Welcome to the Devon Energy's Fourth Quarter and Full-Year 2016 Earnings Conference Call. At this time, all participants are in a listen-only mode. This call is being recorded. I would now like to turn the call over to Mr. Scott Coody, Vice President, Investor Relations. Sir, you may begin.

Thank you and good morning. I hope everyone has had the chance to review our fourth quarter and full-year 2016 financial and operational disclosures that were released last night. This data package includes: Our earnings release, forward-looking guidance, and our detailed operations report. Also, on the call today are: Dave Hager, President and CEO; Tony Vaughn, Chief Operating Officer; Tom Mitchell, Chief Financial Officer; and a few other members of our senior management team. I would like to remind you that comments and answers to our questions on this call today will contain plans, forecasts, expectations, and estimates that 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 and actual results may differ materially. For a review of risk factors related to these statements, please see our Form 10-K. And, with that, I'll turn the call over to Dave.

Thank you, Scott, and welcome, everyone. For Devon, 2016 was a transformational year. We successfully reshaped our portfolio around top two franchise assets, the STACK and Delaware Basin, providing us a sustainable multi-decade growth platform. With these world-class assets, we delivered outstanding operational performance throughout the year. Our drilling programs generated the best well productivity results in Devon's 45-year history and we maximized the value of every barrel produced with cost reduction efforts that reached $1.3 billion of annual savings. We also took important steps during the year to strengthen our investment grade financial position with the timely completion of our $3.2 billion asset divestiture program. Overall, while 2016 will certainly be remembered for extreme volatility in the energy markets, our unwavering focus on the controllable aspects of our business yielded extremely strong results and we laid the groundwork for Devon to deliver differentiated growth in margins and cash flow expansion as commodity prices recover. As we look to 2017, the next step in our strategic plan is to accelerate investment across our U.S. resource plays, while maintaining our low-cost structure to maximize profitability. With an improving cash flow stream, we are planning to steadily ramp up drilling activity throughout the year to as many as 20 operated drilling rigs by the end of 2017, roughly doubling our rig count from year-end 2016. This ramp up in activity would represent an upstream investment of $2.0 billion to $2.3 billion for the full-year 2017. The majority of this capital will be concentrated on low-risk drilling activity in the STACK and Delaware Basin, and is expected to jumpstart companywide production growth, driving light oil production in the U.S. approximately 15% higher for the full-year 2017 compared to the fourth quarter of 2016. Additionally, we expect to deliver this attractive growth profile with…

Thanks, Dave. We will now open the call to Q&A. Please limit yourself to one question and a follow-up. If you have further questions, you can re-prompt as time permits. With that, operator, we'll take our first question.

Your first question comes from Evan Calio from Morgan Stanley. Your line is open. Evan Calio - Morgan Stanley & Co. LLC: Hey. Good morning, guys.

Good morning. Evan Calio - Morgan Stanley & Co. LLC: So you guys – you added significant locations in the Meramec and you have a large location upside in the Delaware where you're ramping up activity most this year. I guess the question is, is how do you think about the portfolio impact if your location count continues to grow? And do you have enough confidence in the current direction to trigger another round of asset sales in 2017?

Well, we obviously are working our way through the appraisal of a number of different zones, as you highlight, both in the STACK play and the Delaware Basin. And the results so far have been very, very encouraging that we've seen with not only the number of zones that are working in both of these plays as well as the potential or down spacing in both of these plays. So we think we have the – we're positioned in a couple of the best basins in onshore North America, and we have some of the best position in those best basins. So we feel really good about that. We do want to further our understanding before we make any strategic decisions such as that. We're also working some of these other areas that may be consideration and we're improving the results in those areas at the same time. We're going to have – for instance in the Barnett, we're going to have a refrac program that is at a substantially lower cost than we've done previously that could really be a game-changer in terms of the returns on that program. We're also going to drill some new wells with modern drilling and completion technology that hasn't been done for several years. So we want to see all of this work come together as far as finalizing or getting more data as far as how big our inventory really is in these top-tier resource plays and in doing some work in some of these other plays to really understand the full potential of these plays before making any sort of strategic decision. Now, I'll say, if you go back over the past few years, we haven't been – if you look at us as a company, we haven't been hesitant to make the right decision at the right time as far as optimizing our portfolio. We think it's really important to, if we ever do make a decision this way, that we have the best information available when we do that. Evan Calio - Morgan Stanley & Co. LLC: Maybe a follow up on the delineation side. I mean, you have two rigs in Woodward and Dewey counties, they're outside the core of the play, can you discuss what your testing there? What zones? And potentially what that could de-risk for you?

I'm going to let Tony Vaughn, our Chief Operating Officer, answer that question for you.

Evan, we've got – I think we've commented before but we have about 80,000 acres outside the core of our footprint in STACK. You probably have read some of the competitors are testing for the Osage and the Meramec and we're continuing to work some prospectivity in those areas, trying to gain an understanding of really where the play moves. Evan Calio - Morgan Stanley & Co. LLC: Any idea on timing there in terms of when we might have some results there?

We're engaged in some operations right now, both on the drilling and the completions side of it. So it'd probably be the second half of 2017 before we have a better understanding about our thoughts there. Evan Calio - Morgan Stanley & Co. LLC: Great. Good results, guys.

The next question comes from Doug Leggate from Bank of America Merrill Lynch. Your line is open.

Well, thanks. Good morning, everybody.

Good morning, Doug.

Hopefully you can hear me okay.

Yes.

Dave, can you just remind us what is the spacing assumption, I guess wells for DSU, that you're assuming in the 1,600 locations in the Meramec. And what's behind my question is, 20 to 30, it seems like quite a big step-up, and I'm just wondering if you could help frame for us if that's across the entire play or just the over pressured area or just how you're thinking about how that 1,600 locations has – what the upside risk is for that?

All right. Doug, thanks for the question. In summary, we see tremendous potential for that continuing to increase through time. Right now we average six wells per section across the entire position in that number. As we – and it is a much higher number, probably around 13 wells per production, and obviously, the average six is much lower outside the core and we've essentially put none of the locations we've counted within the liquids-rich part of the window, where we are participating along with some of our peer companies and the drilling activity there as well. So we see that there is tremendous upside to this as we further appraise the entire area. So we're just getting started.

All right. I appreciate that. I guess I'm going to ask you about the portfolio as well, if I may, because let's assume you have a tripling or a quadrupling of the inventory in the STACK, I think Tony has said in the past that your Delaware Basin slope or your Delaware slope acreage probably wouldn't compete for capital; your Barnett production or assets probably struggles to compete for capital, so what do you need to see to – or whether or not you can actually confirm that is the case that those are maybe non-core assets, and what do you need to see to maybe start thinking about moving those forward as another assets disposition program ? And I will it leave it there. Thanks.

Well, again, we are looking to further quantify just how rich our inventory is. We know it's rich, but we would like to get more information on the spacing in the various intervals that we're testing both in the STACK play and the Delaware Basin. Also, and just how many of these different intervals are working. So we would like to further detail that to know for sure. It has certainly been true historically that the slope in the Delaware Basin does not appear to compete as well. Although I will note there've been some pretty big purchases their recently by some other companies. But I think historically it has not competed as well. And the Barnett, although you can get returns well above the cost of capital, have not competed in our portfolio. But again, we are currently testing some innovations in the refrac technology side to significantly lower that cost, and we're trying some new wells out there with modern drilling and completion. So we would like to understand that potential before, both in terms of just how deep our inventory is, and also what is the real upside better from these other plays before we make a final decision. We understand the question very well. It's not lost on us. We understand, and like I say, we have not hesitated historically when the time is right to make these strategic decisions. But that's what we're working through before we make a decision.

Very clear, Dave. Thanks very much.

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

Great. Thanks. Maybe a question on the – the first question on the type curve in the STACK. I mean, at this point, you've only provided one that's been for a 5,000 foot well. Any color on how we should think about the reserves from the 10,000 foot longer laterals that you're drilling now? And 30 day rates? Should we extrapolate in terms of kind of reserves for lateral foot from the 5,000 foot wells? And what's the average well cost at this point are you expecting from a 10,000-foot lateral?

Hey, Ryan, this is Scott. And, last quarter, we did roll out our first extended-reach type-curve for what we considered the overpressured oil window within the STACK and the EURs on that are approaching 2 million barrels per well on an equivalent basis. And depending upon the strength of the casing, whether it's two or three, the cost of the – D&C cost can range from $7.5 million to $9 million. And from an IP rate perspective, these are pretty prolific wells as well; it's well north of 2,000 barrels equivalent per day on a 30-day rate. So that's our initial type curve. And I think Tony can talk about maybe what we're seeing at the early results on that and how it's trending.

Yeah. Thanks. Scott did a good job of characterizing the type-curve there for the 10,000-foot wells. And the producing history that we've had on those is really exhibiting better performance over time than even the 5,000-foot laterals. So there is additional upside in our type-curve, I believe. We need more information to look at that, but we're quite pleased with the 10,000-foot wells over the 5000-foot wells and we'll certainly try to maximize every opportunity we can to drill those 10,000 footers.

And on the longer laterals, is there room – I appreciated the incremental shift towards 65% of the inventory of 1,700 wells in the STACK being the longer lateral. Is there room for that to shift higher at this point? Or how should we expect your ability to drill longer laterals to trend over the next little while?

Yeah, Ryan, I think that's what our technical teams do every day. I think they're looking for opportunities to core up either through small-scale land acquisitions or trades and also, looking to work with other operators there. We've got a great relationship with the other primary operators in STACK trying to maximize the efficiency of each of our operations, and so that's working quite well. And I think the positions are largely made between the large operators. So there is potential for that to continually inch its way up.

Thanks. And then maybe if I can ask one on your view on costs. I mean, what did your 2017 capital budget assume in terms of well costs relative to constant 2016? How much inflation do you assume? What are you seeing today? And any expectations on what you expect over the course of 2017 and maybe into 2018 in terms of the cost structure?

When we were out a few months ago talking about that, we said we expected high-single digit inflation across all aspects of the business. We have revised that upwards a little bit now, we're saying now in the 10% to 15% across all aspects of the business. And so if you look at our – and we have accounted for that in the capital guidance that we provided to you. We were originally talking about a capital program around $2 billion, a couple, three months ago. It's been now at a $2 billion to $2.3 billion. We probably upped the midpoint about $150 million of that. About $100 million of that is due to just moving up the timing of some rig activity, particularly in the Delaware Basin. And about the other $50 million or so is due to additional cost inflation. Now at the same time, we think we can largely mitigate about 75% of this cost inflation that we anticipate to see this year. And you're seeing examples of us across our portfolio where we're lowering the drill times associated with these wells. Our 24/7 365 drilling control room is really helping out a great deal with the efficiency, and nearly 100% in zone on these wells. So yes, it does appear the inflation has picked up somewhat from a few months ago, but we think we can largely offset that.

Great. Thanks. Very helpful.

Your next question comes from Arun Jayaram of JPMorgan. Your line is open.

Yeah, good morning. My first question just involves your CapEx program from this year of $2.5 billion at the midpoint, which is kind of below your upstream cash flow potential that you highlight on page six of the ops report of $2.7 billion. So I just wanted to get your thoughts on spending a little bit below cash flow and the strategy behind that and maybe some thoughts around 2018. You highlighted $3.5 billion of upstream cash flow potential. What does that 20%-type growth number for U.S. light oil, what does that embed in terms of CapEx next year?

Well – hi, Arun. This is Dave. First off, from a corporate standpoint, given the strength of our balance sheet and our financial strength, we are comfortable right now spending approximately at cash flow in any given year. We want to stay a strong investment-grade credit company. And we believe with our net debt position at this point that the spending within cash flow is approximately where we should be. Now, we recognize, depending on whose price deck you use that there may be the potential to – that we may have a little bit of free cash flow this year. I think frankly, there probably you would have to subtract off the dividend off the numbers in our book there, and then you'd probably see we're really at cash flow neutral. But if there is the potential where we have a little bit stronger cash flow than we anticipate, we certainly have the program and we are very confident we can deliver on good returns on that program for a little bit higher capital spend. So that we are not doing – not announcing we're doing that, obviously, right now but that potential is there. We have some of the highest, best positions in onshore North America, and we have focused on delivering outstanding returns on that. And we could ratchet up to some degree our capital spending and be confident that we could maintain those returns. As far as the 2017 – or excuse me – the 2018 capital program, basically, what we're – we're not going to give you specific numbers there, but do feel comfortable stating that we're roughly planning to once again spend within cash flow and deliver on our growth targets that we've outlined there.

That's helpful.

Another thing to keep in mind on that, the 2018 capital spend really has a bigger impact on 2019 production than it does 2018 production. Really, the bulk of the 2018 production given the time delay between when you spend the money and you just have first production is largely determined by the 2017 capital spend.

That's great. I guess my follow-up is I wanted to go back to a comment that you all put in the press release just talking about Canada and the tremendous upside exists within your Canadian resource potential. You highlighted $1.4 billion of resource potential there. Wanted to see – obviously, a lot around Canada recently with the market concern around border taxes. How are you thinking about an investment decision at Pike? And given the resource potential that you have in the Delaware as well as the STACK and elsewhere in the Lower 48 portfolio, I was wondering how you guys were thinking about Pike, obviously that's with BP?

Well, that's a decision that we will visit the second half of 2017. We are very confident that Pike is going to be like Jackfish in the sense that it's going to be a top 10% type project in the SAGD. Geologically, it looks just as good if not better than a Jackfish project. And obviously, we've have shown the ability to execute on the construction side at Jackfish as well as anybody and we have the graphs in our operations report that just show the efficiency with which we're able to manage that production too in terms of steam-oil-ratios and it also goes back as well to just the quality of other reservoir. So we like the project a great deal. Now, obviously, the question is not what prices are going to be in 2017, but what we anticipate prices will be when first production happens, which would probably be around 2021 or so. And so we are hoping to get some greater clarity on that question. There are other variables that, obviously, factor into it beyond price and also just the capital costs. We do not necessarily see the proposed border adjustment tax as a negative to Canadian prices. We do see where it could be a positive overall for our portfolio and that the bulk of our oil is in the U.S. and we think it would cause WTI prices to go up. It may cause the differentials to increase a little bit, but not necessarily lower the prices coming out of Canada, because that heavy oil is needed by the refineries here in the U.S. That's what they're tooled to handle. And with the decrease in Mayan crude, particularly too, we think that the draw on Canadian crude will still be there largely. So we don't see that as a negative on our Canadian operations at all. You might even benefit from a positive FX as well, impact to it. So we'll visit that question in the second half of the year. We like the project a lot but, obviously, it does take a – it's a little bit lower return in our well-oriented programs here in the U.S., but the way I'd like to describe is more the bond in our portfolio. It's a lower risk. We know how do it and generate good returns with it. So we'll make a call along with our partner, BP, later on in the year on this.

Okay. Thanks a lot.

The next question comes from Charles Meade with Johnson Rice. Your line is open. Charles A. Meade - Johnson Rice & Co. LLC: Good morning, Dave, and to the rest of your team there.

Good morning, Charles. Charles A. Meade - Johnson Rice & Co. LLC: I'd like to ask a question about the Delaware Basin. And I know we spent a lot of time talking about what you guys are doing up there, in Lea and Eddy counties, but you've got this other center of gravity down there along the Reeves and Ward line, along the Pecos River. And I'm sure it hasn't escaped your attention that there has been a lot of A&D activity down there. And I'm wondering if you could just talk a little bit about what the nature of your position down there is and how testing your development on that position slots into your drilling plans for this year and beyond?

Tony is dying to tell you about it, Charles. That's why we call our Maveda (32:25) area down there. And so, I'm going to let Tony talk about it a while.

Charles, you're right. There is a lot of A&D work down there. A lot of extremely high price per acre transactions have occurred. We've watched that. We've also spent a good bit of a subsurface evaluation time on our position looking at the results from our competitors there. So we think we're in the right country for good return work. We've got activity planned for the latter part of 2017. And again, as we manage our investment in the Delaware Basin, we've tried to highlight the primary areas that we'll be working there in our operating reports. So while we'll be drilling about 100 wells, the majority of those will be in those four areas there in southeastern Mexico. But we are working on some appraisal-type work in the Maveda (33:23) area and certainly watching a lot of activity around us that are helping us de-risk that. So it's a good play, as you mentioned, and something we'll incorporate into our development plans. Charles A. Meade - Johnson Rice & Co. LLC: That's great detail, Tony. Thank you. And, Dave, for my follow-up, I'd like to pick up on something you said in your prepared remarks. You talked about Devon being a leader in Big Data. To the extent you're comfortable, can you tell us where in your operations you're using Big Data that's yielding good results? And what makes you a leader? And what sort of things should we look for going forward from your efforts on this front?

Tony would like to do this one also.

Charles, thanks for the question. And it's probably about three years ago, we made a large commitment internally to be more fact-based and data-driven in our day-to-day work. We spent quite a bit of time in that, we brought in and incorporated some people from outside the industry to help us get through that work. So collectively, it's been a big effort. So as we've taken the information or that data collection and we talk about all the different types of subsurface data that we're acquiring, also that has been included in our surface work. So we stood up some decision-support centers was the first thing that we did, just monitoring all of our producing assets from around the company. Minimizing downtime, trying to maximize the production rate from that, but it really has greatly expanded from that. So while we're acquiring a lot of this information, we've found ways now to get that information in the hands of our technical teams, more real-time than we have in the past. And so the data reporting has elevated us to a new level here internally. We're incorporating that into all phases of our business. And some different areas that we're working on it, as you mentioned, was on a artificial lift reliability. So now we're watching daily information – more than daily information on all of our submersible pumps and gas lift injection rates across the company and are able to better predict the reliability of those pumps. We're able to better schedule maintenance on those pumps so we have limited downtime. We're also incorporating this data into our well flow-back type work. We're able to monitor our rates and pressures and really get the wells off of the well flow back environment quicker. That happens to save about $50,000 per…

Your next question comes from Paul Sankey from Wolfe Research. Your line is open.

Good morning, all. In terms of all your various choices, could you talk a little bit at a high level about the marginal decision between natural gas and oil? It just seems that the prices are so far apart of the two commodities. But I'd like to know more about your sort of thinking in terms of what kind of returns you need? What kind of risk you put on either kind of activity? Thank you.

Paul, I'm not sure exactly where you're going with that, but what I would say is that we obviously are driven by returns in all of our capital allocation decisions. And those returns are largely driven by the – what the anticipated prices are for both oil and natural gas. Given right now the relative strength of oil compared to natural gas, that does mean that the bulk of our capital program is going to those plays that have a higher proportion of oil versus our dry gas type opportunities. We still have some of those in the portfolio, and the Barnett would be the big one and some areas even in a deeper part of Cana for instance, that we're – not have a lot of activity going. So that will drive our capital allocation decisions; they were just our belief in what the relative strength of the commodities will be. And obviously, that not only does it from our capital allocation, but we take that into account when we are making strategic decisions as to where we think the portfolio should be positioned.

Yeah, I mean, I guess it's a fairly simple question but it was really the Barnett that I was thinking of and how come there would be any kind of investment? I mean, how good do the returns have to be given the price discrepancy between the two commodities? And is it sort of a maintenance activity with distributor CapEx going there, or is there genuine – I mean you said that you pursue return, so I just wondered quite how you could get there. It must be...

Well, we're spending money there not to maintain production. We are 100% dedicated to putting our capital where we believe the highest returns are. In the case of the Barnett – and Tony can detail it, we are spending a little bit of capital there this year, not a large amount because we are investigating the – how well a new re-frac design, which may be around $700,000 versus previously is around $1 million to $1.2 million cost to re-frac those wells – how well that is going to work. And if that is successful, it could have returns that are very competitive within our portfolio. There is also the potential that with a modern drilling and completion design that you could also have returns that are competitive within our portfolio. Remember, we haven't had an active drilling program there for several years and there has been tremendous advancements on both the drilling and completion side since then. So we aren't putting a lot of capital into that, but the only reason we are is because we believe that that could lead to a program that could be competitive within our portfolio or anybody else's portfolio if we choose to make a strategic decision around that.

Yeah, I think that's what I was driving at. It's just interesting that there's any kind of activity there. And I guess it's a bit bearish for natural gas that there is. Just the second question would be on the Delaware. Can you talk more about the nature of your activity there? Is it primarily an appraisal-type activity or is it in the exploration realm? Thanks.

Paul, it's really not in the exploration nor the appraisal. We're doing a little bit of appraisal work across our position, but for the most part, we're moving into developments in 2017. And so you will see on the operating report on the Delaware section there, the four core areas that we're working. We've already got three rigs stood up right now working the Thistle area. That's going to be predominantly a Leonard Shale development. We've announced in December that we had a couple of good wells stacked on top of each other in the B and the C, and we've seen industry work in the A. So we think we have a very hearty development plan there for the Thistle area. And Cotton Draw has been an area that we've had a – the majority of our historic second Bone Spring work. And again, we'll have rigs working there through the year, developing additional Bone Springs, Delaware, Leonard and some Wolfcamp-type activity. And in the Rattlesnake in the southeastern portion of our position there, we'll actually be standing up work there in the second half of the year, prosecuting the Leonard Shale but primarily the Wolfcamp. And we've seen some really outstanding results from some operators adjacent to our footprint there in Rattlesnake that have had some stellar wells. So we're really trying to move our Delaware and STACK into the development mode as quick as we can. We continue to do some amount of appraisal work year-in year-out just to prepare for the next year's developments.

Great...

Hey. And Paul, real quick. This is Scott. Just to add on a little bit at the end of that, just to provide a percentage, about three-quarters of our activity is going to be development drilling. And that's one of the reasons why we're so confident with our production outlook with the Delaware Basin. If you look in our operations report, you're going to see greater than 20% growth from Q4 to Q4 on a 2017 to 2016 basis. And obviously, we expect to stabilize production in the first quarter. And even more important, I think, is just how excited we are about the momentum that carries into 2018. So this is absolutely going to be a strong growth asset with some of the best returns in North America.

Great and thank you for your help.

The next question comes from Matt Portillo from TPH. Your line is open. Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc.: Good morning, guys.

Good morning, Matt. Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc.: Just a quick question on the Jacobs Row. Wanted to see if we could get a little bit of color around how you're thinking about the hydrocarbon mix, obviously Hobson's gotten into an oilier section from a development perspective and Jacobs offsets that. And then I wanted to see if we could get any high-level color in regards to timing of, kind of, rig allocation there and when we may start to see first production from that very large development.

Matt, this is Tony again. And just let me start a little bit with the work that we're doing on the Hobson Row and then I'll move into that Jacobs Row there. But we're about halfway through that five-section position that we have in the Hobson Row. And Dave's opening comments, he commented the results we're having there are outstanding and we're on track with that development. What's unique about the Hobson Row, the reason why I wanted to bring this up is that if you start – as you start on the west side of that five-section footprint there, you've got fairly leaner fluid type that we're producing, but as you move through the – quickly move into the heart of those five sections, we have a higher oil content there. And so we've commented that we're seeing 25%-plus oil content. As you move to the far eastern side of that footprint, we expect it to be even higher there. So while we don't have everything completely delineated on the Jacobs Row, I think it's going to be in that higher oily mix, at least to 25% going forward. When we think about the timing of bringing in rigs for the Jacobs Row, we're in the midst of our plans right now. We think that will be the second half of 2017. You can see there that it's a larger development in the Hobson Row. We're going to incorporate the number of rigs and frac crews to timely get through that so we're maximizing the present value of that operation. Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc.: Great. And then just a follow up to Canada. We've continued to see improvements on the operating side in regards to Jackfish. I was curious if there is any other de-bottlenecking opportunities for expansion on the production side. And then a follow on to the comments on Pike. If we think about, kind of, 2018 and 2019, if you were to move forward with potentially sanctioning, what sort of call on capital could we expect, ballpark, around the project?

Matt, I'd tell you, I've got to complement our operating team in Canada right now. They are extremely efficient, they have de-bottlenecked J1, J2 and J3 to the point we're seeing daily production rates, 10,000 barrels, 12,000 barrels per day above nameplate capacity. And that's a function of de-bottlenecking on the surface, but it's also – it's a function of their clear understanding of how to optimize steam injection into that high quality rock. So we're rocking along at a pretty high rate in our minds. We've got some fairly new pads that have been brought on in the latter part of 2016 that has really helped move that production rate up. We're starting to work on another pad that will have some rate benefit in early 2018. But they're doing an excellent job on the Jackfish operating of those plants there. As you think about Pike going forward, it's really a fairly minor capital draw on the company. As you think about that, we're 50/50 with BP. We staggered the capital profile out so, just to give you order of magnitude, if we were to sanction later this year, in 2018, that draw would be about $50 million net and would go to about $150 million for the next couple of years. Dave mentioned, we'll get the first team about 2021. So in the grand scheme of things, it's really about 5% of the company capital as you look out in time. So it's really not that significant. Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc.: Thank you very much.

The next question comes from Scott Hanold from RBC Capital Markets. Your line is open.

Thanks. Good morning. Dave, I hope I won't wear you down again with another, kind of, portfolio kind of question, but when you step back and look, obviously, you talk about the potential of 20,000-plus wells in the Delaware, you're drilling about 100 this year. So certainly it seems like at the current pace, the value potential is not being maximized. But as you step back and understand how industries have been fairly aggressive of buying acreage in the Delaware Basin at what looks like pretty, pretty good prices. And it seems like your desire to maybe want to maximize the value by finding out first what you have and what new technology will show you on those assets. How do you balance the two? And when you look at it, is it more about understanding the potential before you look to monetize it? Or is there a consideration, we may just keep this and decide to outspend cash flow to monetize it ourselves. Can you just give us a sense of the high-level perspective?

Well, I'm not going to announce anything today, so I'm not sure I can really answer that question fully. But I would say we're working both sides to really understand what the potential is in a more complete manner in our core plays both in the STACK and the Delaware Basin, as well as trying to make sure we understand the true value of other assets that may be considered for monetization. You never have complete knowledge. We understand that. There is not a set point in time where you fully understand, and you would make this call. But it's our judgment right now that we would like to learn more rather than make that decision today. But again, it's not lost on us that there is at some point that call will have to be made, one way or the other. And we certainly, as I keep saying it, have not shown any reluctance to do that historically when we think the time is right to do that. We fully understand the values that are being paid in the Delaware Basin. We understand all the variables. I don't need to iterate or lay them all out on the table here I don't think. But we just feel that it would be helpful to have some increased knowledge at this point of the continued appraisal in both the STACK and the Delaware Basin before we make that final call.

Okay. No, I appreciate that. And, Dave, just to clarify. So is the likelihood more or less that if the timing is right, the price is right you'd monetize versus look to outspend to bring forth the value?

I would say it has probably, on balance, probably the more likely scenario, that we would go that direction, yes, I would agree with that.

Okay. No, fair enough. Thanks. And as a follow up, could you clarify too on your identified inventory in the Permian, how much of that is roughly in the slope versus in the basin? And down in the Nevada area, if you could just clarify what the size of that position is?

Yeah. Scott, this is Scott. With regards to the inventory, probably two-thirds is going to be in the basin, which we consider is superior returns to the slope. And as far as the acreage, you're probably looking 55% of our acreage from a surface perspective is going to be located in the basin as well. So we're certainly levered to the basin.

Thanks.

The next question comes from Biju Perincheril from Susquehanna. Your line is open.

Thanks. Good morning. Dave, you talked about two Bone Spring wells in the operations report, and I was wondering, are those wells targeted in similar landing zones as what you've been targeting there? Or would this be something different?

And, Biju, your question, you broke up a little bit. Your question is what landing zones for the Bone Spring in those particular wells? And I will hand it over to Tony. But essentially those are in two very different areas than where we've drilled historically. It was the Thistle area, obviously was one of those areas where we drilled the Bone Spring and I believe it's the Todd area is where we drilled our other Bone Spring. And, Tony, feel free to jump in, but obviously I believe it's a second Bone Spring is what the Todd area would be targeting. And when you think about the Thistle, that might be a more shallow member of the Bone Spring.

Yeah, the Thistle is going to be really dominated by the Leonard development there, but we do have about half a dozen wells in the second Bone that's going to be drilled, but in the Todd area that's going to be largely dominated by the second Bone Springs, a little bit of Leonard and Wolfcamp activity there. We also know that we had the Upper Bone Springs second Bone Spring's member available to us in Cotton Draw and the Todd area that we'll be incorporating into our developments.

But, Biju, just to provide a more global thought when you think about our overarching inventory and the play for the Bone Spring, we have inventory across the first, second and third members of the Bone Springs. So – and it just depends on where you're at within the basin. It can be very localized. But certainly, we're more heavily levered towards that second Bone Spring opportunity, which we believe delivers the best returns.

Okay. And then my second question is in the Meramec, when I look at the Alma pilot versus the Pump House, the middle well in Pump House is performing right in line with the outer wells. Maybe you see it's a little bit lower performance on the bounded wells in the Alma, which I guess is what you would expect normally. Just wondering, that difference in the two, the two pilots is – how do you explain that? Is that geologies or anything that you did in terms of landing zones or completions that would explain the better performance out of the Pump House pilot?

Biju, we were actually happy with the results out of the Pump House pilot. I think that was helpful for us to understand the lateral spacing that we had there. But the Alma was also – was helpful in understanding what it was. We just – we didn't see the communication between the five-well pilot that we pumped in the Alma, and so we've been pleased with the work that we're seeing in both of those. I'd say the repeatability across our footprint there, primarily in the core of the play, has been extremely high. We're continuing to see better performance in the optimization. In fact, if you looked at some of our year-end reserve work, we're able to add a substantial amount of general revisions due to increased performance from a lot of these new STACK plays in comparison to the original type curves. So we've been pleased with all the pilots. They've been very informative to us. We haven't seen a real train wreck out there and we think the play, at least in the area that the industry has been working, is very repeatable.

And, Biju, just one thing to add on with that and it's really kind – we've been asked a lot about the upside with the STACK play. And one of the – one example that's lost on a lot of people but not you would be that with that – with the offsetting well actually not showing degradation, and a lot of that comes down to landing zone. We're still optimizing landing zones in this early-stage play. So as we continue to better understand landing zones and we extend these laterals out further, that's where we expect well productivity and capital efficiency to continue to ratchet up in this play.

All right. That's helpful. Thank you.

Your next question comes from David Heikkinen from Heikkinen Energy. Your line in open.

Good morning, guys, and thanks for taking the question. As I was looking at the Hobson chart in your forecast and your comments about where you were as far as timing into that, I had a couple of questions just as you think about that forecast. First, did that include the 40% of the wells that are above the curve, or is this your forecast before you started bring the wells online?

Well, the forecast is based on our type curve, David.

So your above the type curve. And so can you – what would be great, I guess as you get into second quarter and third quarter is to overlay the actuals because it looks like that would track above that forecast, just given your bullet number two in that section about the request.

Yeah, I think we'll be happy to, David. I tell you when you look at the results we're seeing, it's extremely early. The results have been above type curve and their wells are cleaning up. But if you remember, we're about – we're probably about halfway through on a real-time basis on these – on the completion of these wells. And so the flow-back is pretty early.

Yeah. No, that's cool. And then, Dave, maybe – I'm a little confused around some of the questions on the call of selling parts of your core assets in the Delaware or the monetization as you're in kind of the early phase of appraisal. I guess I'd assume that you guys are still in the mode of delineating and trying to determine what your potential is and that a sale of any of those assets would be not even a consideration yet. And so did I miss something in kind of where investor expectations were, because it's kind of confusing (58:49) that direction.

I believe the questions, David, were not around the sale of any of our core assets, the core of the Delaware Basin or the core of the STACK or anything but were...

The flow?

...more directed around some assets that we could still have some capital programs that are probably well above the cost of capital, but they're not going to compete in our portfolio and not going to receive capital. And so the question is, I believe that the people are asking is, at what point will you make that decision that that's not going to be an area that you're going to allocate significant capital to and might consider for rationalization?

Okay.

But certainly, there is no consideration on our point of selling any of the core assets in our portfolio. We're glad we have them and we think we're some of the best, and we're going to execute on them incredibly well.

Yeah, I guess it was just the high-value acreage that may be on the slope and there's been transactions around it. So it is a little more fringy versus on a big block, of course. So maybe that was my confusion. Thanks for clearing that up.

Yeah, I think they that's probably the questionable area, yeah.

Okay. Thanks.

Well, I'm showing that we're at the top of the hour, and there're still a lot of people left in our queue. So we apologize for everyone that we're not getting to and – but, please don't hesitate to reach out to the Investor Relations team at any point which consist of myself and Chris Carr, and have a good day. And we do appreciate your interest in Devon. Thank you.

Thank you, everyone. This will conclude today's conference call. You may now disconnect.