Devon Energy Corporation (DVN) Q1 2017 Earnings Report, Transcript and Summary

Welcome to the Devon Energy First Quarter 2017 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. [Operator Instructions] 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's had the chance to review our first quarter financial and operational disclosures that were released last night. This date 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. As you can see from our first quarter results, Devon's three-fold strategy of operating in North America's best resource plays, delivering superior execution, and maintaining a high degree of financial strength is working exceptionally well, and generating top tier results. Our production in the quarter exceeded guidance expectations by a wide margin. Our margins and profitability continue to expand as we transition to a higher margin product mix, and capital programs continue to achieve efficiency gains as we shift our focus toward full-field development in the STACK and Delaware Basin. On the call today, I will focus my comments on three key messages. First, we remain very well positioned to accelerate investment across our world-class U.S. resource plays, and deliver on our 2017 and 2018 growth targets. By the end of this month, we will have 15 operated rigs running in the U.S., focused primarily within our top two franchise assets to STACK and Delaware Basin. As we progress through 2017, we are on pace to steadily ramp up drilling activity to as many as 20 rigs by year-end, resulting in a $2 billion to $2.3 billion upstream capital program for the year. Importantly, providing additional certainty to our accelerated investment plans, our attractive hedge position, excellent liquidity position, and innovative supply chain efforts. With our disciplined hedging strategy we have stabilized our cash flow stream by locking in more than 50% of Devon's estimated oil and gas production for the year at or above market levels. We are also systematically accumulating additional hedges for 2018, and expect to protect the price on at least half of our production in 2018. Coupled with our investment-grade rating, and $2.1 billion of cash on hand, we have the financially capacity to execute on our business plan. On the supply chain front, given the heightened competition for services and supplies in our core basins, we are taking aggressive steps to ensure that we have the resources and capabilities to achieve our growth plans. With this proactive work we have successfully secured equipment, crews, materials, and take-away capacity at competitive prices, and at the bottom of the cycle. Additionally, to achieve the best results for LOE and capital dollars we are mitigating inflation by decoupling historically bundled high-margin services, and are utilized in a much more diversified vendor universe base. Also adding to our savings are the continued efficiency gains we're achieving across our early stage development plays, where the majority of our capital is invested. As we shift to full-field development in the STACK and Delaware Basin these efficiency gains will only ratchet higher. As a result of these strategies, strategic supply chain initiatives, and operational efficiencies, we have completely offset inflationary pressure through the first part of the year. Overall, when you combine our financial strengths, and our innovative supply chain initiatives with the prospects of our top tier STACK and Delaware Basin assets, we are highly confident in our ability to deliver the value and returns associated with our growth plans over the next few years. The second key takeaway is that we are building momentum across our U.S. resource plays as we head to full-field development. As we have talked about at length over the past several months, we expect 2017 to be a breakout year for our Delaware Basin asset as we concentrate our activity in the economic core of the basin within southeast New Mexico. In fact, the initial well result from our development program in the first quarter, were truly fantastic. Our first operated Wolfcamp well in the Rattlesnake area achieved the highest production rate of any well Devon has brought online in the Delaware Basin to-date. With 30 day rates reaching 3,000 BOE per day, we also tied in three high rate Bone Spring developable wells during the quarter with production rates that exceeded our type curve expectations by 30%. In addition to our high rate well activity for the quarter, our shift to full field development in the Delaware Basin is now underway, we just completed drilling our first multi-zone development targeting three Leonard shale intervals and we have as many as four more multi-zone projects lined up to begin in the Delaware over the coming year. This development approach is expected as several advantages that will drive higher returns compared to traditional pad development work including improving rig and frac crew mobilization times, leveraging surface facilities across multiple drilling units, increasing per section recovery potential with improved planning, maximizing net present value as flexibility to add or defer development zones and more efficient permitting process on federal lands. Additionally to maintain similar cycle times to traditional pad drilling, we plan to deploy concentrated development and completion activity across these larger developments. To position ourselves to accelerated activity across the Delaware Basin in 2018 and beyond, we have recently submitted four Master development plans to the Bureau of Land Management designed to accommodate up to 600 permits, in fact we just received notification of approval for a first master development plan at the Cotton Draw and expect the other three plants to be approved by year-end. This innovative permitting strategy will allow us to accelerate our multi-zone development activity, maximizing returns and per section recoveries from our world class acreage. In the Oklahoma stack play, our capital activity also delivered outstanding well productivity, with the Woodford development program, we have now brought online the majority of the 39 well Hobson Row which results from this high impact road tracking at or above our EUR type curve of 1.6 million BOE per well. Hobson Row is one of the key drivers of our STACK growth plans in 2017 and gross production remains on pace to exceed 40,000 BOE per day by the end of the second quarter. We're also excited about our next Woodford development, the Jacobs Row, we were deployed to learning attained from the Hobson Row and leverage larger completion designs across extended reach laterals, which we expect will boost returns associated with the Jacobs project to among the best in our portfolio. To the north and the over pressured oil window of the STACK our appraisal work during the quarter confirmed the potential for up to four landing zones in the core of the play. This appraisal activity will help further refine our initial multi-zone stack development, the Showboat project which is satisfied in the third quarter. While still preliminary, our plans call for drilling 25 to 30 wells across two drilling units at Showboat, co-developing both the Meramec and Woodford formations. With additional appraisals of success in the core play, we could increase spacing to more than 20 wells per drilling unit with future development projects. To provide perspective on the scale of our stack opportunity, we have identified approximately 400 drilling units that are candidates for multi-zone development work providing us with a highly visible growth platform. Looking beyond the Delaware and STACK, we also had impressive results within our Eagle Ford and Rockies assets. The initial flow back results from our nine Well Diamond spacing test in the Eagle Ford were very strong where 30 day rates averaging 2,100 BOE per day, with this pilot we have confirmed the Upper Eagle Ford as a commercially viable landing zone adding to our multi-year inventory in the field. Our initial Rockies drilling work also delivered impressive results. Our first four Parkman wells crushed type curve expectations by averaging more than 1800 BOE per day of which 95% was light oil. Making the Rocky story sizzle even more for the quarter, are the results from recent state and federal lease options, winning bids that offset our southern acreage position recently $17,000 per acre. As a reminder, we opportunistically secured our leasehold position in this area for about $1,000 an acre in late 2015. And my last key message is that Devon absolutely possesses the low risk development inventory due to deliver sustainable long-term growth. Between the STACK and Delaware Basin alone which are two of the very best positions, position poise on a North American cost curve, we have exposure to more than 30,000 potential drilling locations. These world class assets provide Devon with a highly visible multi-decade growth platform. And as you saw in our press release last night, given the massive growth opportunity associated with our STACK and Delaware Basin assets, we simply have an abundance of opportunities within our portfolio. This high quality dilemma has resulted in our initial step to bring value forward with a $1 billion non-core asset divestiture program over the next 12 to 18 months. The non-core assets identified for monetization includes select portions of the Barnett Shale focus primarily around Johnson County and other properties located principally within the U.S. Looking beyond today's announcement, I also want to be clear that our risk resource base in the U.S. has the potential to a further expand with ongoing appraisal work in STACK and Delaware Basin. With successful delineation results, we would evaluate strategic options for additional non-core asset sales in the future. The bottom line is the divestiture program combined with our excellent liquidity and strong hedge position supports our capital program and places us firmly on track to achieve our multi-year growth targets. Additionally, the certainty associated with our capital programs uniquely positions Devon attain strong operational momentum through the end of the decade. So in summary, I believe Devon clearly offers investors a differentiated opportunity in the E&P space. We have a great collection of assets, we will continue to get the most out of these world-class assets with superior execution and we have one of the more advantageous capital structures in the E&P space. As we continue to execute on our disciplined business plan, we are well positioned to generate outsized returns for our shareholders for many years to come. Now I will turn the call back over to Scott.

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 if time permits. With that, operator we'll take our first question.

[Operator Instructions] Our first question comes from the line of Arun Jayaram with JPMorgan Chase. Please go ahead.

Yes good morning, I was wondering Dave if you could maybe give us some more details on the multi-zone development, you mentioned that you had submitted kind of four master development plans, I was wondering maybe you could give us some details on what one of these development plans could look like at Cotton Draw in terms of the different zones between the Bone Spring Wolfcamp, Avalon et cetera?

Arun, I'm going to take the first part of this, Arun, and good morning and I'm going to turn it over to Tony talk about the specific zones that we've been developing but talking a little bit about the Master development plan and that's really something that we are one of the first companies to do in the Delaware Basin and basically it takes a lot of the risk out of the permitting. As you know, we're developing this on federal acreage and historically has been difficult on a well by well basis to get an inventory far enough ahead of your drilling program to have the confidence that you can you can execute on a drilling program, with this master development program that essentially gives us a permit for a large area you see submitted four across and it's going to give us 600 and average about 150 per master development plan, we have the first one in already and so with that then all you have to do is get the individual ADPs which are a much, much shorter process and are really not on the critical path at all. So this is a great concept that we've been working with the BLM on, we appreciate their cooperation on this and it's really a huge step forward for allowing us to go to a much higher rig count and you've seen in our operations report we said we're making plans not initially but up to 20 rigs out there and this is a big part of that. So Tony, you want to talk specifically about Cotton Draw a little bit?

You know, Arun, appreciate your question, this is some planning works that we've been incorporating into the halls [ph] of Devon for about the last two years. And again as Dave mentioned, we appreciate the partnership that we have the BLM. It's really worked out to our advantage. And so if you look at the concept that we're describing in these multi-stacked horizons here, we're starting off with some fairly small sized, small-scaled, multi-stacked, multi-well pads. And so as we just commented on, we just finished a drilling of our Thistle Area 10 well pad. We will have a 20 well pad in the Delaware Basin by year-end. We'll gradually transition from fairly small pads in 2017 and early '18. And by 2018 and beyond, we'll be a little bit larger in scale. But the benefit for something like Cotton Draw which has actually got prospectivity for 17 that will include the Bone Springs, Delaware, Leonard, and Wolfcamp. We will be prosecuting all those areas there. This one design allows us to have a larger sized pads not in surface areas much as in well count. And it will have a centralized production facility that each of the pads will be able to flow in to. This starts optimizing the surface facility; starts optimizing really the manufacturing process that we have. We will be able to have simultaneous operations as we go through the work. So provides a lot of the inherent efficiencies and our plan with a deep inventory that we have talked about in the Delaware Basin, we just knew there had to be a better solution than just a historic 2 to 3 wells per pad environment.

And I might add I outlined in prepared remarks some of benefits of these type of well, but I know one of the push backs we've had is people are concerned, oh, my gosh, is this going to look a major offshore development in terms of timing with going this direction. Two comments on that, first is as Tony said, we're starting out small. So you are not going to see a large [indiscernible] 10, 15, 20 type of well sized pad initially. And the second point is in each of these pads, we are going to have multiple rigs working [ph]. And so, bottom line is you are not going to see a significant timing shift as we go from two to four wells per pad to a larger because of how we are going to concentrate our rigs on there to get it -- to keep the timing the same. So that concern is -- we have obviously been thinking about that, and we believe we have been working on that for a long time.

Great. Thanks. And my follow-up, I wanted to talk a little bit about the four extended reach wells that you're doing at the Hobson Row and what are your thoughts around the Jacob's Row? I think you talked about a 70 well development with Cimrax, I assume that's the standard lateral NSPs, four extended reach lateral wells do okay at Hobson, how could that influence your development plans for the Jacob's Row?

Arun, we are really through all of the -- on the Jacob's Row -- on the Hobson Row excuse me, we are all the way through the completion of our normal lateral wells, and as you can see in the report, seeing very encouraging results. We've upsized the frac designs. And we decoupled our operations there. I will talk a little bit more about it as we go through call. I hope that great efficiency of operations. Execution phase is going really well. We're just now getting to long laterals that we described in the plan for the Hobson Row. We're fully expecting that long lateral is going to be the design of the future. And that will be what we incorporate into the Jacob's Row. What I'll also comment on about we have 50:50 partnership with Cimrax there as you mentioned. We are continuing to work with their technical teams on what the -- what the forward plan is for capital allocation, both in Devon and in Cimrax. Right now, we're expecting to prosecute our three well section at the -- in Q4 of this year, we are expecting Cimrax to be close that same timeframe, but for right now, we're fully anticipating long lateral designs as we forward, and -- but we are fully focused on starting our three well program in middle of Q4…

And just to clarify is the Jacob's Row going to 70 long laterals or single laterals? I wasn't quite sure.

It's going to be -- Arun, it's going to long lateral. Every time we can drill long lateral, we are going to drill long lateral. So I think if you've looked at lay out on the map that we highlighted here, they are all going to exposed to long lateral drilling.

Okay. Thanks a lot.

Arun, this is Scott. Hey, as you know, just a standard length lateral you are looking at 1.6 million equivalent on recovery basis. Right? So when you extend these laterals out with the Jacob's the returns ratchet significantly higher raveling what you are seeing in the over-pressured oil window in the Meramac. So, it'll be a great project for us and we are pretty excited about our spurting activity which will occur in Q4.

Thanks, Scott.

Your next question comes from the line of Doug Leggate with Bank of America Merrill Lynch. Please go ahead.

Thanks. Excuse me. Good morning everybody. Excuse me. So, I wonder if I could start off with a question on inventory, Dave. And I guess it relates also to your billion dollar proposed asset sale. There are multiple pieces to this question, I guess, but just looking at all the data you've given today. You talked about going to 20 rigs. And at Delaware, you talked about 2000 unrisked locations. But yet your inventory in the Wolfcamp is only 500. So when do you basically get a little bit more disclosure, or, what do you need to see to step up the inventory in both the Delaware but also in the [indiscernible] landing zones now that seem to be working in the quarter the STACK. It seems your inventory is substantially understated. And my question is what that means for your -- timing of your non-core disposals as your inventory extends? If I may, I have got a quick follow-up to that, I will be glad. Thank you.

Great. Well, I think you are hitting it exactly right, Doug. We see significant upside to our risked inventory. We obviously had a great well there with the Fighting Okra, and there has been some great offset wells to that. We are going to have a significant portion of our appraisal dollars in the Delaware Basin going to additional Wolfcamp wells here in the second half of the year. We are also going to be doing a lot more appraisal work up in the STACK. We take the approach so we want to see the actually results before we really put it into the risked inventory. But we have every confidence based on our well results and other competitor well results that this is going to continue to increase. And we've looked as I said in our prepared remarks we look at this divestiture program as a first step. We think it's an appropriate first step because obviously commodity price has also has softened somewhat in the past few months. We are confident that we have a program already that we are planning on in 2018 that's well beyond the 20 rigs that we will in 2017. And we even talked in the last operations report, we didn't put in this one but a 60 and 3.25 $6 WTI, 3.25 Henry Hub, we will be generating about $3.5 billion of cash flow - upstream cash flow. So prices have fallen off a little bit from that. But with this, divestment program and that certainly gives us increased certainty that we can deliver on the growth results even if commodity price has soften because these wells are still generating incredible rates of return even at somewhat lower prices. So want to execute it. Our operations teams are fully prepared to execute on that. And this gives us additional confidence that we will have the cash to generate that. Now as we further upraise these areas such as the Wolfcamp and additional landing zones in the STACK, we will consider additional divestments as appropriate if they are appropriate. And so, I would just look at this as certainly a single for how we are going in the future as we think this is the appropriate first step. But as we finish our appraisal program, there could be further steps. We continue with our appraisal program, there could be further steps.

So just to be clear, Dave, so, you are basically saying Devon lives within cash flows including asset sales?

Essentially at this point, that's right, yes.

Okay. My follow-up is really on the relative economics across the different place. Obviously you've got a ton of things that are emerging that are competitive and what sits at the back of my mind is the rocky statement you made in the presentation. In order to provide a per acre value one would argue that you are trying to get the market to focus on the value of your acreage, but of course that only gets realized if you monetize it, and any reasonable timeline? I guess you can say the same thing about [indiscernible] recent sale of their oil sand. Again they got a big valuation for that, It's probably not getting recognized in your stock. So when you look to build the growth in inventory that you are clearly having in these areas, how did this relative areas within your business compete for capital? In other words, where would your incremental first look be to monetize, would it be Delaware slope, would it be the rest of the Barnett, would it be part of the Rockies, would it be oil sand, just how do you think about, how you prioritize non-core asset sales?

Well, first off, I would say. We are not just trying to highlight it. We also get all the necessary I guess build in when you sell it. I think we can have that discussion over a beer someday I guess. But I don't think up sell all of our assets to get value recognized for it but what we are trying to say is that other people starting to recognize the value that we have and we think that should start showing up in our stock price. The most important thing I can say is we are conscious strategy here and Devon has been to not only be in some of the best place in onshore north America, but to have the best positions and the best place in onshore north America. These are big place and they always in these place are as good spots to be and not so good spots to be and we are focused on being in the best and so I think when you look at our well level economics we will stand them up against anybody in the industry because we are in the heart of the best place onshore north America. Tony, do you want to add any comments from a relative viewpoint on the economics, but I am telling you they are all pretty outstanding.

I think one thing Doug that we are proud about is we picked up our position. We expanded our position in the powder at a time when the industry really didn't understand the potential value there and now the industry has recognized that but if you look at the returns that we had before commodity prices cycled off, returns that we had in the powder where every bit is good, if not at the top end of our results in late Q4 or 14 and again if you look at the six wells or four wells that we talked about for this particular quarter. Again, there is a top end of our portfolio, so it's an equivalent capability to the Delaware, the best of the Delaware and the best of STACK, it just doesn't have the same skill to us as the other. So as commodity prices rise and additional cash flow is generated, it's going to be a great opportunity for us.

I appreciate the answers, guys. Thank you.

Thank you, Doug.

Your next question comes from the line of Philip Jungwirth with BMO. Please go ahead.

Thanks, good morning. Question on the Barnett of the 400 to 500 million of cash flow expected in '17 just trying to understand the high level, does this include the -- in these de-payments and how should we think about any upside to Barnett cash flow de-contract, who are closer to the market rates.

Well, I can certainly handle the first part of that with regards to the cash flow that we put up and that's net of all of our transportation and processing cost. So absolutely and I guess so could you repeat the second part of that question. I'm not sure I heard that clearly.

Just trying to understand how much upside there could be to that cash flow number if the AT&T contract within link we are in your vehicle sort of market rate?

At that point you know, Philip that's undisclosed there is confidentiality regarding that. So that's not a number that we are going to be able to provide for you today. But I think the key takeaway is that these are very valuable assets that are generating free cash flow. So this isn't like other comps that occurred previously in prior years. This will be an asset that will be sort after and we expect to have good market as we look to market the asset.

Okay, great. And then, there has been a fair amount of or say the activity up towards northwest Dewey and Woodford County and we didn't had that's one filing, one empty position up there, I was just hoping that you help frame Devon's position in this area and is there anything to discuss in terms of well reserves, thoughts on the player or future activity plan?

Philip, I think we've described that we have about 80,000 acres as what we call the northwest tag extension. We've acquired that position, just through a lot of organic leasing and picked up a few real small pieces. We have some well active in area we are really not ready to disclose that but we are encouraged and excited about the opportunities going forward and so I think at this point as well that's where we are leaving.

Great. Thanks, guys.

Your next question comes from the line of Ed Westlake with Credit Suisse. Please go ahead.

Yes, good morning and it really feels like you are making progress de-risking this multi-zone perhaps in the Delaware. I mean each of the individual wells you give us later on. As you go to sort of a sectional development, are you ready at this stage to kind of like give us some kind of overall sectional tight curve and well cost or is it still too early?

Probably the challenge to do that and good morning it is that. It really depends a lot on where you are and even in some cases you will find that some zones have already been developed and we will developing other zones as well. So there is, it's a fairly complex thing to try to give you a perception. In some cases there are. As Tony said we have Bone Springs, we have Leonard we have Wolfcamp, we have Delaware all of those in other areas such as our initial development and this we are just developing three zones in the Leonard and there is every other variety as well, but I guess the key is they are all working incredibly well, but it would be a very, it's not really possible just as to give a tight curve per section. I don't think because as a variety.

Okay, I think you know, when I think of the inventory and the value of the inventory. I'm trying to think of reasons why that the shares aren't reflecting in that and that sort of uncertainty maybe one of them although we can see obviously it's very good well results?

Well, I see we said we have just a -- such a deep on risked inventory and we are going through an appraisal program and we will certainly layout even. Bottom-line is everything is working and it's working extremely economically right now and so as we continue this appraisal throughout '17 and even in the future years, you are going to see this inventory expand, we are confident to that. We just want to get the results before we give all the details.

The other comments in the up support around operational efficiency we are very interesting you talked about unbundling obviously the inflation starting to appear in certain lines but maybe if you can talk a little bit about how any examples you can share of how the unbundling of say problems or pressure pumping or other lines is leading to savings relative to say you know, a year ago or Q-over-Q however you want to describe it?

Ed, we are seeing attention and cost escalation across the business. We've been very pleased. I think we commented in the past. So we are going to be able to mitigate about 75% of that cost escalation throughout Q4 '16 to Q4 '17 with just some good planning and good operational efficiency. We are seeing that in fact if you look at our capital spend through Q1 we are a little it light and we feel like we are being able to mitigate any tension we have on the system. Guys are doing extraordinarily a good job right now with the planning, not with execution but the planning of the work that we do and so when you guys are looking for we are already working out into 2018 and 2019 planning or work there allows us to go to providers, give them certainty about the long-term plans that are able to make more definitive long-term decisions. That's helping us in a big way, so we like to have control over our destiny as a lot of companies do we find that when we have good plans in place, good partners and control over the project schedule we can excel there. So, we have actually contracted and secured our 2017 sand or all of our work in the mid-time and then also in the Delaware we have entered into a contract to secure the 100 mash [ph] sand for all of our STACK work for three years out. We find that the sand mines are pleased to be working with the end-user because we have definitive plans and also we are not at the mercy that some of the larger scale pressure pumping providers because we are getting plans from a lot of people that may not be as fine tuned and is well thought through as ours and so we would tend to get shuffled at times and so if I went back and looked at to look back on our work that we just completed on the Hobson Row, I think we've had a total of seven hours of delay not having sand on location rate of pump. Historically, we would have three times that amount on single jobs at times, when we were depending on turnkey type work. So we've got some outstanding work across the organization that is allowing us to have good relationships. You're starting to see the OCTG market inflate as well. And we've had some long-term relationships with three providers there that we stuck with them during the downturn; they're sticking with us in the up cycle, so we're able to mitigate cost on the pipe side of the business. And on the drilling rig side of the business you're starting to see the, I guess I'll call it the high-spec end market for rigs is starting to diminish. And a little bit more pressure there, but our relationships with a couple of primary providers there have helped us get through that. We're also taking the opportunity to contract longer term in some of these spaces. And while we've always had a fair amount of our rigs under term -- In fact, right now I think we have 11 out of our 15 rigs under some amount of term. But we're also now moving that into the frac space. And so, four out of six frac crews that we have working are on one-year term as well. So the guys are continuing to think forward. Our operating team and our supply chain group work extremely well together doing some good design work in-house. And so, we feel like we got places across the business that we essentially [technical difficulty] are gaining operational efficiencies that we didn't have two years ago.

Thank you for the first answer.

Your next question comes from the line of Scott Hanold with RBC. Please go ahead.

Yes, thanks. Just kind of curious as you look at the STACK play and discuss the opportunities to get three to four potential formations for obviously these pad developments that sound pretty exciting. When you step back, how are you going to delineate the test of how many places have that say third or lower Meramec available or the Woodford available, is that something that you've got a good sense of right now or is there still a lot of work to get there?

Scott, I think if you've watching the release on where our well activity has been, we've been really appraising around what we call appraisal areas one and two. In appraisal area one we'll have our first development that will start in Q3 of this year, we call that the Showboat development. In and around that particular area we feel confident that we understand the horizontal or the lateral spacing per zone very well. We're also getting fresh information on the vertical connectivity. And so we've got a lot of data on what we call the Meramec 200, and now we're seeing it on the 300 and the 400. That's being included, and that's what's described pictorially on one of the exhibits that we had in our operating report. So, in the specific area of the Showboat development we've got great pilot results in. It's giving us the confidence to incorporate parts of three different intervals in the Meramec. And as we continue with this development in Q3 we're also continuing appraisal work as we start moving to the western portion of the field. So if you look at the latter half of '17 and the early part of '18, we'll be moving rigs more westerly than they had been to date. We're also going to be learning from our results as we go here. And so the first development, for instance, that Tony described here, is in the Showboat area. Well, our next development will be most likely a little bit to the west of this, so that we then learn from the Showboat and any actual well results. And sometimes there may even be some questions, I think, on the operations report. One of the things, that we don't have as many wells on that diagram in the lower part of the Meramec. But it's because we think there is a question as to whether these are in vertical communication. And less wells is good; if you can get the hydrocarbons out with less wells, that's actually good. But we'll learn from the actual production from that to help us guide our future development, and when we move back into that area. So we have a very well thought out, very well planned approach to this so that we will be bottom line, optimizing the NPV overall or the capital efficiency that we're going to get from this program.

Okay. And I hope that this is not putting words in your mouth, but in part where you're looking to delineate first and move to is part of it, it sounds like maybe a sickness of the Meramec?

As you move to the west and to the south a bit, Scott, you are moving into a sicker portion of the Meramec in the, what we call, the 300 and 400 intervals. So you would see more oil in place in those middle-to-lower sections there. So you're right, it changes as you go from the eastern part of the field over to the west.

Okay, great. And as a follow-up question, the Barnett Shale potential sale, can you guys give us a sense of how much net production you'll have there? And maybe if you'd even extend that to that cash flow expectation or estimate that you all have put out there today or yesterday. What portion would be associated with that?

The planned divestments are about 20% of the leasehold production reserves and the cash flows, a simple way to think about that.

Okay, I understand. That's great. I appreciate it. Thank you.

Your next question comes from the line of Jeffrey Campbell with Tuohy Brothers. Please go ahead.

Good morning and congratulations on a very interesting quarter. First, going to the multi-zone concept, as you continue to evolve this concept I was wondering is overall pad oil cut versus overall BOE potential a consideration factor regarding which zones might be developed?

Well it is, Jeff. And I think Dave was trying to articulate the full matrix of considerations our technical teams are going through right now. And so if you look at the different intervals, some are completely de-risked and already in the development phase and some have very little data. As an example, the lower portion of the Wolfcamp, we have higher oil cuts in some than others. And some are just more prolific from a traditional rate perspective. And so there's a complicated matrix that the guys go through. I'd have to tell you that we'll be focused on generating maximum present value and returns from each of the multi-stacked developments that we go into. There is also an optimized size that we look at. And we think that we can get up towards savings, roughly, of about 20% in the DNC side of this up to a certain limit of wells before you start seeing that cost benefit degrade. And also, returns will be maximized at a certain point. And then with too large of a program will turn over, and also diminish. So, guys are looking at this on a project-by-project basis. And it's harder to describe that. But they'll be looking to maximize value and returns.

That was a helpful answer, I appreciate it. And then this is a little bit higher level one. Both the Barnett and the Delaware Basin are proximal to the Gulf Coast and growing that gas demand. Ultimately, can the legacy Barnett nat gas compete for capital with what might be viewed as associated nat gas in the Delaware Basin?

Well, the nat gas that we have seen, the drier gas opportunities in our portfolio for the most part are not competing for capital as well as our more oily-oriented areas that have associated natural gas. Now everybody likes to talk about these more oily-oriented areas. There is in most cases a fair amount of natural gas that comes along with those; it varies play-to-play. But there is a fair amount. But I think we have not focused much drilling in our portfolio on dry gas opportunities. And so that's one of the things that we obviously are thinking about here as we look at our divestment program. There are still opportunities that can generate returns well above the cost to capital. It's just our portfolio is so high quality they may not generate capital within our portfolio. So we think there's a great market out there, and there's an opportunity potentially to move value forward. We're just trying to make those type of decisions at the appropriate time. And I think you saw the first step of it with our announced divestment last night, and described earlier the rationale for the timing and the magnitude of that.

Right, understood. Thanks very much.

Your next question comes from the line of Ryan Todd with Deutsche Bank. Please go ahead.

Great, thanks. Maybe let's start out with one in the Delaware Basin. I know you have limited results in the Wolfcamp right now. But in the past, you had talked about lack of capital deployment in the Wolfcamp, the view that wouldn't compete on a return basis with the Bone Spring, and the Leonard, I mean. First well there look quite strong and I mean would you still at this point based on incremental data we've seen over time characterize -- how would you characterize returns competitiveness of the Wolfcamp versus the Bone Spring and the Leonard and could this have any impact and how you think about deployment of capital within the Delaware going forward?

Ryan, we're actually very positive view in the Wolfcamp going forward and we've seen some industry derisk the Wolfcamp around us and we've reported on the hiding of our well ourselves so we're highly encouraged with the opportunity in the Wolfcamp will compete for capital as well as our Bone Spring Delaware and Leonard going forward if you really step back about a year, year and a half ago we didn't have the infrastructure built in the southern portion of our play there so that was a learning experience we had to think you also saw about that time we had very high lease operating cost for BOE. All of that infrastructure we've caught up with our selves now, and so, we've got full water being pipe we've got power grid system across our position there in the Cotton Draw and in Rattlesnake area. So we'll have a much healthier commercial answer for Wolfcamp development going forward, and if you just look at the areas of focus for 2017 probably about 50% to 60% of our well activity will be focused in both Leonard and the Wolfcamp going forward. So we're encouraged by the quality of results that we're seeing in Wolfcamp.

I would more directly to answer your question I still think the highest returns are in the Bone Spring and the Leonard has come up. The Wolfcamp is certainly improving significantly and it has the largest upside to the inventory.

Okay. Thank you, that's helpful. And then maybe one follow-up on the multi-zone developments, you talked about some of the drilling and service level improvements and efficiency you might I wasn't sure if you just said there you could see 20% DLC improvement, but if you quantified what you think the efficiency improvements might be in multi-zone development relative to defend a single well that you've told in the past and then we talking about a 10% improvement in kind of capital efficiency 20% any ability to ballpark that.

Ryan, that was trying to describe a little bit earlier, but we have quantified that guys do a really good job of planning out these developments to maximize the efficiency of the developments. We think these multi stacked developments have the opportunity to reduce total CapEx cost by about 20% on a given section as compared to the historic two to three wells per pad and if you go through the long list of positive attributes that these new designs will yield, but we think it's a game changer for the large inventory that a company like Devon has.

And I'll just reiterate one more time I said it earlier too, but you're not going to see a significant timing differences, this is not like an offshore development Tony and I've worked a lot of offshore developments we know what offshore developments look like it. You're not going to see significant timing difference are compared to what you've seen historically which I think has been some of the concern.

Great, I appreciate the clarity.

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

Good afternoon, guys. Last to cover maybe a bigger picture question, you what level of well performance you guys factor in your full-year production guidance and is it, that based on your actual type curves or something higher and I'm asking the question could you just reported excellent well results across all three of your major basins and most significantly above those type curves that the full-year production guidance for means unchanged this is kind of contrast between the guide and the information the ops report.

Yes. Well, first off, the well results are outstanding as you said there's absolutely no hedging on that, but actually I understand that the current year well results proportionally to the total production is pretty down small and so there's a lot of other factors that go in to your production guidance beyond just the current year well results. So, and then, obviously I think everybody's figured out by now that, what is shifted between our outperformance here in Q1 and somewhat lower guidance in Q2 is just the fact that we moved, we're able to get some Eagle Ford completions accelerated into Q1 production and so the full-year guidance is unchanged it's just we got production on a little bit earlier and that's on those wells, but they do go on incredibly economic wells. But they are come on very high rates and have pretty steep declines, and we'll see some of that in Q2 in Eagle Ford. So there's just a lot of factors that go into the full-year production guidance were beyond the current -- beyond just the type curves that are -- that we publish, but obviously we are pleased that in several areas we are exceeding type curve expectations…

Make sense.

Yes, I will add in, one more Tony.

Yes, just I want to give a little kudos to the work our technical teams are doing on the completion side of the business is driving some of the sap performance and if you remember even I think it was probably several quarters ago that we showed that our 90-day IPs were number one out of 30 most active operators in the U.S. base and that was in 2015 and 2016 you looked the data, in 2015 by the way with the average of our per well performance was over 600 BOE per day. When we look at 2016 our average for new wells brought on is over 900 BOE per day. So we took -- what we thought was an outstanding performance and '15 continued to evolve doing some really sophisticated subsurface modeling, frac modeling and have increased our 90-day IPs another 50% in 2016. And you start looking at Q1 results in '17 it's a little higher than where we left off in '16, so the guys are continuing to put the pedal down and really outstanding results.

Understood.

And just a point of clarity real quick that those are for a 90-day rate and then also the gas piece of that production which is being adjusted on a 21 basis as well, so that would account for some of the reconciliation versus some of the 30-day rate you're seeing in our operations reports.

Great. So will look for that in the 2018 numbers, it sounds. And my second question is on the little bit fall from the asset sale programs to pick up on your opening comments and some of the Q&A discussion. The asset program appears to be its employees to grow as organic location count grows. How do you think about optimal inventory that defines how much is non-core so either in years of inventory region or return driven program and somewhat related to me is the vision to scale asset sales with the deliberate before the capital or more pace just with the down spacing results?

Yes. That's a great question and it has a really hard question to answer it's kind of like the old reserve production ratio, you're going to have too much and you can have too little and what is the right number and I can give you some directional thoughts on that. I don't know that there is an absolute right answer, but I tend to think of somewhere around a 20 year inventory at anticipate that will be very economic locations that anticipated prices. Is kind of a quick summary of before I would say I don't think it does a lot of good to have a 100-year inventory and I don't know if I sleep for a while if I had a five year inventory, though so somewhere around there I know that there exact right number I really can't say, but I think that probably get you somewhere in the ballpark.

Great. In the pacing concept, does it -- do you think the sales utilized can match ability to redeploy capital obviously neutralizing for many kind of commodity change or is it just going to run its course with results and location count?

Well. We see this billion dollar divestment program is just giving us additional certainty with and we would do it anyway, because it's the right thing, because it's a right given the depth of our inventory. We also see that same time that commodity prices have weakened somewhat and so this gives us greater certainty around the fact that we are going to have the cash flow to execute on a very high return program in 2018. Now as we see in 2019 we're going to continue to ramp up activity and we again as we finish more of this appraisal work more of it gets de-risk the 2018 and the end of the game for us we see continuing to ramp up and capital and activity as we move forward beyond that this just going to continue to accelerate our growth and future years. And we will, if the all the appraisal work, works out as we anticipate it well I think that we would be looking at additional divestments depending on commodity prices to how strong those are but we're probably looking at additional investments to focus our capital even more.

Great, I appreciate it guys.

Your next question comes from the line of Matt Portillo with TPH. Please go ahead.

Good morning, Dave, and team. Morning Just first question I wanted to follow up on comments around the upper Eagle Ford you made at the beginning with the successful commercial delineation just curious how that potentially impacts your view on inventory in the play and with the new diamond pattern that you're currently title piloting how much think about your core inventory over the next few years.

Matt, we're very pleased with the well results we saw with the acceleration of our ductwork into Q1. That data is being incorporated open to Devon and BHPs technical thoughts right now but the lower Eagle Ford staggered wells worked extremely well the Upper Eagle Ford wells that were incorporated in that plan worked very well. We're drilling Austin Chalk wells at this time so, I don't know the technical teams of come out with their plan I would just made somewhere between 500, and 1000 locations and going forward, the main thing to think about at this point is we've got two rigs operating right now on the plate and anticipate probably three in the second half of this year. Those will be utilized when the guys are have incorporated all these results into their thoughts.

And that really just another thought to that is that when you think about the Eagle Ford where well we do have some very high returning inventory in a multi-year basis that we can execute upon the transition of the Eagle Ford really is a free cash flow generator for our stack in Delaware Basin growth and I think that's how you need to perceive that asset with regard to the strategic fit in our portfolio of very high margin barrels, great results, but it's certainly we're going to harvest that cash flow and put it over the basin.

Great. And then as follow-up just in regards to the PRV highlighted some fantastic Parkman wells here in the rates of return on a, on a well level basis are competitive with the Delaware in the stack just curious from a milestone perspective what we should be watching for over the next year or two in term opportunities to scale the PRB further in regards to production and capital allocation?

Our plans right now we're bringing in a second rig pretty quick so, we're encouraged by what we have we're starting to prosecute some of the new lands that we picked up this past year in the southern portion of our property and again it's going to be cash flow available to allocate between Delaware stack in the Rockies will these kind of the, the question that we evaluate quarter-to-quarter but we've got inventory and permits are coming we've got to get another good relationship there with the BLM office that is progressing. And we feel pretty good about uncertainty of execution in the powder as well as we did in the stack in the, in the Delaware.

Great thank you very much.

And our final question for today comes from the line of John [indiscernible]. Please go ahead.

Yes, thank you. As you get these bigger drilling units, Dave -- Tony has discussed some of the efficiencies you're gaining the fact that vendors like long term visibility do you see a point where as these filling units are larger that you have such concentrated activity that you're willing to do multi-year deals or that the vendors would do multi-year deals and also would behoove you if they're not willing to do that to be perhaps more integrated?

Absolutely, John, and we have already done that on sand and we do see that is and I think Tony tried to allude to that that but that's one of the advantages that we see because this does provide certainty of activity and with us working directly with the sand mines for instance they like that because they really know then okay, we're dealing with counties is actually going to drill the well so, there is a much more certainty of demand in areas dealing with a service company who is relying on representations from a number of operators. And it's not a service company solve with a beta is not knowing it is detail whether those plans are going to be true or not where dealing directly with the Devon with a house standing reputation and following through on what we say we're going to do. We see that's an advantage and allows them to have confidence to enter into multiyear agreements with us.

Okay, good. With respect to the Eagle Ford I just heard you know about the harvest mode essentially put the Delaware in the stack what if BHP wanted to exit would you be interested in that position or you would just consider again the Eagle Ford to be more of a cash flow source.

I don't know we have to I'd hate to say on any individual asset whether we would be interested or not instead. I think it is probably fair to say that we tend to like things where we see value gaps and a lot of times of value gaps of appear because of a perception of what the upside of an asset may be from one company to another. So, I think given the maturity of the asset there's probably not as much inventory there as or maybe in other areas where there could be value gaps. Newest prefer more undeveloped acres so, I don't think that's a big focus for us right now, but I'd never have you know I mean have to see how it evolves, but that's initial thoughts.

Okay. Thank you very much, Dave.

I'm showing us at the top of the hour. So, I appreciate everyone's interest in Devon today. And if we didn't get your question, please don't hesitate to reach out to the Investor Relations team at any time, which consists of myself and Chris Carr. Have a good day.

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