landing and spending most of our concentrated energy in the lower portions of the second Bone Springs, we know we're contacting a little bit upward into the middle, but we haven't seen evidence that we're contacting into the very upper portion of the second Bone. So it's really just, as we do in a lot of these type of plays where the rock is not that favorable or certainly not that obvious from first inspection, it takes a little bit more science to uncover that, and a lot of the subsurface data points just gives us a little bit more information to lead our developments down the road. Charles A. Meade - Johnson Rice & Co. LLC: That's helpful. And then, following up on the type curve adjustment you guys had. So you bumped the IPs by about 60%, but on your operations report, the graph right above there says your cum through 180 days is also up 60%. And so it looks like that's not just an IP effect but it's a sustained effect that you're seeing, sustained production uplift. So, if I put those two pieces together, it looks like the EUR is – maybe this is what you mean by the (21:41) but that EUR of 600 MBoe really looks to me like that's going to go higher. Is that -

Well, that is an increase, Charles, from – if you go back a couple quarters, we said 450 MBoe plus. And I made the flippant comment it could've been plus, plus, plus, if I remember right. Charles A. Meade - Johnson Rice & Co. LLC: Right.

Well, so now we are saying 600 MBoe in the basin. And I think what – the comment that Tony also made earlier, I hope you caught that, is about a third of the wells we're drilling up in the slope are following the basin curve. And we haven't increased it on the slope yet, but we have some evidence so far that we may have some better results coming in the future on the slope as well. But that is an increase from – we've never come out with that 600 MBoe number specifically. Before we just said 450 MBoe plus. Charles A. Meade - Johnson Rice & Co. LLC: Okay. Thank you, Dave.

And there may be some upside in the basin from that also, frankly. But we'll see how it goes. Charles A. Meade - Johnson Rice & Co. LLC: Right, right. Thank you.

Your next question comes from the line of Jeffrey Campbell with Tuohy Brothers Investment Research. Your line is open.

Morning, and I'd like to also begin by saying happy trails to John.

Thanks, Jeff.

You've certainly left Devon a much better company than it was when you took over. I wanted to actually talk about the Powder River Basin Parkman results, because I thought they were really quite impressive, particularly since some peers have retreated from the area during the downturn. I just wanted to ask a couple of things. If you want to count it as two questions, it's fine with me. What percentage of your focus area can support the 9,600-foot laterals that you highlighted? Will you drill shorter laterals where the geometry of the acreage requires it? And, finally, will you take your Parkman approach to the Turner or to the Frontier and see if they can show similar uplift?

Thanks for noticing the results, Jeff. I think what we spent is – if you go back in 2013, early portion of 2014, we spent a lot of our capital on the efforts really delineating a very large, broad area there in the Powder, as you know. And we have centered in on a couple of what we call sweet spots in the Parkman and in the Turner. So the work that you're seeing now is us being able to confirm repeated high return-type work in those sweet spots. And most of that has been in the Parkman. We find that there's a great uplift with extended laterals, and we will continue to do that when possible. We also find that we're bringing on – starting to bring on some extended Turner wells right now, so we'll have a little bit better knowledge of what that will look like. But I would expect the Turner to follow the Parkman results. And in terms of the total inventory, I think we've commented that we have about 1,000 locations in the Powder. We picked up a little bit more acreage in Q1 and supported our Tier 1 position in the Parkman and Turner. That adds to that location count. So on a normal lateral basis, that location count goes up a few hundred if not 300 more locations, but really goes up to 1,450 as I see in the operations report now. But we're trying to reduce that by drilling the extended-reach wells, and we think that if we can do that and core up our position, we can drop that to about 800 and see the results that you just saw this last quarter. So we're very excited about the Powder position right now.

Okay, thanks very much. I appreciate it.

Your next question comes from the line of Ryan Todd with Deutsche Bank. Your line is open.

Great, thanks. Good morning, gentleman. Maybe if I could follow up with a couple questions on capital allocation. I guess one in the near term in 2015, if limitations persisted from the second quarter on, in terms of the debottlenecking in the Eagle Ford, what's your ability to deploy capital elsewhere in the portfolio? Can you make up the difference by accelerating activity in the Permian or the Anadarko Basin?

Well, we don't really see that the limitations that we're seeing in the Eagle Ford at this point are going to really change our capital requirements there on a very significant level at all. So it's kind of a hypothetical question, I guess you'd say, because we just don't see that to be a limiting factor. Now, obviously, in the future – I'll expand your question. Longer term, we absolutely plan to increase our rig count in the Permian and in the Delaware Basin, because we are expanding the inventory so much. Now, we don't see that so much as a 2015 event at this point. We're balancing our cash flows with our returns and the available infrastructure and the other limitations, permits, et cetera, that we have in the Delaware Basin. But longer term, we absolutely plan to expand our activity in the Delaware Basin and most likely in other plays, such as the – up in the Powder River Basin as well. And we have scope eventually as prices improve to deploy more capital also in the Cana-Woodford area. So we have a lot of opportunities in the inventory, but we don't see a significant change to where we're spending the money in 2015.

Great and maybe that segues into a discussion on 2016 on the allocation of capital. But can you talk a little bit about moving pieces in the portfolio, maybe in the case of a flat year-on-year CapEx environment? How much spend do you have rolling off year on year from 2015 to 2016 in areas like the oil sands or other places that would allow for incremental dollars to flow into places like the Eagle Ford, the Permian, and the Anadarko? And then with incremental – as you think about incremental capital growth from 2016 and beyond, can you rank maybe where the dollars go back into in terms of Eagle Ford versus Permian versus the Anadarko or other?

Ryan, when you think about where we're allocating our capital this year and what – where you might, to your question, where you might drop some capital in the future, we're spending about $700 million this year in Canada. That was largely as a result of some ongoing projects that were well under way, and also the engineering and delineation appraisal work that we're doing on Pike. And so, on a going-forward basis, that could drop to somewhere around $200 million, $250 million just for the ongoing maintenance capital for the oil sands. So that drives the $500 million, I guess, of less expenditure there. We also had some expenditures this year as we were finishing up the program in the Miss and the Southern Midland Basin that you could see curtailing next year. So those additions – and then costs, of course. We're seeing costs go down significantly as we discussed, and we still think by year-end, we'll see costs 20% or 25% below where they were in the fourth quarter of 2014. So that rolls through as well. So there's some fairly significant chunks that you could see coming off. And it's a little hard to force rank. There's no question that our Eagle Ford is giving the best returns in our portfolio. But after that, as you look at the Delaware Basin, some of the work that we're doing in the Anadarko Basin, and as Dave said earlier, and Tony, the really positive results that we've seen in the Parkman, in the Rockies, they kind of fall into that next bucket. And you'd kind of be making decisions there not based on a full basin analysis but on incremental rigs and where you're drilling within those basins. So, as Dave said, we've got lots of opportunities, and if we were in that flat pricing environment, we also have some additional cash that frees up.

Great. Thank you. That's very helpful.

Our next question comes from the line of John Herrlin from Société Générale.

Yeah, hi. Just a quick one from the ops report. In the Eagle Ford, you mentioned that you're using a diverter and 100 mesh sand. Can you address that a little bit? Are you trying to put more sand at individual intervals, Dave? What's going on there? Tony D. Vaughn - Executive Vice President-Exploration & Production: John, this is Tony. John, we're taking a engineered approach to our completion work in the Eagle Ford, so we're capturing a lot more science than we historically have done. We are trying to look at the rock that we drilled with our open-hole logs and design our fracs according to what we think will be successful to pump our jobs away. So we are using the 100 mesh trying to increase the total volume of sand into the wells, but we're also trying to be thoughtful in where we place that. And I think when you look at the results that we're seeing there, we've increased the results from our completions. We're also working with BHP, and their design is also changing greatly over the last year that we've been involved with them. Their completion results are also being upgraded as well. So I think between the two of us taking a slightly different approach, we are driving our completion results to be much more effective than we have in the past.

Great. Thank you.

Our next question comes from the line of David Tameron from Wells Fargo.

Good morning. Yeah, John, I'm going to echo my sentiments for a happy retirement, and congrats on what you've done at Devon.

Thank you, David.

If I just think – I want to go back to the Eagle Ford. And if I start thinking about big picture, I mean, you're adding 20,000 – or you added whatever you added, 23,000 barrels, I guess. 24,000 barrels during the quarter. When you start talking about 170,000 and I know you can go over nameplate, how should we think about this asset in 2016, I guess? Do you kind of ramp to that 180,000 level, and kind of sit at that level? Or how should we think about that?

Well, we aren't giving specific 2016 guidance at this point, David. But I can tell you we're real happy with how it's performed. And I think one of the key things is also going to be just how successful we are in debottlenecking the infrastructure here, and that's going to determine to some degree what our 2016 production is. But you can see we're just producing outstanding results, and until we work through the debottlenecking and we really work through our whole capital allocation, we're just trying to not get in too much detail at this point about 2016 production, I guess you'd say. But we're certainly very happy with the results we've had thus far.

Okay. Let me ask another question, just thinking about 2016. Kind of what's your framework or how should we think about your framework for – no matter what the price environment, whether it's $50, $70, $80, $60, whatever the number is, kind of what's your goal from a corporate perspective as far as cash flow, CapEx? How should we think about that?

Well, David, yeah, we said before that within some reasonable limits going forward, we want to live somewhere around cash flow, but cash flow can be different things. There's the operating cash flow. We also have other levers that we have been able to pull in the past. And so it's just a – we've got a lot of flexibility. It's a great thing about having a very strong balance sheet and a strong financial position in a tough market. But, philosophically, over time, we want to balance our capital expenditures somewhere close to what our cash flow is.

Okay. I'll leave it at that. Congrats on a good quarter, and good operational detail. Appreciate it. Thanks.

Our next question comes from the line of Brian Singer from Goldman Sachs. Brian A. Singer - Goldman Sachs & Co.: Thank you. Good morning.

Morning, Brian. Brian A. Singer - Goldman Sachs & Co.: Congrats to John and Dave. On the Meramec, you've now derisked 60,000 acres, and wanted to see both what portion of the remaining 220,000 acres has scope for the oil window, what your delineation plans are there? And then, when you look at a well being drilled there, I think you talked about 51% overall liquids, how you see that changing if at all through the life of the well? Tony D. Vaughn - Executive Vice President-Exploration & Production: Brian, this is Tony. Brian, just – I think what we highlighted in our operations report is we had about 60,000 acres exposed to the – what we call the oil and liquids-rich window. Industry and Devon and our partner, we're currently delineating the fluid gradients through – across the field. But order of magnitude, I would estimate that our exposure just to the low-GOR oily window would be, order of magnitude, of about – less than 5,000 acres. Most of our exposure is going to be what I would call the condensate liquid-rich window, and that would be the 60,000 acres – largely the 60,000 acres, Brian. Brian A. Singer - Goldman Sachs & Co.: Got it. And then, does the well have a disproportionately higher liquids content initially? Or is it kind of 51% overall through the life, in your estimates? Tony D. Vaughn - Executive Vice President-Exploration & Production: Well, we really don't have a lot of historical performance to look at that, but we're expecting that the performance and really the liquid content will mimic a lot of the results we've already seen in the Cana-Woodford portion of our play there. Not a lot of difference at this time, but I got to tell you, Brian, it's real early. Not a lot of performance data to tell us that. Brian A. Singer - Goldman Sachs & Co.: Great. And then, lastly, in the Permian, a lot of time spent talking about the Delaware Basin, obviously a lot of improvements and efficiencies going on there. I wonder if the extent of that opportunity set makes the meager Midland Basin assets less strategic in how you're thinking about the Midland?

Well, we always look at our portfolio, Brian. That's, I think, one thing you can say about Devon. If you look at what we've done over the last two years that we have really high-graded a portfolio, and we don't ever consider that job fully finished. We think part of our job is to bring in top-tier assets, and then when assets can be more effectively handled by somebody else or create more value through a transaction, we'll consider that. So I'm not going to get too specific on the Midland Basin, I wouldn't say. We like Martin County, and we've had some historical success in the Southern Midland Basin and Wolfcamp, not quite as strong of economics over there, though, obviously. So we are constantly looking at what's the best return for our shareholders overall as far as whether should keep or do something with it. And certainly, the answer to this question is oil price dependent also. If oil prices move up, it significantly impacts the economics of our Midland Basin opportunities. So it's not just a – you have to evaluate it pretty carefully in different oil price scenarios. Brian A. Singer - Goldman Sachs & Co.: Great. Thank you so much.

Our next comes from the line of James Sullivan from Alembic Global.

Hey. Good morning, folks. Congrats to John and Dave both, also. Could you just remind me, to hop back over to the Bone Spring again, what is the average lateral length you guys are drilling out there right now? And what are you using for your type well? What is that based on in terms of a lateral length?

These are just normal laterals, so they're about 5,000 feet at this point. We do like the opportunity to drill extended laterals or extended-reach wells when we can. And so, as we move into some of the other horizons, maybe the Wolfcamp and Leonard, you're going to see us move up into maybe the 7,500-foot lateral length. But, for now, most of our work and certainly the type curves are based on a 5,000-foot lateral.

Okay. Great. Just to follow up on that point, and I guess what I'm trying to get at here is, I know folks have talked about it a little bit more with the Wolfcamp, but is it a priority for you, as the focus continues to be the second Bone Spring, is it a priority for you to block off your acreage to give yourselves more double sections to drill longer laterals for the second Bone Spring? I know you do have a couple of blockier areas where you can do that already. But maybe more opportunity to do that. Is it a priority for you guys? And if it is, would you consider a bigger, more comprehensive kind of acreage swap with one of the other operators in the basin there?

Well, we would. We're always trying to block up acreage everywhere we work. The Delaware Basin is an area that, as you know, we're committed to. So we would love to have both a larger footprint and a more contiguous footprint, so our guys are always trying to work those opportunities. And we'll continue to expand the position and get our footprint to the point we can have the most optimum development plan possible. So, yeah, I think we would be interested in considering a trade to core up our position there.

Okay, great. Thanks, guys. I'll jump back in the queue.

Our next question comes from the line of Paul Grigel from Macquarie. Paul Grigel - Macquarie Capital (USA), Inc.: Hi. Good morning. Most have been asked. Just wanted to get the latest thoughts on looking at 2016 in regards to hedging? And if there's a plan for instituting some hedges, a little bit more agnostic of prices or if it'll be a little bit more active? Or if you prefer to enter the year, depending on prices, without hedges? Darryl G. Smette - Executive VP-Marketing, Midstream & Supply Chain: Yeah, this is Darryl. As we've said before, we would like, over any given point in time, to have about 50% of our oil and our natural gas financially hedged. Currently, we have no hedges for 2016, although we're very well hedged for 2015. Our current thought is that as we look at commodity prices, we think there's a lot more room for upside than there is downside. And so we have not executed on 2016. We do have a process by which we consider hedging opportunities every couple weeks within our company. And so while we'll not give you any specific prices under which we would hedge, it is an ongoing discussion. But again, our overall thought is that we'd like to have about 50% of our oil and gas hedged at any given point in time. So it's something we look at all the time, continue to look at. But in the current price environment, when we look at the natural gas and the oil strip for 2016, it's not something that excites us. Paul Grigel - Macquarie Capital (USA), Inc.: Okay, great. Thanks for the color.

Our next question comes from the line of Sameer Uplenchwar from GMP Securities.

Hi, good morning, guys. And congrats, John. And best of luck for you in the retirement.

Thanks, Sameer.

What I'm trying to understand is, if I'm looking at 2016 – I know this question has been asked before; I'm just trying to get a direct answer. Is – what do you need to see to put rigs back to work, like, from a cost perspective? From an oil price perspective? Gas price perspective? Just trying to understand, because right now we're in a low price environment. But what happens in second half 2015 if prices move higher? How should we think about that?

Well, Sameer, that's obviously a hard question to answer, and we're not trying to be evasive about 2016, but we're so early in thinking about 2016, and there are so many variabilities – costs and prices and all of the other variables that go into that. But I think what we would say is, whatever the price is, we're going to focus our efforts next year in the areas where we're going to drive the highest returns, or get the best rate of returns. And there are going to be some funds for that that will be available to us in even the next – in those really good areas where we've been driving the higher rates of return for next year. So, because we'll spend less dollars in a couple of the other places that we're committed to going into 2015. So there's just a whole lot of variables right now, and we're so early in the process in determining what 2016 looks like, it's really hard for us to give you an answer there. But you ought to feel that – take away from this that our focus on the Eagle Ford, on the Delaware Basin, this emerging opportunity we have in the Rockies, which looks pretty good, are all areas that are going to drive high rates of return, and we'll focus on those areas whatever our capital budget ends up being.

Perfect. And then, on a broader basis, everybody's, including Devon's, well results continue to improve in the Eagle Ford and Bone Springs. I'm just trying to understand, what is Devon doing differently versus peers? And where is Devon leveraging on peers or partners, and just trying to get an idea about that longer laterals completion designs, or what have you? Thank you.

Well, if I understood the question, what we're doing in the Bone Spring that's different, I think two things. One, we have some of the best geology for the Bone Spring, and so our acreage happens to be located where some of the best Bone Spring opportunities are. And, second, we think we are leading the industry in our completion technology. We have really made a conscious decision to step out and test various size sand concentrations and stepping up to 3,000 pounds of sand per foot and that too in some areas, so we can really understand what's the right size completion to put on each of our specific areas. And it's obviously a price-dependent issue as well. So, I think what are we doing to lead the way in the Bone Springs? We're fortunate we have good geology. I think we have a good appraisal program going on, a good development program. And we're testing the various zones, and we are really, I think, leading the way with our completions at this point in the industry also. So, Tony, you want to add to that? Tony D. Vaughn - Executive Vice President-Exploration & Production: Yeah, Sameer, I think what I'd add to you, and we talked about this at the last call. But our technical teams are putting a lot more science and a lot more work into the subsurface characterizations of the projects we work on. So we're taking a lot more cores, pressures, temperatures. We have fiber optics in all the plays that we're currently working, so we're able to calibrate all that information. On the execution side, the guys are doing a really good work. I think we've talked about standing up our well-con (46:25) center. So we're maintaining – we have 24-hour coverage of every drill bit that we're operating right now. So we're keeping the wells, the trajectory flat. We're keeping them in zone more than we have in the past. All that's really adding to a better completion. It's hard to measure the work that we do and where it ends up, but I think the outperformance that you've seen in the last couple quarters has been associated with just some good quality work from our technical people.

Perfect. Thank you.

Our next question comes from the line of Jeffrey Campbell from Tuohy Brothers Investments.

Wow, this is like Christmas. Back here again. Thank you. Let me ask two real quick questions. The first one is with regard to the second Bone Spring stacking test, the stacking pilots. The first – the Pilot 3 and Pilot 4, are those located in the basin area? And Pilot 5, because it's got a third Bone Spring well in it, is it located someplace else? Tony D. Vaughn - Executive Vice President-Exploration & Production: They're mostly in the basin. We have several pilots there, but I'd also let you know that we've got a couple up on the slope. So we're testing the downspacing concept mostly in the second Bone Spring. But we're trying to understand the relationship when these staggered laterals approach and just simply the downspacing in the same interval. We're testing these concepts in original pressured environments. We're also testing these concepts in partially depleted areas to know what we might be able to come back to and further develop our current position in.

Okay, that's great. The other quick question I just wanted to ask. Slide 16, in the Anadarko, you showed a number of zones of interest. Was just wondering if you guys have tested or have any plan to test the Springer? Some of the peers in the mid-con are calling the Springer comparable or superior to the stack. Thank you. Tony D. Vaughn - Executive Vice President-Exploration & Production: Well, we do have exposure to other intervals inside of the Mississippian there, and so our guys are looking at all of these intervals. We don't have a lot of data to talk about at this point, but we're not oblivious to some of these other opportunities, and we will be testing some of these with time.

Great. Thank you.

Looking at the queue, it looks like we're getting fairly near the end of the calls, but I was thinking – there's one area we thought we might be asked about and we haven't been and I may, since we have a couple minutes here, I might ask Tony just to make a comment about it, our refrac program in the Barnett. And this is a program that we're really proud of how it's proceeding so far, and we see some real upside associated with that. So, Tony, you want to make a comment on that? Tony D. Vaughn - Executive Vice President-Exploration & Production: Sure. Dave, like you mentioned, we were expecting a call on our refracs. We've heard a lot of that from our shareholders in the past. And I guess I want to – or kind of summarize the work that we're doing. We're excited about this opportunity across our entire position. We've seen such a dramatic improvement in our completion results with the newer technology that we're incorporating on our original completions that we've gone back and are starting to test some of these new completion techniques with our existing producers. We've already completed about 50 refracs on vertical wells in the Barnett, all with outstanding results, very commercial. We intend to complete a program of about 200 for 2015. We've also – have completed about eight to 10 jobs on horizontal wells in the Barnett on what I would call partially depleted wells. We're encouraged by the work we're seeing there. We're – continue to test that consent. We have also – are testing refracs across the remaining portion of our portfolio. We've tested some in the shallow-water portions of the Permian Basin oil play and also in the Haynesville. We're designing refracs right now…

This concludes today's conference call. You may now disconnect.