Welcome to Devon Energy's second quarter earnings conference call. At this time, all participants are in a listen-only mode. This call is being recorded. I'd now like to turn the call over to Mr. Scott Coody, Vice President of Investor Relations. Sir, you may begin. [0FH2DB-E Scott Coody]: Thank you and good morning. I hope everyone has had the chance to review our financial and operational disclosures that were released last night. This data package includes our earnings release, forward-looking guidance, and detailed operations report. Additionally, for the call today, we have slides to supplement our prepared remarks. These slides are available on our website, and we will make sure to refer to the slide number during our prepared remarks so that everyone can follow along. On today's call, I will cover a few preliminary items and then I'll turn the call over to our President and CEO, Dave Hager. Dave will provide his thoughts on the strategic direction of Devon, which we have branded as our 2020 Vision, and commentary on the next steps associated with this multiyear business plan. Following Dave, Tony Vaughn, our Chief Operating Officer, will cover a few key highlights and operating themes that are central to delivering our multiyear development plans. And then we will wrap up our prepared remarks with a review of our financial strategy by Jeff Ritenour, our Chief Financial Officer. Overall, this commentary should last around 15 minutes before heading into Q&A. I would also like to remind you that comments and answers to 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, please see our Form 10-K. And with that, I will turn the call over to our President and CEO, Dave Hager.

Thank you and good morning, everyone. The second quarter was another strong one for Devon. We are executing at a very high level on the strategic objectives underpinning our three-year business plan, otherwise known as our 2020 Vision. For today's call, my comments will be centered on the significant progress we have made year to date toward our 2020 Vision, and I will also touch on a few of the critical next steps associated with this differentiating multiyear plan. Turning to slide 2, the next item I'd like to cover today is the outstanding performance of our U.S. resource plays, which has consistently delivered light oil production results above our base plan year to date. This outperformance has been driven by the record-setting well productivity we have achieved across our franchise assets in the Delaware Basin and STACK. During the second quarter, the momentum from high-rate wells drove U.S. light oil production 12% higher than the previous quarter, exceeding guidance by a wide margin. With the strong well productivity we achieved through the first half of the year, light oil production is on track to advance 16% in 2018. This represents a growth rate that is 200 basis points above our original budget expectations heading into the year. Overall, we're off to a great start in exceeding the light oil objectives associated with our 2020 Vision. Importantly, we are delivering this incremental production growth within the confines of our original capital budget guidance range. With our go-forward capital plans, I also believe it is worth highlighting that even with the recent rise in oil prices, we have no plans to add incremental activity in 2018. While we have a very deep inventory of highly attractive growth opportunities within our portfolio, we fundamentally believe that a more measured investment program through…

Thank you, Dave. I'd like to begin by covering a few noteworthy operating highlights for the quarter. A great place to start is on slide 4, with our Delaware and STACK assets. These delivered 54% and 41% oil growth respectively year over year. This prolific growth was a driving force behind our U.S. oil production beat in the second quarter. The strong performance in the quarter was driven by another batch of prolific well results across the U.S. While the massive Boundary Raider wells filled the headlines last quarter, our Cotton Draw program topped the Delaware Basin highlight list in Q2 with a four-well package that achieved a combined 30-day IP rate of 14,000 BOEs per day. We also had several other prolific wells in the Delaware, with our top 10 wells for the quarter averaging 30-day rates greater than 3,000 BOEs per day. Our other franchise asset, the STACK, also delivered strong operating results in the quarter. Top wells in the play continued to routinely deliver initial production rates in excess of 2,000 BOEs per day, and the efficiencies associated with the Showboat and other initial infill projects are compressing cycle times and driving first production well ahead of planned. And while we are still in the early days of evaluating the performance of our Showboat infill project in the STACK, we have attained peak project rates. The average well at Showboat, normalized for 10,000-foot laterals, attained 30-day rates of approximately 1,800 BOEs per day. With this upside spacing test, from spud to initial flow rates, this project has largely exceeded expectations. However, based on early observations, it appears this development concept is not optimized for rate of return, and is likely spaced too densely. With our initial three infill projects, Showboat, Horsefly, and Bernhardt, we are testing 12,…

Thanks, Tony. For my prepared remarks, I will provide an update on the shareholder return initiatives underway at Devon and discuss the next steps in the execution of our financial strategy aligned with our 2020 Vision. Moving to slide 7, I'd first like to cover how the sale of EnLink impacts Devon's financial statements. With our second quarter reporting, the financial results associated with EnLink will be reclassified as discontinued operations in our consolidated financial statements. Subsequent to the closing of this transaction, which occurred in mid-July, EnLink's financial results will no longer be consolidated with Devon's upstream business. To further assist investors with this transition, we have provided pro forma financials in a recent Form 8-K filing to better highlight the historical performance of our go-forward upstream business. As Dave mentioned earlier, we're returning the sales proceeds from the EnLink transaction to our shareholders through our share repurchase program. In June, our Board of Directors authorized a 300% increase in our share repurchase program to $4 billion. At current pricing, this represents over 15% of our share count and is the largest share repurchase authorization of any E&P company in the industry based on a percentage of market capitalization. As of today, we have repurchased nearly 5% of our outstanding shares at an average price of $41 per share, bringing the total cost of our program to approximately $1 billion. For the remaining $3 billion of our authorization, we plan to utilize a series of accelerated stock repurchase programs, otherwise known as an ASR. We expect our initial ASR to commence in early August once the blackout period related to our Q2 earnings release expires at the end of this week. The ASR programs will allow us to repurchase large amounts of our outstanding shares on an expedited basis.…

Thank you. . Our first question comes from the line of Doug Leggate from Bank of America Merrill Lynch. Your line is open.

Thanks. Good morning, everyone. Dave, with your share price reaction today, I hope you're going to get busy with the share buybacks. I have two quick asset-related questions, if I may, probably both for Tony. Tony, first of all on Showboat, the work we've done in the past, my understanding was that the Lower Meramec extends out in that northeastern portion of your acreage where the Showboat test has been. I'm just curious if you could give us some color as to how many of the wells that you drilled there were in that Lower Meramec area. Did that influence the average production rate? And what's the read-through as you move into the thicker part of the section with Horsefly and Bernhardt?

Thanks for the question, Doug. In our Showboat project, we had – about half the wells landed in the Upper Meramec, half in the Lower Meramec. We saw a little bit of an increased performance from the Upper Meramec. And I'm going to turn it over to Wade. And, Wade, if you can give Doug a bit of a description on the subsurface of where Horsefly and Bernhardt would go, that would be great.

Sure, will do, Tony. Doug, again, half the wells were in the lower, half in the upper. We actually saw about a 25% performance difference between those in that the upper was much more prolific. You're correct, as you move south and west of Showboat into the core of the play, we see the Lower Meramec targets have even higher productivity. And so as we develop both Horsefly and Bernhardt and other projects like those, we have increased confidence that those zones will work in an infill development scenario. And so although they didn't work as well as we thought they would at Showboat, we still feel like they have great potential across other parts of the play.

Wade, did you get the cost benefits that you were expecting?

Yes, we broadly have. I think that's the most successful part of Showboat is on a pace and cost perspective, we met or exceeded our expectations. We were 40 days ahead of plan on Showboat. We saw cost reductions relative to our parent wells. We're even seeing more cost performance on the Bernhardt and Horsefly. Those two projects, which are both all 10,000-foot wells, are projected and they're pretty much done at this point to come in between $7.5 million and $7.1 million per well. So we're pretty encouraged about the cost efficiencies we're seeing.

Thanks. My second asset-related question, Tony, again, it might be for you, but the Delaware, obviously you have been still drilling random one-off couple of pairs wells all over the place toward Rattlesnake and so on. But it looks to us that as you prepare the program going into 2019, the cadence of the completions is obviously an issue, it looks like, as you move into development mode. But I'm curious if you can just walk us through what role the Delaware plays in the dip in your production in the third quarter and how that might ramp as we go into 2019, particularly given how prolific those wells are. Asked differently, it looks like your 2019 program is going to be some pretty strong wells versus the type curve that you based your 2020 plan on. I'll leave it there, thanks.

Doug, I'm going to start off here. Then I'm going to ask Rick to fill in a little bit of details there. But I think we really haven't been drilling a lot of couple-well random wells in the Delaware. We have been appraising a little bit, and you heard us announce the Boundary Raider wells last quarter, which were quite prolific. But for the most part, probably 70% of our activity in the Delaware is really associated with these multi-zone projects that are going quite well. And so we're reaping a lot of the cost and schedule benefits that Wade just described in the Showboat project. They're also happening in our larger multi-zone projects in the Delaware. And so while these projects can be a little bit lumpy, we've sized them to have fairly contiguous – or continuous growth on both oil and cash flow. We're pleased with what we're seeing right now. We're starting to move some of our work in the Delaware from the traditional Second Bone Spring type activity that we've had to the Wolfcamp. And this is really an effort to optimize, again, the developments of the Wolfcamp horizon there. But you're right. You're going to start seeing – we saw a little bit of, I say, a slowdown in pace of IDs in Q3. That's what caused a little bit of the softness in our forecast in the Delaware. That really picks up at the end of the third quarter. And into the fourth quarter, we'll have a dramatic increase in ID count going forward. But with that, Doug, I'm going to let Rick describe just some of the work that we're doing.

Great question, Doug, and this is Rick Gideon. Very much in line with what Tony just said, I'll tell you right now when you look at our ops report, we talk about our Seawolf and Lusitano, Medusa, Fighting Okra, Snapping, and a North Thistle program. So you're seeing that progression into these programs of many different sizes. And what I'll tell you that's based on is the great technical work provided by these teams. It's the understanding of the dependent and independent flow units, whether that be in the Leonard, Bone Spring, or Wolfcamp. So what I think what you'll see are some different sized programs going forward here that we are seeing outstanding results from the multiple horizons, from the multiple flow units in our spacing, not just horizontally by vertically. You've seen some great well results in the Second Bone that tie directly to better technical understanding, better planning, and quite honestly flawless execution as we move through this. With that, we're able to utilize different flowback techniques, and I think you're starting to see the results of just great teamwork, great planning, great execution, and very good technical understanding.

Thanks, guys. I appreciate the full answer. But just to be clear, the Boundary Raider wells, if that's the type of well that constitutes the program in 2019, that's substantially better than the type curve that's set in your current program. Is that correct?

The Boundary Raider wells are special wells, Doug, and we've got some offsets to drill to the Boundary Raider, which are going to be a really good development, and we're going to be kicking that area off later this year. But as you look at our current operations report, we just reported some really good wells in the Cotton Draw area and the Second Bone Spring. Those are also really good wells. So I'd say in general, our performance from our wells is better than it has been in the past. The subsurface understanding from the technical teams is just outstanding. So this commitment to the data acquisition and being data driven has really paid off for us.

In general, I think, Doug, the comment is absolutely the Delaware is running ahead of plan.

That's the answer I was looking for. Thanks, Dave.

Our next question comes from the line of Scott Hanold from RBC. Your line is open.

Thank you. Hey, a follow-up question on Showboat. You did obviously mention there were some I guess a bit stronger declines. Was that related to the parent well being obviously three years old in the area, or was it more the Lower Meramec? And if you could, also comment on what you saw with the Woodford well.

Sure, Scott. This is Wade Hutchings again. I think there are three big preliminary insights we've taken from Showboat. The first is the difference in performance between Upper and Lower Meramec, which we just discussed. The second really relates to your question, and that is a very clear trend that any of the wells in either the upper or the lower that were drilled in the parent well's shadow, those underperformed relative to any of the wells that were in more of what we'd call the greenfield parts of those sections. And underperformance would be reflected at both an IP and even at a decline level. The third key thing we observed is we're seeing some initial indications that there's more vertical connectivity between these reservoir landing zones than we may have saw in other parts of the play. And so those are really our key preliminary observations so far from Showboat.

Scott, this is Dave. I might add that I think at this point, though, you have to be extremely cautious about extrapolating any results that we have from Showboat to the remainder of the STACK play. It is very early on. We are taking the learnings there and we're adjusting our go-forward development plans in terms of spacing. The ones beyond Bernhardt and Horsefly we're adjusting the spacing, as we think that's the right thing to do in the short term. But it's not clear that that's the only answer that's going on here too. And so I would certainly be extremely careful that we have had some challenges here at Showboat. We knew we were testing the upper limits of the spacing. That's proved to be true, but we're learning a lot from that. And I think that there's a lot more to learn, and we'll learn a lot more as we proceed through the next several development projects here. But to take the results from Showboat and extrapolate a general learning across the entire play, I think it's very premature to do that.

Okay, understood there. And on the Woodford, did you have a commentary, any comments on the Woodford well?

So that Woodford well would be one of the furthest north Woodford oil window wells, and right now it's still in a phase where it's still in flowback. So we don't really have a lot of hard conclusions to make on the Woodford prospectivity extent at this point.

Okay, understood. And then in the PRB, it looks like you guys are looking to expand your program next year to maybe four rigs. Can you discuss what you're seeing there and what we should be looking forward to?

Scott, I think again, the work that we're doing, primarily in the Turner, is really providing a lot of good insight. We've done some spacing tests there. We're very pleased with what we're seeing. Every well that we bring on is really some of the higher rate of return wells that we have. So we're starting to define what the development plan will look like. We're also having some positive results in the Niobrara. We haven't commented on that specifically yet, but both of those parts of our program are developing very well. And so I think what we're trying to infer is later this year we'll not only pick up the second rig, pick up the third rig, and then in 2019 expect to be in full development mode there with increased activity beyond that. So everything that we're seeing in the Powder is developing just to plan.

Okay, so it's definitely in the Turner and both in the Niobrara what you're seeing results that could be – you could be active on next year?

Primarily. And not to shortchange some of the work that we typically do in the Parkman and the Teapot, those always deliver good results. But really, as we've commented in the past, the Turner is more of a resource opportunity for us, and that's what is being uncovered right now. So that will really drive a lot of the pace of activity in the Powder.

Got it, thank you.

Our next question comes from the line of Bob Brackett from Bernstein Research. Your line is open. Robert Alan Brackett - Sanford C. Bernstein & Co. LLC: I had a question on your comments trying to unpack this notion of strategic high-grading. If we look two to three years into the future, what assets are you highly certain stay in the portfolio, and what assets do you think could find a home for someone else? And then I have a follow-up.

Hi, Bob. First off, we believe very much in the multi-basin approach, and I think you're really seeing the benefits of that approach right now as we speak. We're having outstanding results in the Delaware Basin. Tony just described some very promising results that we're seeing in the Powder. Overall, we have a strong inventory in the STACK. We have admittedly had a little bit of disappointment here, not tremendous, but there's a little bit of short-term with Showboat with one development in the STACK, but with 90% of our development still in front of us we're adjusting quickly, and we still have some strong, really strong return opportunities in the Eagle Ford as well. So we believe that this multi-basin approach that allows us to shift capital between several high-return basins is the absolute right approach, and it really optimizes returns versus being overly dependent on one specific play. But we look at a lot of different things when we look at what may or may not remain in the inventory. We look at what is our overall depth of our development inventory, what's the intrinsic value of the asset that we may be looking to monetize, and what is its production and cash flow contributions. We look at what are the prevailing market conditions out there. And obviously, we have teams that are very engaged and understand the market from both a buy and a sell standpoint extremely well. And when we identify an opportunity to pull the trigger, we're not afraid to do so. If you look at our history here, we've had about $30 billion worth of transactions over the past decade. I'm not going to telegraph today specifically what may or may not, but those are the key issues that we look at here. We think we have a very strong inventory where we are, and we'll continue to evaluate conditions as we move forward. Robert Alan Brackett - Sanford C. Bernstein & Co. LLC: Okay. So getting a little more granular, when you talk about the spacing tests in the Turner, are you aligning those wellbores parallel or perpendicular to that old Cretaceous Seaway?

Most of those are running in a north-south direction throughout the play. And we're spacing those – in the areas that we have two horizons in Upper and Lower Turner, there's a staggered pattern. And so it's not just about one horizon. It's understanding the different horizons and what the interaction is between the two. Robert Alan Brackett - Sanford C. Bernstein & Co. LLC: Great, thank you.

Our next question comes from the line of Brian Singer from Goldman Sachs. Your line is open. Brian Singer - Goldman Sachs & Co. LLC: Thank you, good morning.

Good morning, Brian. Brian Singer - Goldman Sachs & Co. LLC: In the Eagle Ford, I realize per your comments, you haven't had discussions with the new operator. But what rig count or level of activity do you think would be optimal for Devon in an accelerated case? And if this were to happen, would you reduce capital elsewhere in the portfolio, or would you use your free cash flow or balance sheet to increase activity in the Eagle Ford?

We're currently running two rigs there, Brian. I think in an optimized scenario, we'd run three rigs. And so frankly, that's not a large incremental capital spend if you look at the overall size of the company as Devon. So it's barely a material question, I guess you'd say, as to whether you'd drop activity elsewhere or use some of the incremental cash flow. If we were going to do that, that would be a 2019 event. We anticipate that would not be a 2018 event that we would change the program. And those returns, just to refresh everybody, are as strong as anywhere in our portfolio, particularly given the fact that we're getting WTI-plus pricing on those barrels. And we've done a great job with locking in well above the current market pricing in the Delaware Basin, incidentally obviously also in our heavy oil in Canada, but still not as strong as we see in the Eagle Ford. So with those flow rates compared to the costs, they compete extremely well. But we don't see rapidly increasing the capital, but we do see one incremental rig would probably be helpful in 2019. Brian Singer - Goldman Sachs & Co. LLC: Great, thank you. And then my follow-up is with regards to the company's CapEx. You reiterated that you expect CapEx to trend towards the top end of guidance. Could you give us a little bit more color on the push and pull there, what you're seeing on the inflationary front, what you've done from an activity perspective relative to your expectations and whether the Permian completion crew on for less time during the second half is helping to keep CapEx in check, and what you think the risk around the top end of guidance is to the upside and downside?

Brian, number one, I think as we mentioned in some of my prepared remarks, our supply chain and our operating teams have got a three-year plan that we are sticking really close to that allows us to go out and secure services for an extended period of time compared to a lot of our peers. So we feel like we have mitigated any of the stress or the inflationary factors that others are probably seeing in the 2018 timeframe. So we're doing some really good work. We're not outspending the cost and schedule management of our projects, as Wade and Rick have already talked about, have been on track. So we're doing really well there. We think our OBO spend has actually been an increase and a little bit of a surprise to us early this year, and starting to see some benefits from that. So that's really keeping us at the top end of the curve. But I think what you'll see is we had a very hot Q1 and have tapered back a bit, as you noticed, a 10% reduction in Q2, and we'll manage our spend in the second half of the year according to our original plan. And we just think this exercise is good discipline, and it's there to maximize the return of our projects.

Basically, Brian, we're executing our plan a little ahead of schedule. We have a little extra OBO spending. It's not on the cost side because we're managing that extremely well. And certainly the decision not to add a third frac crew in the Delaware was not driven around trying to stay within capital. It was driven by a returns decision. And so basically, we are able to have one frac crew, I think, Rick, you'd say per four rigs that we have working out there, and we're able to keep up with it. If we added a third frac crew right now for just a few rigs, basically what that would mean is when we come early 2019, we would have two long-term frac crews, one of which probably wouldn't have any work to do given the timing of all of our schedule. So from a return standpoint, that doesn't make sense. And so it makes more sense to stay with the two who can manage the eight rigs. Now we do see going to three frac crews in 2019 as we continue to increase the activity. Brian Singer - Goldman Sachs & Co. LLC: Great, thank you very much.

Our next question comes from the line of from Subash Chandra from Guggenheim. Your line is open.

Thanks. The Showboat, I'm just curious if the results there have any impact on the prior exit rate guidance in STACK, or if it has any sort of tangible impact on your growth expectations in the intermediate term.

I'd say it has no impact on our growth expectations under our Vision 2020. We have enough projects of different types and high quality that this, our Vision 2020 is absolutely totally intact. Now, could it perhaps have a minor amount of downward pressure? The question might be asked too. Why didn't we raise oil production guidance, I guess, for the remainder of the year? And admittedly, because of the Showboat issues, we thought it was more prudent until we see more data and we get the Bernhardt and Horsefly wells on to not raise production guidance, even though we exceeded it in Q2. So yes, throughout 2018 I would say that that did impact our short-term thinking on raising production guidance. But we have a very deep inventory of projects throughout the company that the 2020 Vision and our growth that we anticipate in oil production, U.S. light oil production, is absolutely intact. We're seeing outperformance, for instance, as we talked about, in the Delaware Basin. We're seeing some very strong upsides for the Powder River Basin, great returns from the wells we're seeing in the Eagle Ford as well. So maybe a short-term timing impact on production, but absolutely the potential that we chose to guide conservatively with regards to. But no implications at all to the long-term vision of the company.

Okay, I appreciate that answer. My follow up is, I apologize if I missed this in your earlier commentary, the Turner spacing test. So what is that architecture? What is the spacing test exactly? And would this be one of the first spacing tests in the Turner – in the play?

This is Rick Gideon again. There have been different spacing tests. And again, I want us to be careful on which part of the field we're in, whether you have an Upper Turner, a Lower Turner, or a Middle Turner. We've tested between two and four wells per section in each of those horizons. And so these latest tests were two wells per horizon or four wells per section and an upper and lower. I think you've seen some competitors do very similar testing. And as I said, we tested at four earlier in the year.

Okay, thank you for that clarification. Thanks.

Our next question comes from the line of Matt Portillo from TPH. Your line is open. Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc.: Good morning, Dave and team.

Good morning. Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc.: The first question I wanted to ask is with regards to STACK completions. You mentioned that you're working to mitigate some of the parent well impacts after viewing the initial data on the Showboat project. I was curious if you could talk about some of the completion changes you might be envisioning, if at all, around proppant loading, cluster spacing, and fluid use that might help optimize development on a go-forward perspective.

Matt, I think we are in the middle of evaluating the specific completion design we had on Showboat and have already taken those learnings and started to apply them even to Bernhardt and Horsefly, which have already been stimulated. And so that's a pretty active process for us. I would say the broad trend is we are a little bit more of a macro scale. We're looking at specific reservoir targets and their rock properties, and we are beginning to more proactively adjust the stimulation parameters based on each of those reservoir targets. Again, some of that's learnings from Showboat. Some of that's learnings that we saw in other projects. On maybe a more specific stimulation approach, I would say that what we're doing is we're beginning to apply much more limited entry type approaches. We've tested a few things in Horsefly and Bernhardt that we think have promise around different technologies that allow us to really target exactly what part of the reservoir, what part of the lateral. And a couple of those is we've tested some NCS sleeves in one of these projects that we think actually has a lot of potential for us. So you'll see us continue to evolve that in much more of a reservoir-by-reservoir specific targeted way. Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc.: Great, thank you. And then my follow-up is a question regarding Jackfish. I was wondering if you could provide additional color on the maintenance requirements that were identified that took down Q3 guidance to some extent. And as we look forward to Q4, any color or context around how we should think about the peak rates mentioned in the ops report?

Matt, I've got to remind us, the maturity of our Jackfish 1 project is different than it was probably the last turnaround. In fact, we've been producing J1 over ten years now, so our turnarounds at J1 were more extensive than they had been at some of the younger projects. You've got to remember, we're operating some of these steam lines at 450 to 500 degrees F. So in the process of cooling and heating these lines, we tend to see movement, and those lines are designed to move. We have pipe racks to guide those lines through there. During the ramp-up period for J1 after the turnaround was over, we saw increased stress in one particular area, so we immediately took the project back down and went through an extensive evaluation and mechanical integrity inspection. And at the same time we were doing that, we took a good look at one of our oil lines as well. And so that really deferred our startup at J1 by about 15 days. It also deferred the startup of a couple of new pads out there. So we're getting a little bit of a slow start in Q3 associated with those couple of events. And then as we ramp the project back up, we fully expect to grow back into something near the historical rates that we've seen in the past. But again, you've got to always recognize that as these projects mature, there's going to be slightly more maintenance associated with them. And the SOR [Steam/Oil Ratio] is just slowly starting to creep up. So there's a little bit less steam capacity that we have available to work with. Overall, the projects are working extremely well. And outside of these two unplanned events, we're back to operating as normal. Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc.: Great, thank you very much.

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

Hi, good morning. Dave, looking through your various spacing pilots in the STACK, Delaware, Powder, it looks like the approach you're taking is that the initial projects, the spacing is something on the aggressive side, and then you're working backwards. And I don't know if that's a fair assessment. But if it is, is the idea that you can get to the final answer in fewer iterations, are you getting more information in the pilot that actually has some interaction between wells?

Absolutely, I think you've nailed it. We want to learn early because we recognize in all of these plays that the vast majority of the development is in front of us. And so we have, just as we did, if you go back even a few years ago on completions, and when you may have said historically we're pumping 600 pounds of sand per lateral foot, we could have easily taken the approach to go to 800 or 1,000 and test out what it is there. But we took the approach there that says let's go on to a much higher concentration, up to 3,000 pounds or so, and learn early where the upper limits are, and then we can dial back a little bit. I think you can take to a large degree that analogy and apply it to what we're doing with our spacing tests. We chose to learn early. Frankly, we also collected a huge amount of data on the Showboat project, which we think is going to help inform us as well. And we recognize that it was aggressive, the spacing, but we'd rather if we were going to have an issue, we'd rather learn that early versus just slowly, incrementally up the spacing and get large – long distance into the development of the overall play before we really learn what's optimum. So there's some pain with this process, we admit that. We're feeling it a little bit today. There's no question about that. But we think that overall, that is the right long-term decision, and leads to a higher returns and higher value in the long run.

Got it, that's very helpful. Do you think at this point if you're looking at STACK or the Delaware that you – how close do you think you are to that, call it, optimum spacing?

I'm going to let the guys that are a little bit closer – I think you're going to hear an answer that's fairly granular. It's going to vary still across the play and across the formations. I don't think there is an easy answer, and I think we're still – we're learning a lot more, but I think we'll continue to learn, but we've certainly accelerated the learning. So, Wade, do you want to kick it off and maybe Rick will make a comment from the Delaware perspective?

Sure. So from a STACK perspective, we are systematically testing multiple density frameworks and spacing stacking frameworks. So as you saw, the next two projects that will come online within a couple of weeks here in August, Bernhardt and Horsefly, are testing slightly lower density than the Showboat. We have other projects that you'll see over the next six months where we may only test one layer, the Upper Meramec. And so that will vary across the play. Ultimately, we think as we approach the end of the year, we're going to have a number of operated tests under our belt that will range in spacing anywhere from 6 to 12 wells per section. And from that, we'll be able to essentially narrow down what the go-forward development plan will look like. But I think to Dave's point, that's unlikely to be just one model for the entire play. We see that these reservoir targets change quality as we move around the play. We know that pressure, conditions, and even fluid windows change. And so we will ultimately have a fairly customized development framework for multiple sub areas of the play. And we think as we approach the start of next year, we'll be in a much more solid place to lay that out, both internally and externally.

Biju, this is Rick Gideon. For the Delaware, very similar. What I'll tell you is it's dependent, as stated, whether it be in the Todd area, Thistle, Cotton Draw, Rattlesnake, or Potato Basin, the five areas that we talked about. What I'll tell you also is it ties very much to flow units. It's not just a single horizon. It's not just the spacing. It's the staggered pattern. It's in the Leonard. Whether you have A, B, and C, how many wells does it take to most efficiently drain that and have the highest rate of return while preserving value? We're probably, in the Bone Spring, we're probably the most mature as we talk about it. Leonard following, and Rattlesnake is where we're doing a lot of the testing right now in the Wolfcamp, which is probably less mature on the spacing. And as we take a look in the Wolfcamp, we have to keep in mind that we're looking at your Third Bone Spring, your Wolfcamp X and Y, your Wolfcamp 110, 120, and 130 as one single flow unit. So as we model that, we have to understand the stimulated rock volume by the types of jobs we're pumping, and what is that horizontal and vertical reaction between those wells.

Biju, this is Tony. I just wanted to highlight too that we probably have on the operated side alone, we probably have a library of 6,000 horizontal wells that we worked in. And the majority of those have had parent/child relationship issues that we've worked through. We're going to continue to learn in all of these plays. The technology continues to change. The guys are getting smarter. New data just leads to new developments. We're seeing some of the best completions we've made in the Eagle Ford today. We're seeing some of the best completions we made in the Cana-Woodford project towards the end of 850 wells. Same thing in North Texas in the Barnett. We're seeing some of the best wells now after 3,000 or 4,000 wells have been drilled. So this is not a single answer that you're going to hear from us. We're going to continue to learn and grow.

Very helpful, I appreciate that detailed answer. Thank you.

Our next question comes from the line of Paul Sankey from Mizuho. Your line is open.

Based on everything that you said, and thanks for all the detail, it does seem that it's difficult for you, for a couple of reasons, to accelerate in the Eagle Ford or the Delaware much more than the pace you're already running. So I wonder. Does that mean that we're very, very dependent on results coming through in the way you've described? And I totally understand that you're saying that there's 90% of the work still to be done. But do you think that the risk has become higher on the STACK in terms of its importance for you and Vision 2020? Thanks.

No, Paul. I don't feel that way. We do plan to have an escalating program in the Delaware Basin as we move into 2019. We haven't laid out the specific plans, but I think we're anticipating having on the order of three or four more rigs working out there. That's directionally the way we're thinking right now. We're looking at adding more rigs in the Powder River Basin. Tony talked about that. So no, I don't think that's true. I think that we've had outstanding results in both of those areas as well. The Eagle Ford we're not counting on for significant growth, but we do think we can stay – keep production flat there with three rigs, and we think that will be optimum. Having said that, we do anticipate STACK is going to continue to grow as well. So I don't want to talk down the STACK at all because we're learning very quickly and we're adjusting and we anticipate a very successful STACK program going forward. It is going to be an important part of our future.

Understood. Thanks, David. Can I just ask a follow-up, which is totally unrelated really? Has your hedging strategy changed subsequent to Vision 2020? Thanks.

No, it hasn't. We fundamentally think that, first off, that we want to have a consistent and predictable capital program because we think that having a consistent program where you're not ramping up activity or not ramping it down is how you deliver the highest returns. If you rapidly increase the capital program, you may not be ready from a technical standpoint or an infrastructure standpoint to be able to deliver optimum returns. And if you ramp down the capital program, you lose some of the efficiencies that you get with a certain level of scale on these – when you have multiple rigs working, for instance, on an individual development. And so you lose some of those efficiencies if you ramp it down significantly. So with that thought process in mind, we think it's important to underpin the cash flows of the company to make sure that we have a certain level of consistency in cash flows to be able to fund the capital program. And so we are doing this through a systematic program largely, where we're reaching out 18 months and hedging production at any given time. We do leave some room for discretionary hedging as well, but it's all within the context of underpinning the confidence in what prices we're going to receive. Obviously, we're hedging on the differentials too, which has provided quite a bit of benefit for us this year in terms of pricing. But we think that's fundamentally important to deliver consistent, strong returns with our programs.

Thank you, sir.

Our next question comes from the line of David Heikkinen from Heikkinen Energy Advisors. Your line is open.

Good morning, thanks for taking the question. One thing I was curious about is the importance of sequencing your drilling, then completions, then putting pads on production across the section and then across multiple sections, and any differences that require sequencing between what you've seen in the Delaware, STACK, and now the Powder.

Hi, David. This is Rick Gideon. Absolutely there's some difference in sequencing, and the teams do a great job on the planning side of this, whether it be with our frac crews, rigs, or other services. It's very dependent on how many horizons you're going after. In the Delaware, we've done some tests where you're hitting six different horizons. What I'll tell you is through our learnings and understanding the flow units, you'll see some areas, especially in the Delaware, where you'll see some smaller projects where we develop one flow unit, move away and then come back and develop the next flow unit to better utilize our surface facilities and infrastructure within the field, as well as water, et cetera. So I think as we move through this, you're going to continue to see how we change based on spacing, but based on flow units also.

Just to follow up on that, how do you think about the scale of required capital and working capital that is invested and what's required for – a company the size of Devon can fund it, but maybe smaller companies, that becomes pretty important and pretty meaningful as you think about that fixed horizon development and the number of wells potentially. Have you done any math on how much capital you actually put into the ground before you turn it on production?

We do. We've done a lot of math on I'd say what is the optimum size development to optimize the rates of return. I think we probably have the capital to fund whatever is the right answer, but we do think that there is an optimum size in many cases to what optimizes the rates of return.

This is Wade. I would just jump in real quick and say we're absolutely focused on the fact that time is money, and so we're very much focused on eliminating as much float in the schedule or white space in the schedule as we can. But to Rick's point, this often is a very technical set of judgments. For instance, on the two Showboat sections, there were six pads, and the team had a very specific order of which pads to stimulate and which pads to flow back in what order because of the impact that they would have on surface operations and even subsurface operations. And so it's an area of intense work for us.

That's helpful, and just one final. What are your current well costs? You gave us the Delaware – or you gave us the STACK. What are the Delaware and Eagle Ford current costs?

Dependent on the horizon in the Delaware again and dependent upon some of these new, we're in the $7 million range on a lot of these down to about $5 million – $5.5 million on some of the shallower zones. We're very early as we move into the Wolfcamp, but we are seeing progression of that lowering.

David, the Eagle Ford wells lately, we're putting a little bit larger sand loading in these wells, and they're running about $6.5 million.

Thank you. [0FH2DB-E Scott Coody]: All right, we're now at the top of the hour. We appreciate everyone's interest in Devon today. And if we didn't get to your question, please don't hesitate to reach out to the Investor Relations team, which consists of myself and Chris Carr. Have a good day, thank you.

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