德文能源 (DVN) 2017 Q1 法說會逐字稿

Welcome to the Devon Energy First Quarter 2017 Earnings Conference Call. (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 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. As you can see from our first-quarter results, Devon's threefold 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 continued 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 3 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 2 franchise assets, the 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 are 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 ratings and $2.1 billion of cash on hand, we have the financial 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 takeaway 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 utilizing a much more diversified vendor universe space. Also adding to our savings are the continued efficiency gains we are 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 pressures through the first part of the year.

Overall, when you combine our financial strength 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 the 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 results 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 3 high-rate Bone Spring development 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 3 Leonard Shale intervals, and we have as many as 4 more multi-zone projects lined up to begin in the Delaware over the coming year. This development approach is expected to have 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 with 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 accelerate activity across the Delaware Basin in 2018 and beyond, we have recently submitted 4 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 our first master development plan at the Cotton Draw and expect the other 3 plans 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 a majority of the 39-well Hobson Row with results from this high-impact row tracking at or above our EUR-type curve of 1.6 million BOE per well. The 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 will deploy the learnings 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 overpressured oil window of the STACK, our appraisal work during the quarter confirmed the potential for up to 4 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 set to spot in the third quarter.

While still preliminary, our plans call for drilling 25 to 30 wells across 2 drilling units at Showboat, codeveloping both the Meramec and Woodford formations. With additional appraisal success in the core of the 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 flowback results from our 9-well diamond spacing tests in Eagle Ford were very strong with 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 multiyear inventory in the field.

Our initial Rockies drilling work also delivered impressive results. Our first 4 Parkman wells crushed type curve expectations by averaging more than 1,800 BOE per day, of which 95% was light oil. Making the Rockies story sizzle even more for the quarter are the results from recent state and federal lease auctions. Winning bids that offset our Southern acreage position reached nearly $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 to deliver sustainable, long-term growth. Between the STACK and Delaware Basin alone, which were 2 of the very best position plays on the 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 noncore asset divestiture program over the next 12 to 18 months. The noncore assets identified for monetization include select portions of the Barnett Shale, focused 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 risked resource base in the U.S. has the potential to further expand with ongoing appraisal work in the STACK and Delaware Basin. With successful delineation results, we would evaluate strategic options for additional noncore 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 multiyear growth targets. Additionally, the certainty associated with our capital programs uniquely positions Devon to maintain 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-advantaged 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. (Operator Instructions) With that, operator, we'll take our first question.

(Operator Instructions) Our first question comes from the line of Arun Jayaram with JPMorgan Chase.

I was wondering, Dave, if you could maybe give us some more details on the multi-zone development. You mentioned that you'd submitted kind of a 4-master development plans. I was wondering if maybe you could give us some details on what these development plants could look like at Cotton Draw in terms of the different zones between the Bone Spring, Wolfcamp, Avalon, et cetera.

Yes, Arun, I'll take the first part of this, Arun, and good morning, and then I'm going to turn it over to Tony to talk about the specific zones that we'd be developing. But talking a little bit about the master development plan, 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 it's 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 execute on the drilling program. With this master development program, that essentially gives us a permit for a large area. You see, we've submitted 4 across -- this is going to give us 600 permits, on average, about 150 per master development plan. We have the first one in already. And so with that, and all you have to do is get the -- an 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, where 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?

Yes. Arun, I appreciate your question. This is a -- some planning work that we've been incorporating into the halls of Devon for about the last 2 years. And again, as Dave mentioned, we appreciate the partnership that we have with 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've just commented on, we just finished the drilling of our Thistle Area 10 well pad. We'll 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'll be prosecuting all of those areas there.

This one design allows us to have larger-sized pads, not in surface area as much as in well count. And it will have a centralized production facility that each of the pads will be able to flow into. This starts optimizing the surface facility, starts optimizing really the manufacturing process that we have. We'll be able to have simultaneous operations as we go through the work. So it provides a lot of the inherent efficiencies in our plan that -- with the 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 my prepared remarks, some of the benefits of this type of development. I know one of the pushbacks that we've had is people are concerned, "Oh, my gosh, is this going to look like a major offshore development in terms of timing with going in this direction?"

Two comments on that. First, as Tony said, we're starting out small. So you aren't going to see large wins initially. We're going to have 10, 15, 20 type well-sized pads initially. And the second point is, in each of these pads, we're going to have multiple rigs working. And so bottom line is, you are not going to see a significant timing shift as we go from the 2 to 4 wells per pad to larger because of how we're 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 in that and we've been working on that for a long time.

Great. And my follow-up, I wanted to talk a little bit about the 4 extended-reach wells that you're doing at the Hobson Row. And what are your thoughts around the Jacobs Row? I think you've talked about a 70-well development with Cimarex; I assume that's just standard laterals, and if these 4 extended-reach laterals wells do okay at Hobson, how could that influence your development plans for the Jacobs Row?

Arun, we are really through all of the -- on the Jacobs Row, we're -- or 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 can talk a little bit more about that as we go through the call, I hope. But great efficiency of operations, execution phase is going really well.

We're just now getting to the long laterals that we've described in the plan for the Hobson Row. We're fully expecting that the long lateral is going to be the design of the future, and that will be what we incorporate into the Jacobs Row.

What I'll also comment on about, we have a 50-50 partnership with Cimarex there, as you mentioned. We're continuing to work with their technical teams on what the -- what the forward plan is for capital allocation, both in Devon and in Cimarex. Right now, we're expecting to prosecute our 3-well section at the -- in Q4 of this year. We're expecting Cimarex to be close to that same time frame. But for right now, we're fully anticipating long-lateral designs as we go forward and fully focused on starting our 3-well program in middle of Q4. (inaudible)

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

It's going to be -- Arun, it's going to be long laterals. Every time we can drill a long lateral, we're going to drill a long lateral. So I think if you'd look at the layout on the map that we've highlighted here, they're all going to be exposed to long-lateral drilling.

As you know, just the standard-length laterals, you're looking at 1.6 million equivalent on a recovery basis, right? So when you extend these laterals out with the Jacobs, the returns really ratchet significantly higher, rivaling what you're seeing in the overpressured oil window in the Meramec. So this -- it'll be a great project for us, and we're pretty excited about our spudding activity which will occur in Q4.

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

So I wonder if I can start off with a question on inventory, Dave. And I guess, it relates also to your $1 billion proposed asset sale. There are multiple pieces to this question, I guess. But just looking all the data you've given today, I mean, you talk about going to 20 rigs in the Delaware, you talk about 2,000 location -- unrisked locations. But yet, your inventory in the Wolfcamp is only 500. So when do we -- 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 -- and the fact that you've got third and fourth landing zones now that seem to be working in the core of the STACK? It just seems your inventory is substantially understated. And my related question is what that means for your -- the timing of your noncore disposals as your inventory extends. If I may, I've got a quick follow-up to that, I'd be glad.

Great. Well, I think you're hitting it exactly right, Doug, that we see significant upside to our risked inventory.

We obviously had a great well there with The Fighting Okra, then there's been some great offset wells to that. We're 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 actual appraisal results before we really put it into our 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 look, as I said in the prepared remarks, we look at this divestiture program as a first step. We think it's an appropriate first step because obviously, commodity prices also have 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 end 2017. And we even talked in the last operations report, we didn't put it in this one, but at $60 and $3.25, $6 WTI, $3.25 Henry Hub, we'd 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, that certainly gives us increased certainty that we can deliver on the growth results even if commodity prices soften because these wells are still generating incredible rates of return even at somewhat lower prices. So we 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 appraise the -- these areas such as the Wolfcamp and additional landing zones in the STACK, we will consider additional divestments as appropriate -- if this -- if they are appropriate, and so I would look at this as certainly a signal for how we're going in the future because we think this is the appropriate first step. But as we finish our appraisal program, there could be further steps. Or if we continued with our appraisal programs, there could be further steps.

So just to be clear, Dave, so you're basically saying that Devon lives within cash inflows including asset sales?

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

Okay. My follow-up is really on the relative economics across the different plays. Because obviously, you've got a ton of things that are emerging that are competitive. And both in the back of my mind is the Rockies statement you made in the presentation.

In order to provide a per-acre value, one would argue that you're trying to get the market to focus on the value of your acreage. But of course, that only gets realized if you monetize it in any reasonable time line. And I guess, you could say the same thing about Conoco's recent sale of their oil sands. Again, they got a big valuation for that. It's probably not getting recognized in your stock.

So when you look at the built, the growth in inventory that you're clearly having in these other areas, how do these 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 sands? Just how do you think about how you would prioritize noncore asset sales?

Well, first off, I'd say, and we're not just trying to highlight it. And we don't think it only necessary gets built in when you sell it. We can have that discussion over a beer someday, I guess. But I don't think we have to sell all of our assets to get value recognized for it.

But we -- just what we're trying to say is that other people are 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 -- our conscious strategy here at Devon has been to not only be in some of the best plays in onshore North America, but to have the best positions in the best plays in onshore North America. These are big plays and they're always in these plays. There's 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'll stand them up against anybody in the industry because we are in the heart of the best plays in onshore North America. Tony, you want to add any comments from a relative viewpoint on them -- on the economics but I'd tell you, they're all pretty outstanding.

Yes, I do. I think one thing, Doug, that we're proud about is we've 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 we had in the Powder were every bit as good, if not at the top end of our results in late Q4 of '14. And again, if you look at the 6 wells that -- 4 wells that we've talked about for this particular quarter, again, they're at the top end of our portfolio. So it's equivalent capability to the Delaware, the best of the Delaware and the best of STACK; it just doesn't have the same scale to us as the others. So as commodity prices rise and additional cash flow is generated, it's going to be a great opportunity for us.

Your next question comes from the line of Phillip Jungwirth with BMO.

A question on the Barnett. Of the $400 million to $500 million of cash flow expected in '17, just trying to understand at a high level. Does this include the MVC payments? And how should we think about any upside to Barnett cash flow if GP&T contracts were closer to market rates?

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

Yes, just trying to understand how much upside there could be to that cash flow number if the GP&T contract with EnLink were, in your view, closer to market rates?

At that point, Phil, that's undisclosed. There's confidentiality regarding that. So that's not a number that we're 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 sought after, and we expect to have good market depth as we look to market the assets.

Okay, great. And then, there's been a fair amount of Osage activity up towards Northwest Dewey and Woodward counties, and we've even had an S-1 filing from one MP position up there. Was just hoping that you could help frame Devon's position in this area, and is there anything to discuss in terms of well results, thoughts on the play or future activity plans?

Phillip, I think we've described that we have about 80,000 acres of what we call the Northwest STACK 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 activity in the area. We're really not ready to disclose that. But we're encouraged and excited about the opportunity going forward. And so I think at this point, that's all, that's where we'll leave it.

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

And it really feels like you're making progress on derisking these multi-zone pads out in the Delaware. I mean, each of the individual wells you give us data 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 type curve and well costs? Or is it still too early?

Probably the challenge to do that, Ed -- and good morning -- is that it really depends a lot on where you are. And in even some cases, you'll find that some zones have already been developed, and we'll be just developing other zones as well. So there's -- it's a fairly complex thing to try to give you a per section.

In some cases, there are, as Tony said, we have Bone Spring. We have Leonard. We have Wolfcamp. We have Delaware. All of those and other areas, such as our initial development in Thistle, we're just developing 3 zones in the Leonard, and then there's every other variety as well. But I guess, the key is they're all working incredibly well. But it would be a very -- it's not really possible just to give a type curve per section, I don't think, because of the variety.

Okay, yes. But I think when I think of the inventory and the value of the inventory, I'm trying to think of reasons why the shares aren't reflecting that. And that sort of uncertainty maybe one of them. Although we can see obviously, some very good well results.

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

The other comments in the ops report around operational efficiency were very interesting. You talked about unbundling. Obviously, inflation is 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, proppant or pressure pumping or other lines is leading to savings relative to, say, a year ago or Q-over-Q, however you want to describe it?

Ed, we are seeing a tension and cost escalation across the business. We've been very pleased. I think we've commented in the past that we're going to be able to mitigate about 75% of that cost escalation throughout Q4 of '16 to Q4 of '17 with just some good planning and good operational-efficiency work. We're seeing that. In fact, if you look at our capital spend through Q1, we're a little bit light, and we feel like we're being able to mitigate any tension we have on the system.

Our guys are doing an extraordinarily good job right now with the planning, not only the execution, but the planning of the work that we do. And so when the guys are looking forward, we're already working out into 2018 and 2019, planning our work there. It allows us to go to our providers, give them certainty about the long-term plans. They're 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 for all of our work in the Mid-Continent and also in the Delaware. We have entered into a contract to secure the 100-mesh sand for all of our STACK work for 3 years out.

We find that the sand mines are pleased to be working with the end-user because we have definitive plans. And also, Ed, we're not at the mercy at some of the larger-scaled pressure-pumping providers because they're getting plans from a lot of people that may not be as fine-tuned and as well-thought-through as ours. And so we would tend to get shuffled at times.

And so if I went back and looked at the look-back on our work that we just completed on the Hobson Row, I think we've had a total of 7 hours of delay not having sand on location ready to pump. Historically, we would have 3x 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's 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 3 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 costs 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 what we've always had a fair amount of our rigs under term, we -- 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 4 out of the 6 frac crews that we have working are on 1-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're -- we got places across the business that we have essentially leaned out and are gaining operational efficiency that we didn't have 2 years ago.

Your next question comes from line of Scott Hanold with RBC.

Just kind of curious. As you look at the STACK play and discuss the opportunities to get 3 to 4 potential formations for these, 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, 1/3 or lower Meramec available or the Woodford available? Is that something that you got a good sense of right now or is there still a lot of work to get there?

Scott, I think you've -- if you watched the release on where our well activity has been, we've been really appraising around the -- what we call appraisal areas 1 and 2.

In appraisal area 1, we'll have our first development that'll 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 have in our operating reports.

So in the specific area of the Showboat development, we've got great pilot results in. It's giving us confidence to incorporate parts of 3 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 early part of '18, we'll be moving rigs more westerly than they have been to date.

We're also going to be learning from our results as we go here. And so the first development, for instance, as Tony described here, is in the Showboat area will -- our next development will be most likely a little bit to the west of this so that we 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 because we think there is a question. So whether these wells are in vertical communication, and less wells is good. If you can get 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 when we move back into that area.

And so we have a very, very well thought out, very well-planned approach to this. So that we will be -- bottom line, optimizing the NPV over [IR] or the capital efficiency that we're going to get from this program.

Okay. And I hope I didn't -- 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 thickness of the Meramec?

As you move to the West and to the South a bit, Scott, you are moving into a thicker 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, you have a potential sale. Can you guys give us a sense of how much per net production you all 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. Simple way to think about that.

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

First, going to the multi-zone concept. And 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 has done it. I 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 derisked and are already in the development phase and some had 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 partition-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% on the D&C 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 [the] guys are looking at this on a project-by-project basis. And it's hard to describe that, but they'll be looking to maximize values and returns.

Now that was a helpful answer. 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 nat 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 dryer 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 -- and 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 of capital. It's just our portfolio's 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 that -- those type decisions on a -- at the appropriate time. And I think you saw the first step of it with our announced divestment last night and I described earlier the rationale for the timing and the magnitude of that.

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

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 your lack of capital deployment in the Wolfcamp as the view that it wouldn't compete on a returns basis with the Bone Spring and the Leonard. I mean, the first well there looked quite strong. And I mean, would you still, at this point, based on incremental data that we've seen over time, characterize -- how would you characterize the returns competitiveness of the Wolfcamp versus the Bone Spring and the Leonard? And could this have any impact on how you think about deployment of capital within the Delaware going forward?

Ryan, we're actually very -- have a very positive view on the Wolfcamp going forward. And we've seen some industry derisk the Wolfcamp around us, and we've reported on The Fighting Okra well ourselves. So we're highly encouraged that the opportunity in the Wolfcamp will compete for capital as well as our Bone Springs, Delaware and Leonard going forward.

If you really go -- step back about 1 year, 1.5 year ago, we didn't have the infrastructure built in the Southern portion of our play there. So that was a learning experience we had. I think you also saw about that time, we had very high lease operating cost per BOE.

All that infrastructure, we've caught up with ourselves now. And so we've got full water being piped. We've got power-grid system across our position there in the Cotton Draw and Rattlesnake areas. So we'll have a much healthier, commercial answer for our Wolfcamp development going forward. And if you just look at the areas of focus for the -- for '17, probably about 50% to 60% of our well activity will be focused in both the Leonard and the Wolfcamp going forward. So we're encouraged by the quality of results that we're seeing in the Wolfcamp.

I would -- you know, 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, that's helpful. And then, maybe one follow-up on the multi-zone developments. You've talked about some of the drilling and service-level improvements and efficiencies that you might see in there. I wasn't sure if you'd just said that you could see 20% D&C improvement. But have you quantified what you think the efficiency improvements might be in a multi-zone development relative to kind of single wells that you've drilled in the past? I mean, are we talking about a 10% improvement in kind of capital efficiency, 20%? Any ability to ballpark that?

Ryan, that's what I was trying to describe a little bit earlier. But we have quantified that. Guys did 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 2 to 3 wells per pad. And I could 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 difference. This is not like an offshore development. Tony and I have worked a lot of offshore developments. We know what offshore developments look like. But you're not going to see a significant timing difference or -- compared to what you've seen historically, which I think has been some of the concern.

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

A lot has been covered. Maybe a bigger picture question. What level of well performance do you guys factor into your full year production guidance? I mean, is it -- is that based on your actual type curves or something higher? And I'm asking the question because you just reported excellent well results across all 3 of your major basins, most significantly above those type curves, yet I think the full-year production guidance remains unchanged. This is kind of contrast between the guide and the information in the ops report.

Yes. Well, first off, the well results are outstanding. As you said, there's absolutely no hedging on that. But you just have to understand that the current-year well results proportionally to the total production is pretty darn small. And so there's a lot of other factors that go into your production guidance beyond just the current-year well results.

So -- and then, obviously, I think everybody's figured it out by now that what has shifted between our outperformance here in Q1 and somewhat lower guidance in Q2 is just the fact that we've moved -- we were 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 then that's -- on those wells. But they do go on, they're incredibly economic wells, but they are -- come on at very high rates and have pretty steep declines. And we'll see some of that in Q2 in the Eagle Ford.

So there's just a lot of factors that go into the full-year production guidance 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.

Dave, can I just add...

Yes, add in a little more, Tony.

Yes, just to -- 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 this outperformance. And if you remember, Evan, I think it was probably several quarters ago that we showed that our 90-day IPs were #1 out of the 30 most active operators in the U.S. space. And that was in 2015.

In 2016, you looked at data. In 2015, by the way, with the average of our per well performance was over 600 BOEs per day. When we look at 2016, our average for new wells brought on is over 900 BOEs per day. So we took what we thought was an outstanding performance in '15, continued to evolve, doing some really sophisticated subsurface modeling, frac modeling and have increased our 90-day IPs another 50% in '16. And you start looking at the 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 achieve really outstanding results.

And just a point of clarity real quick. Those are for 90-day rates and then also, the gas piece of that production which is being adjusted on the 20 to 1 basis as well. So that would account for some of the reconciliation versus some of the 30-day rates you're seeing in our operations report.

Great. So we'll look for that in the 2018 numbers. It sounds -- and my second question is on the -- a bit of a follow-up on the asset sale program to pick up on your opening comments and some of the Q&A discussion. The asset program appears to be poised to grow as organic location count grows. How do you think about optimal inventory depth that defines how much is noncore or sold, either in years of inventory, regional or return-driven program? And somewhat related, I mean, is the vision-to-scale asset sales with the ability to redeploy the capital or is it more paced just with the downspacing results?

Yes, that's a great question, and it's a really hard question to answer. It's kind of like the old reserves production ratio. You can have too much and you can have too little, and what's 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 -- there would be very economic locations at anticipated prices as kind of a quick summary of where I would say. I don't think it does a lot of good to have 100-year inventory, and I don't know if I'd sleep real well if I had a 5-year inventory. So somewhere around that. And is that their exact right number, I really can't say. But I think that probably gets you somewhere in the ballpark.

Great. And the pacing concept, is it due to sales utilized to kind of match the ability to redeploy capital? Obviously, neutralizing for any kind of commodity change? Or is it just going to run its course with the -- with results and location count?

Well, we see this billion-dollar divestment program as just giving us additional certainty with -- and we would do it anyway because it's the right thing, because it's the right -- given the depth of our inventory. We also see that at the 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 derisked -- 2018 and the end of the game for us, we see continuing ramp up in capital and activity as we move forward beyond that. This is just going to continue to accelerate our growth in the future years. And we will, if all the appraisal work works out as we anticipate it will, I'd think that we would be looking at additional divestments depending on commodity prices, too, how strong those are, but we'll probably be looking at additional divestments to focus our capital even more.

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

Just first question. I wanted to follow up on a comment 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 piloting, how we should think about your core inventory over the next few years?

Matt, we're very pleased with the well results that we saw with the acceleration of our ductwork into Q1. That data is being incorporated both into Devon and BHP's technical thoughts right now. But the lower Eagle Ford staggered wells work 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 -- the technical teams will come out with their plan. I would guesstimate somewhere between 500 and 1,000 locations going forward. The main thing to think about at this point is we've got 2 rigs operating right now in the play, anticipate probably 3 in the second half of this year. Those will be utilized when the guys have incorporated all these results into their thoughts.

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

Great. And then as a follow-up. Just in regards to the PRB, you've highlighted some fantastic Parkman wells here and the rates of return on a well-level basis are competitive with the Delaware and the STACK. Just curious from a milestone perspective, what we should be watching for over the next year or 2 in terms of opportunities to scale the PRB further in regards to production and in capital allocation?

Our plans right now, Matt, 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 and the Rockies -- will be, kind of the question that we evaluate quarter-to-quarter. But we've got the inventory and permits are coming. We've got another good relationship there with the BLM office that is progressing. And we feel pretty good about certainty of execution in the Powder as well as we do in the STACK and the Delaware.

And our final question for today comes from the line of John Herrlin with Societe Generale.

Actually, to get to these bigger drilling units, Dave. Tony has discussed some of the efficiencies you're gaining and the fact that vendors like long-term visibility. Do you see a point where as these drilling units are larger, that you have such concentrated activity that you're willing to do multiyear deals or that the vendors will do multiyear deals? And also, would it 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, I think, Tony tried to allude to that, that 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 a company that's actually going to drill the wells. So there's much more certainty of demand than there is dealing with a service company who is relying on representations from a number of operators. And it's not the service company's fault, but they may just not know in the minutest detail whether those plans are going to be true or not, where dealing directly with a Devon with an outstanding reputation for 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 about the harvest mode essentially for the Delaware and the STACK. What if BHP wanted to exit? Would you be interested in their position? Or you would just consider again the Eagle Ford to be more of a cash flow source?

I don't know. We'd have to -- I'd hate to say on any individual asset whether we would be interested or not interested. I think it is probably fair to say that we tend to like things where we see value gaps. And a lot of times, those value gaps 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 there may be in other areas where there could be value gaps. We just prefer more undeveloped acres. So I don't think that's a big focus for us right now. But I'd never have -- I mean, I'd have to see how it evolves, but that's initial thoughts.

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