Welcome to the Devon Energy Second Quarter Earnings Conference Call. At this time, all participants are in a listen-only mode. Today conference is being recorded. I would now like to turn the call over to Scott Coody, Vice President of Investor Relations. Sir, you may begin.

Thank you, and good morning. I hope everyone has had the chance to review our second quarter financial and operational disclosures that were released last night. This data package includes our earnings release, forward-looking guidance, and detailed operations report. Also on the call today are Dave Hager, President and CEO; Tony Vaughn, Chief Operating Officer; Jeff Ritenour, Chief Financial Officer and a few other members of our senior management team. I would 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 related to these statements, please see our Form 10-K. And with that, I will turn the call over to Dave.

Thank you, Scott, and welcome everyone. Devon achieved another high quality operating performance in the second quarter, building operational momentum in our U.S. resource place and accelerating efficiency gains across our portfolio. These successful efforts result are in a record study and well reserves that growth of our U.S. oil production above guidance expectations with a capital investment that was 17% below our budget year-to-date. As a result of this strong capital efficiency we are lowering our full-year capital outlook by $100 million and importantly we have not made any changes to our planned activity levels in 2017. For more details on our very strong performance for the quarter, I encourage every investor to read about our Q2 operations report. With this momentum, we are highly confident in our ability to deliver value and returns on our investments plans over the next few years as we navigate industry conditions. For 2017 our capital plan remains on-track to reach 20 rigs running by year end and we expect to maintain this operational momentum in 2018. Importantly nearly all of these plan drilling activities concentrated within our STACK and Delaware Basin assets which are two of the very best position place on a North American cost curve delivering attractive returns even at today’s strip prices. To be clear, we are not chasing product growth with our capital programs and remain keenly focused on maximizing our full cycle returns. With this disciplined approach to the business, I can confidently say that this drill bit activity is a very appropriate level of investment for Devon in this environment. Providing additional certainty to the execution of the business plan is our strong financial position. With a disciplined hedging strategy, we have stabilized our cash flow stream by locking in roughly 55% of Devon’s estimated oil…

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

Your first question comes from Doug Leggate with Bank of America. Please go ahead.

Thanks. Thank you. Good morning, Dave. Good morning everybody. A couple of questions Dave. I guess the one is kind of the housekeeping issue on Canada. Can you just walk us through just the issues in the most recent quarter and the trajectory as we move through the backend of the year. just trying to get a handles as to what do you think the sustaining production capacity in the auto sign at this point. And I have got a follow-up please.

Great. Doug and I’m going to let Tony answer the details. Obviously, we did encounter what we consider to be a one-time maintenance event is it impacting our production. In July we’ve actually move beyond that that’s fixed that issue is, but Tony can give you the details of that. And I can tell the asset in general is performing outstanding, we just had a one-time maintenance event that’s in a rear view mirror as we sit here today and things look outstanding from this point forward. So, Tony you want to follow-up a little detail on that.

Yes. Good morning, Doug, Doug at J2 we have these very large skim tank vessels there that are really of large diameter vessels this got dapples in it, it is designed to move water and oil through a last stages of separation and extend the retention time. And what we found was we have a pretty sophisticated leak detection system in our Jackfish projects we recognized that we had a small leak in the J2 skim tank areas. So, we got in there and recognized that what we suspect is through vibration of the flow into those dapples that were down the bolt and brackets system causing some of those brackets to drop, one dropped and punctured the bottom of that vessel. So we got in cleaned the tank out and took a look at it, we knew exactly what the problem is, so we only did that on J2. We also just did a turnaround in J3, we suspected this issue in J2, so we have been in the in two of those skim tanks in the last 30, 40 days and we will be in the third at J1 within 12 months from now. So really it was an isolated event that’s now behind us and I think we had this solution remedy and if you just look at the forward just like Dave mentioned, we have production at all three of these Jackfish plants really operating at name plate and above. In fact J2 and J3 the two that we just took down that are already rent backup and access of the name plate capacity and expect both of those to be back in the mid 40,000 barrels of oil per day. So when we get into the Q4 with the claim quarter we will be back into that 140,000 barrels of oil per day range and again a long life project in front of us. So this is just one of event that’s in the rear view mirror now Doug.

I appreciate the color. Thanks for that. I guess that the follow-up is, I’m not quite sure how to ask this question efficiently. So when you look at the third quarter guidance I think at least versus the dump sale side that was a little bit late, but still you hasn’t change which I think chemist speaks to the potential lumpiness of moving to these very large developments are going to characterize the production profile I guess forward. So I just wondered if you could help us navigate that a little bit in terms of what that trajectory you had laid out with all these very large full-field developments going on, what that could look like as we go into next year and how you how ratable you expect that goes to be in I guess there is multiple pieces but I will leave it there and let someone else jump on. Thanks.

If you look at the issue that happened with probably maybe a little bit like guidance compared to what some people are expected in Q3 on the U.S. oil side is we had a large number of completions in the Eagle Ford in Q1 and that caused really strong performance compared to guidance in Q1 and also carried over to some degree into Q2. But those wells obviously fall off fairly quickly. When we originally put the budget together we had anticipated a little bit more balanced on the completions in the Eagle Ford and have submit in more in Q2 it would cause a little bit higher production in Q3 and where we ended up. So in essence we completed those wells early, caused strong performance Q1, Q2, we had no Eagle Ford completions in Q2 because we got them done early and so that caused Q3 Eagle Ford to fall off a little bit more than was originally anticipated. But again extremely economic wells, some of the best in the portfolio we just moved the production forward as water boiling down to. As we get more into the full development, what is going to happen is that we are going to have multiple numbers of these multi zone developments going at anyone given time and certainly in any individual one you can say there will be lumpiness, but we think there will be enough of those. It’s not going to call us extreme lumpiness in the overall production profile for the company and keep in mind also that even as we are moving into these ,the bulk of these are going to smaller to start with and as we get further on in the development they will growing size most likely, but by then we have even more going. so that’s sure there are going to be some lumpiness to it, we anticipate with a number of lumpiness or should be the number of developments we have going on. The lumpiness will not be too magnified.

I appreciate the answer, Dave. Thanks a lot. I know it’s a tough thing to describe.

Yes. And let me just emphasize to we’re still on target to grow our U,S, oil production by 2018. And so there is no change in that guidance at all.

Great. Thank you.

Your next question comes from Evan Calio with Morgan Stanley. Please go ahead.

Hi, good morning guys. Yes. When are your STACK developments schedule for next year, Coyote, it’s in the far north western areas of your acreage. Just any color, do you think that to be party or acreage as de-risked or mature for development or is that dependent upon Coyote. And maybe more generally, if you can just discuss raw quality well performance or expected well performance difference between your focus areas in Showboat [indiscernible] and what do you expect around the Northwest Coyote?

This is Tony here. I just kind of describe to you that we have broken down our footprint in the STACK prospect here into several different what we call the appraisal areas and of course Showboat is really in appraisal area one where we’ve had some lot of success we’ve reported on that but we’ve also been in the process both us and industry de-risking our next couple of appraisal areas. And so, the Coyote project will be in one of these top couple of appraisal areas that we have been de-risking. So, the way we look at this is we’ve got a great understanding and the Meramec 200 and the Meramec 300, you are starting to see some results come in across the board and Meramec 400 some from Devon but some from industry. We have seeing some in the west from other operators that have not performed up to the same quality of results that we’ve seen in the 200 and 300, none of that was unexpected I think from us, and I guess I got to remind everybody on the call Evan that this commitment that we have to being highly data driven is we think is really laying us out to be a the premier operator in the field. Number one, we have got what we think is the best footprint in the play, but really we have this commitment to being data driven and have acquired substantial amount of subsurface data, we’ve built that into the three dimensional earth models and that’s really the basis for all the design work going forward. So, when you look at some of the results we have over there, industry is doing a good job right now of piloting different ideas from spacing and lateral intervals to vertical connectivity type testing to just simply appraising different horizons. And we’re moving into what we think are going to be the sweet spot of each of these intervals that we’re in. So we are expecting a good performance out of the Coyote project.

Great. Thanks. And maybe second if I could. Yes, Jacobs Row was downsized I guess not surprise given commentary for your partner. How do you deploy free of capital from lower non-op activity in 2018. And could you provide us some color on how do you would compare Woodford full development returns versus your STACK Meramec or your Delaware program and I will leave it there?

Yes. Well obviously we look at our portfolio across the entire company and we allocate our capital to those on a risk adjusted basis provide us the highest return. And so we when we look at redeploying capital such as that, we will look across the entire company and see where the best place is. I can tell you in general that we will be redeploying any capital there back into the Meramec development or into the Delaware Basin development. Those are very good returns, so we think we’re going to get there, but we think we have - they are probably a little bit less on average, we would say that we can get from our Delaware and Meramec program but not significantly less, but there is obviously less condensate production on those than the other players were pursuing. So that’s where the capital would be redeployed.

Okay. Thanks a lot guys.

Your next question comes from Ryan Todd, with Deutsche Bank. Please go ahead.

Thanks. Maybe one question on CapEx if we look at the CapEx that you announce that the full-year, what were the primary drivers and how do you see those trends as sustaining or evolving over the course of the year.

Well the primary driver for the CapEx reduction is just the increased efficiency that we have been able to achieve in across the entire asset base, I would say one big factor in that as our supply initiative where we have decoupled much of the completion activities where we are supplying our own sand our own diesel and we see significant savings from that. We’re also just through the use of our advanced predictive analytics, artificial intelligence work we are finding that not only are we is it helping deliver best of any operator a 90 day IP, there is also driving our costs roller as well. So we feel really good about where it is, we’re very confident obviously the $100 million reduction there maybe some upside to that we will have to see how the second half goes. We do anticipate there maybe some increase inflationary pressure in the second half of the year and so that may drive our costs a little bit higher than they were in the first half of the year. We will just have to see how that goes, but we decided as appropriate at this point just take what we are sure of which is a $100 million reduction and then see how things evolve in the second half of the year.

So far the early takeaway is which I think Jacobs Row with some of the first kind of larger scale unbundled efforts that you had made on supply chain mainly, the takeaway has been a little bit better than expected. Is that fair?

And the efficiencies across our entire portfolio of just drilling wells more effectively, et cetera. Yes.

That’s great, thanks and then maybe one follow-up question on the Meramec. You had some comments in there about results that you have seen in-production results today, have you seen any spacing pilots in the Meramec. I think there has some noise and confusion around some of the pilot results that we have seen across the play from some of your peers in the basin that’s caused them concern. So any thoughts that you can share on what you have seen so far across the spacing pilots and views on what that it means for kind of full-field development in the Meramec?

I will kick it off, I’m going to probably just going to repeat what Tony did, maybe are just slightly different words here, but if you look at it our operated spacing tests have been very, very successful. We have seen on some of the outside operated spacing test or has been some very successful and ones but some have had mixed results. When we look at those test that others have done, we can’t say for sure why they tested it exactly what they tested, but the results are not a surprise to us. Now, without going to the specifics of each one sometimes we’ve seen that they have been testing zones that we know have would be thinner and wouldn’t have the kind of productivity as other zones that are in the same geographic area. Why they tested that, they are probably just trying to get an idea of the productivity of our secondary or tertiary zone we suspect. In other cases, we know that they have been grilled on the fringe of what we consider the key part of the play to be. In some cases we think that they have used completion designs that are not as a sophisticated as what design we are using. And we’ve talked a little bit in the press release about the proprietary completion design. So, to our view point there is nothing this surprised us with our test which have been very successful or some of these others that had mixed results and in just affirms, we have the best position in the play and that we understand what is going on, on here. So, that’s kind of an overall view. And would also say it that it is very early on in the play and I suspect and we don’t know for sure, but I suspect in some of these cases these companies maybe testing the limits of certain things. And they learn from these and as they go into full-field development it will be better results. And so I would be very careful about extrapolating the results from any early experimentation that maybe taking on in the play, say this is the way it’s going to work on the full-field. But I suspect they knew what they are doing, we don’t know exactly all the reasons. We suspect they knew what they are doing and they are just testing a limits of certain things to see if it would work or not. But, again it’s no surprise to us at all in any of the results we have seen.

Great. Thank you.

Your next question comes from David Tameron with Wells Fargo. Please go ahead.

Thanks. Good morning. I’m just going to reference the slide, I think it’s 15 in your deck, just the route area. Can you just give me an update of kind of Seawolf, it looks like this development pattern changed from maybe what you had been thinking. Can you just give us the latest and greatest thinking as far as that relates to or I guess the focus on this area and realizing every areas is different. But, can you just update us on that as far as the development patterns and how many wells per section, et cetera.

Dave, this is Scott. And absolutely that a systematic change slightly. I think we added one or two more wells from last year and we got a little bit more specific with regards to the landing zone. I think this time around we include the X, Y because that’s a common nomenclature in that area. And obviously we’re doing an appraisal well and lower Wolfcamp bay as well, but maybe Tony could speak to just what we’re trying to accomplish at that particular pilot, which we call the Seawolf pilot.

David, as Scott mentioned the well that we’ve reported on here in the lower portion of the upper Wolfcamp A, was just below the highlighted Rattlesnake area there. It gives us a little bit of upside thought process on the lower portion of the Wolfcamp, but if you go back to the last quarterly call, where we’ve reported the results of the Fighting Okra well. It’s just immediately south of the spot on the map that says the word Seawolf. And so there you saw the outstanding results that had there in upper portion of the upper Wolfcamp and this Seawolf is really going to be our first what we call our first multi zone development in Rattlesnake and we have got a substantial amount of locations that we have highlighted in our resource play. Starting right here with this will spread the 12 world program and the Wolfcamp and as we work that of we will just move those three rigs from that location start moving to the East and probably delineate that Rattlesnake area. So what we don’t show on this is a lot of industry activity that’s been around this and there is been some boomer wells there. We feel like this particular portion of not only of our play that this particular portion of the Delaware Basin is perhaps the best column in all of North America, so we are expecting a very robust long-term development just in this Rattlesnake area.

Okay and just noticed the B maybe versus the prior to the Wolfcamp B is no longer part of that plank, you talk a little bit about I know others have done the same, can you just talk about your thinking there?

There is not been a lot of data points that have come through in the lower portion of the Wolfcamp A or the B, there has been some other nomenclatures, Wolfcamp 300 and 400, there has been some data points out there few and far between, some of those have been in fact a bit disappointing. So we know there is a very rich hydrocarbon column here, lot of oil in place, we think it will come with time, but we also think we can maximize our present value by focusing on the upper portion of the Wolfcamp. And we know that we can come back and drill back through that zone and get to the lower portion of the Wolfcamp which we frankly right now we are not prioritizing in our development because we just have not de-risked it, we don’t see the activity from industry really shown us the results either.

Okay, thanks for that color. And then Dave can I just ask one about [indiscernible] sell the Barnett or a portion of the Barnet and I can imagine what your answer is going to be, but because we have talked it about in the past, but I’m just thinking about in terms of returns and generating cash flow you know historically it has generated lot of free cash flow, it doesn’t’ look like you are going need that over the next couple of quarters or a couple of spending gap or can you just talk about your decision there?

Well you are right, we don’t needed for the shorter term. What I tried to do paint in my prepared remarks at the beginning of the conference call here is where we see directionally we are going and by 2020 and that is as we are moving into full-field development in the STACK and the Delaware that we will become a more streamlined company eventually and we see in the billions of dollars of asset sales that we may accomplish over that timeframe and in a very measured way as we balance our cash inflows and our cash outflows. Certainly there are several different areas that we can consider and I’m not going to go into detail on any decision over regarding any specific area or assets that we have that we may consider from monetization. But in general, I mentioned that we would certainly most likely be divesting several billion dollars of assets, we see using some of that to further development activity in the STACK in the Delaware Basin and also repaying debt with a portion of those proceeds to build an extremely strong balance sheet with a net debt-to-EBITDA on the order of 1 to 1.5. So, we think that financial strength is going to certainly position us with a great deal of strength in any commodity price environment. We think that’s really the key for a top performing E&P company to have, we have franchise assets, we’re executing very well on those assets and we will further streamline the portfolio and we will have one of the best balance sheets and not the best balance sheet in the industry when we are finished with his total transformation. And so certainly the Barnett or some other assets configure into that equation, again we’re making no decision on that today and certainly no announcement on that today. But we certainly have a lot of flexibility about how we go about accomplishing this strategic objective, but that’s where we’re going.

Okay. Thanks, I appreciate it.

Your next question comes from Charles Meade with Johnson Rice. Please go ahead.

Good morning, Dave and to rest of the team there. I would like to ask two questions on the Delaware Basin. First on the Seawolf development. Can you talk about what if any lessons you are able to bring from your multi zone high intensity development plans over in the STACK to the Delaware Basin in to that development or is it more of just a blank slate and there is not a lot of portability of lesson from one to the other?

Hi, Charles. Thanks for the question, we do find the ability to transfer learning between our Delaware and STACK teams, in fact we’ve been on this multi zone design for about two years now and that’s a really thoughtful work that has going on with our technical teams in both areas. I meet with each other, so transfer learnings quite easily here, we’re all centralized in this building so makes it real advantageous from that perspective. One of the things I think unique about the Delaware is really the federal permitting aspects is a little bit more complicated than it is in STACK and I think in the last conference call we talked about receiving our first master development plan which was played as a 162 well permit that we received in [indiscernible] and we feel like we’re very close to having three more of those master development plans approved by the BLM which will set us for about 600 to 750 potential locations left. And the benefits we see from this multi zone development concept is just much more efficient not only permitting exercise that we are going through as I just described but really we layout the integrated surface facility concept for each of these areas. And in that we’re able to use the centralize production facility not just by one pad or two pads, but in our planning there, when we start looking at the chart and laying out all of these different projects we continue to use these surface facilities for a given area. So for instance in Seawolf while that will be the first 12 well project we will drive. We will continue to run additional projects producing through that centralize production facility for some time to come. So, we will maximize the rate capacity in that facility for a while. We also feel like there is tremendous ability to increase the efficiency of our operations and just to give you order of magnitude on that, when we put in a park of that three rigs in a half section or quarter section type area and don’t have to really move those rigs from location-to-location, we will not got about three days of rig time out of the what is normally about a spud to TD time of about 10 bay. So the more we keep our operations centralize there, we can continue to think of things in terms of batch operations, so we will use had the flexibility use spudder rigs to get to surface pull drill and then come back behind with our conventional rigs for the production stream, we will also be able to do simultaneous operations and it will actually have some frack operations ongoing in some of these projects while we drill and produce. So tremendous amount of present value uplift by thinking a little bit differently than industry has taught up in the past, and we’re incorporating the same concept throughout the Delaware and the STAC development shows.

Charles, the only think I would add. I think you had a really strong list a bunch of stock there that one thing is we probably have as much experience as anybody out there in the industry what we would call the parent child relationship in any given area. In other words the relationship between the first well section and what the ultimate down spacing might be and what kind of completion designs optimize recovery given that. And so that’s something that we have obviously studied from Eagle Ford to the STACK and the Delaware and we feel we have a really good understand, you have to actually drill the wells in many cases to know absolute results, but we have a pretty good understanding of I would say what is going to optimize the overall recovery for the highest returns around that and that comes from experience and drilling in a number of different areas and transferring those earnings from one place to another.

Right, that’s great color guys, and you guys are pushing the envelope within the industry on that kind of concentrate development. And that actually leads to my second question, you guys have highlighted the Seawolf development, but I couldn’t have noticed that just in north you have got this [indiscernible] development that just maybe a little bit behind those schedule with actually more wells and so maybe can you give us little more color on what the plan is there?

Charles we have laid out, I think what we show here to be really these projects that will be initiated through the later part of 2017 and into the early part of 2018, so we have got a gain chart that actually goes beyond that with additional projects there, but as you the focus for what we call the distilled areas really largely going to be the Leonard and little bit of bonds claim type work and some Wolfcamp work there. So it’s just another - the project that we have talked about in the last operating report and the one that we mentioned in this the Anaconda is really a three interval test on the Leonard that we are completing those wells and starting to bring those online. We will have operating results of those in Q3 but at this point we’re looking at those as very favorable results, so I did say it’s just really just a continuation of the development of that column.

Got it. Thanks guys.

Your next question comes from Arun Jayaram with JPMorgan Chase. Please go ahead.

Yes. Dave, I wanted to see if you can elaborate a more on your thoughts on this longer-term vision perhaps this leaner and meaner Devon with the focus on the STACK and Delaware Basin. I’m just trying to get a sense of how we should think about how other assets fit into the Devon portfolio as you are thinking about maybe deleveraging through assets sales and particular at Canada?

Well, thanks Arun. We obviously have a number of strong assets throughout our portfolio. It appears that those will have the greatest development opportunity are going to be the STACK and Delaware Basin. And then to probably a lesser degree and the anticipated price environment and again we’re basing - we’re a thrive in a $45 to $50 well and we’re not counting on higher prices. So, we are building a company here is kind of succeed and be one of the top companies in the current price environment. And in that world it looks like STACK and Delaware are probably going to lead the way as far as development opportunities on the number of other areas we will have some developments such as Rockies and others are going to be providing more cash flow to the company. So, we’re on the cusp of really moving into full-field development in the STACK and the Delaware plays and when we do these plays are going to be out absorbed and generate very strong returns. And again, I want to emphasize again, we are a returns oriented organization, we’re not just growing for growth sake, but we think we can generate very strong returns in those plays in this price environment. If there is any question about the quality of the wells that we’re drilling again I would refer people back to page six of the operations report where we show we have the highest 90 day IP in the industry. So, we can talk 24 hours, you can talk 30 days all that, but when it comes to 90 day, we’re the leader. And we can generate very strong returns from that. So, as we do, we do see that some of these other areas could potential provide divestiture opportunities that would allow us to further our development in the STACK and Delaware Basin. And I’m not going to go as far as saying what specific it was, because that’s going to or continue to looking at that and we will continue to look. It will be a measure a very thoughtful process, we will be balancing our cash inflows and cash outflows as said and we’re going to use sum for debt repayment to build this fortress balance sheet. So, beyond now there at this point no further discussion, but obviously we’re going to look at all the key criteria when making that call, but it’s a great position to be in where we have a very strong asset base, we’re executing now IPO very well on that asset base. And we are going to continue to increase the focus of the company.

Okay. That’s great. And just my follow up Dave, in a $45 to $50 world we had been thinking about Devon based on your previous kind of commentary of kind of balancing your internally generated cash flow plus the in-link distributions with your CapEx. Given how you maybe embarking on this asset sale program beyond the 20% sale in the Barnett. Is there a comfort perhaps to spend above that amount with asset sales kind of plugging the delta there.

In essence yes, is the quick answer to that. Now again we are driven by returns first and we are we only do it if we feel we can generate good returns with the capital that we are deploying. We are confident in that price environment that we can generate good returns in the STACK and Delaware Basin plays. And so depending on these circumstances we would certainly be open to using a portion of divestment proceeds to further development of those plays and then a portion of that to pay down debt to build this strong balance sheet as well.

Great. Thank you very much.

[Operator instructions]. Your next question comes from David Heikkinen with Heikkinen Energy Advisor.

Good morning guys, thanks for taking my question. Just a quick question Jackfish one, do you expect similar skim tank issues and inspections ongoing and potential downtime?

David could, we solve a little bit of evidence of the bracket issue in J3 skim tank, we had no detection this time at J1, you also have to remember we have already been in this skim tank at J1 in the previous turnaround. So, we’re really not expecting it to be initially, but we will certainly made the same type of proactive repair work that we did in J2 and J3 while we are in the tank.

Okay and then just on the Hobson Row you highlighted that in your 2Q ops report can you talk to all about what the current production is and how it actually contributed to the volume I’m just trying to get an idea of those 39 wells are actually producing?

Obviously the Hobson Row the key driver behind our growth in STACK this year, we have revamped STACK production by that 20% and that’s largely driven by just the success of the Hobson Row and what we are seeing there and maybe I handed it over to Tony where he can talk about just what we are seeing from the type curves and more importantly how we are going to deploy that success to the Jacobs Row. Tony.

Dave I don’t have a whole lot to add to that. We reported a little bit of the results on the last operating report, the work that we have done so far in this particular quarter has been type curve type results, so we didn’t really highlighted individually, but I will tell you we pumped near 500 million pounds of sand in that work and from an execution perspective the team did outstanding results. And there is a great partnership between the operating guys and the supply chain guys that we have there, I think Dave mentioned earlier, this is the first area that we decoupled great success there and we think we dropped about 15% of the cost of those that work out of this system just through that operating efficiencies there. We are very excited about extending the work from the is a normal lateral work that we have historically done and to the long laterals, we got the all the wells completed now, they are all starting to flow back, we will be able to report on those results in the next quarter, but again when we start looking towards the future in this and understanding what the value of the long lateral will bring we think the returns through this development are as competitive as much of what we have in the portfolio.

And just on that cost savings. How do you think that will flow through to your future development cost reported in your reserve reports. Should we expect a down or trend and Devon future development cost as you kind of lock in this decoupling of services and just trend deposit?

Well I think that certainly is a positive driver towards, yeah towards lower F&D now. Obviously as you pursue more oil oriented plays as you well know David those tend to be a little bit F&D type plays in general. But that element would help mitigate to absolutely.

Yes. One other thing to add on that Dave, real quick is just ultimately as you start heading towards those multi zone developments for the majority of our capital is going to be concentrated going forward and that’s going to be another tailwind as well. So very concentrated capital programs combined at the supply chain, we would expect to show very well in this metric in the upcoming year.

Thanks guys.

Well, I guess it looks like there is no one else in the queue. So, we will wrap up the call today. We appreciate everyone’s interest in Devon. And do you have any other questions feel free to call the IR team anytime and that consisting myself Chris Carr. Have a good day.

Thank you. This concludes today’s conference call. You may now disconnect.