德文能源 (DVN) 2016 Q1 法說會逐字稿

Welcome to Devon Energy's first quarter 2016 earnings conference call.

(Operator Instructions)

This call is being recorded. I'd now like to turn call over to Mr. Howard Thill, Senior Vice President of Communications and Investor Relations. Sir, you may begin.

Thank you Melissa, and I'd like to wish everyone a good morning as well, and welcome you to Devon Energy's third-quarter earnings conference call. I hope you've had a chance to review our first-quarter earnings release, which includes our forward-looking guidance as well as our detailed ops report.

Also on the call today are Dave Hager, President and CEO; Tony Vaughn, Chief Operating Officer; Tom Mitchell, Executive Vice President and Chief Financial Officer; and a few other members of our senior management team.

Finally, I'll remind you that comments and answers to questions on this call will contain forecasts, plans, expectations and estimates, which are forward-looking statements under US 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 might differ materially. For a review of risk factors relating to these statements, please see our Form 10-K. With that, I will turn the call over to Dave.

Thank you, Howard, and welcome everyone. There's no question that low commodity prices in the first quarter led to tough conditions for Devon and the industry. However, we responded to these challenges by delivering another outstanding operating performance, as we continue to take the appropriate steps to deliver significant cost reductions and accelerate efficiency gains across our portfolio. These successful efforts resulted in us delivering production at the high end of our guidance, driving down both operating costs and G&A down more than 20% over year, and increasing our liquidity to $4.6 billion.

This strong execution has improved our full-year 2016 outlook, with us raising our 2016 production targets by 3%, importantly without any incremental capital requirements. Additionally, our cost saving initiatives are well on their way to preserve more than $1 billion of cash flow during the year, and commodity prices are running above our base budgeting expectations. Even with a meaningful increase in commodity prices from first-quarter lows, our disciplined approach to this environment remains unchanged.

Our top priority is to protect our balance sheet strength by balancing spending requirements with cash flow, and we see no compelling reason to accelerate production at these improved, yet still low pricing points. As I touched on earlier, our 2016 E&P capital program remains unchanged, and the activity we will deploy is designed to maximize cash flow generation and maintain operational continuity in our top resource plays.

For us to consider adding additional activity, we would need to make additional progress on our asset sales, have the ability to hedge at sustainably higher commodity prices, and have comfort that we can secure services and supplies at rational costs. When these conditions are met, we have no shortage of attractive investment opportunities across our resource-rich portfolio. Our core assets are concentrated in North America's best basins, and we're getting the most out of these assets with Best-in-Class execution that has consistently exceeded peer results through higher production rates, lower capital costs and reduced operating expenses.

While there are several variables to consider when allocating capital, it is likely that we would initially accelerate activity with our top two franchise assets, the STACK and Delaware Basin. Between these two world class resource plays, we have access to over one million net acres and thousands of low risk development opportunities that are delivering rates of return that rank among the very top of our asset portfolio.

Another strategic imperative for Devon in 2016 is the work we were doing to improve our financial strength through the monetization of $2 billion to $3 billion of non-core assets. In April, we took an important step toward that goal with the announced sale of our Mississippian assets in Northern Oklahoma for $200 million.

The data rooms for our remaining non-core upstream assets have been opened since early March, and bids are expected by the end of the second quarter. The interest in our Midland, East Texas and Granite Wash asset packages has been quite strong, and we have great confidence in our ability to sell these assets at attractive prices in 2016.

In Canada, we're also making progress toward the sale of our 50% interest in Access Pipeline. Negotiations are ongoing, with discussions centered on contract-related considerations. Given the multi-decade life span of heavy oil assets, it is important that we judiciously work through these contractual details to ensure both parties are comfortable with this long-term relationship. Overall, we are encouraged by the direction of these conversations, and we still expect to announce a transaction in the first half of this year.

Before we move to Q&A, I want to summarize a few key messages from today's call. Even with the recent uptick in pricing, our top priority remains unchanged, [of] maintain a strong balance sheet. We are committed to balancing capital requirements with cash flow and enhancing our financial strengths by utilizing upstream asset sale proceeds to reduce debt.

We are laser focused on the controllable aspects of our business. This is evidenced by our outstanding operational performance in the first quarter and our continued cost control efforts.

We have taken aggressive actions to position Devon not only to weather this downturn, but to be positioned to take advantage of our world class resource plays when market conditions incentivize higher activity levels. And as commodity prices recover, Devon has significant leverage to rising oil, natural gas, and NGL prices.

For every $1 increase in realized price on a BOE basis, Devon generates more than $200 million of incremental cash flow annually. Additionally, this $1 increase in realized price proportionately expands Devon's margins more than nearly every large producer in North America.

Couple this with a catalyst risk deleveraging of the balance sheet from the asset sales and upside from further delineation of the STACK play, and Devon is extremely well positioned for differential stock price performance. With that, I will turn the call back to Howard for Q&A.

Thanks, Dave. To ensure that we get as many people as possible on the call, we'd ask you to please limit yourself to one question with an associated follow-up. You may re-prompt to ask additional questions as time permits. With that, Melissa, we're ready for the first question.

Thank you.

(Operator Instructions)

Your first question is from Ed Westlake from Credit Suisse. Your line is open.

Yes, I just wanted to start with the STACK update. You've said that the results are bigger, they're oilier, and the downspacing is more interesting. But obviously, you're capital constrained in terms of the amount of cash that you can put there until perhaps the disposals are executed.

So maybe just give us a sense of the type of news flow that you might be able to generate in terms of those three aspects, particularly EURs and downspacing, over the course of this year. Thank you.

I think Tony Vaughn is going to take a stab at this, Ed.

Good morning, Ed. As we continue to work our footprint in the STACK play, we're overwhelmingly -- had positive feel about the results that we see. And I think an operating report that we published last night continues to show that our results are above type curve expectations.

The interesting thing about this was a lot of rock and fluid and pressure variability across the play. In fact, Ed, the whole play is working, from the far Northeast to the Southwest, really well, but there's a lot of different characteristics of the play that are changing across that footprint. And if you look at the results that we've had just in the Devon footprint, our range of results have been very tight.

Our P10 to P90 ratio is about 2.4, which is very indicative of a lower risk development type play. So I think as we go forward, we'll continue to see optimization of our completion designs. We're changing the fluids. We're changing the proppant loads. We're changing the number of stages and tightening up on the perf cluster spacing, just like a lot of people in the industry are doing. So that will continue to optimize our results.

We're also engaged in about six different pilots across our footprint, and four of those are being operated by Devon. We already have production data coming at us on two of those pilots that we commented on in the operations report.

It's early, but the early indications are on a fairly conservative spacing on a single zone of five wells per section, which we're testing in the [Alma]. We didn't see interference on the frac work that we were doing. All the well rates are coming in to the type curve, if not better.

We published a little bit of information, early information, on the Born Free test, which was a staggered type test in the Merrimack, and very positive there that we did not see the energy across from one interval to the next. And ultimately, that would be spaced at about six wells per common zone, potentially 13 in the two that we're testing there.

We also had two additional pilots that will test seven and eight wells per section in a common interval. So I think as the data flow comes in throughout the year, we'll get more information about spacing.

We're participating in some other pilots from some of our non-operated partners there. They'll have information coming in. So really, for the second half of 2016, I think that spacing question will start being a lot more clear.

I think you'll continue to see our performance improve as we optimize the work that we do. But right now, we're extremely pleased. And as you know, as the -- if you look at the location count there, it's just very deep for Devon, and this will be a driver for Devon's future for a long time.

And then quick follow-up on the disposals. The commodity prices have picked up. Has that changed the attitude from buyers, particularly perhaps on the E&P side?

Well, Tom Mitchell can give you some more details on this. But I can tell you we're very pleased with where we are right now with the process. All indications have been positive so far. We're still in the middle of a process. But we're very confident of our ability to deliver in the range that we have put out there, of the $2 billion to $3 billion. Tom?

Not a lot to add to that, Ed. It has been very -- a lot of interest in the process, even more than we had expected and from strong parties, parties that are good for the money. So the commodity price environment has worked in our favor in that regard, as well as the liquidity events that we had earlier in the year. So we're well positioned, I think, to do extremely well with the trades.

Thank you.

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

Thanks. A follow-up on the questions specifically. Maybe I missed it, but for shorthand, did you put out an EUR in the over-pressured oil window?

Subash, I think we've got a type curve -- I'm looking for it right now -- that we commented on at the time we acquired the Felix footprint. And we actually had two different type curves, one in the volatile oil window and one in the oil window. Roughly speaking, they're about initial rates of about 1,500 BOEs per day, with an EUR of about 1,400 MBoe.

Okay. I can go back and take a look. My follow-up is, the Q2 decline -- and I guess as we come off the Q1 production, basin by basin, a little bit more flavor, if you could, on where you expect to see it?

And Canada has been surprisingly strong. I assume there was no royalty benefit, so how you see Canada performing for the rest of the year?

Yes, and to give you an idea, we are seeing a quarter-over-quarter oil decline here from our core oil, of about 25,000 barrels a day. But I think the most important thing to understand is that when you look out for the second half of the year, we expect our oil production to be flat to slightly higher than the Q2 production, as our completion activity resumes in the Eagle Ford and our Jackfish 2 facility ramps up to name plate capacity. So it is a -- and obviously, overall, we raised our production guidance. And so overall, it's a very positive story.

We may be seeing a slightly higher decline in Q2 than some of you may have expected, just mainly because we have such high rate wells that we delivered. Particularly in the Eagle Ford in the last half of 2015, with the lack of completion activity here earlier in the year, as the completion crews left the field. But overall, it's a very positive story. I think it may just have surprised a couple people that we're taking it in the second quarter.

But the good news is, as commodity prices improve, hopefully in the second half of the year, given that we raised our overall guidance, we'd be producing more than what was originally anticipated in the second half when prices will be higher. So Tony, do you want to add some more detail to that?

Yes, I'll just -- I think you said it well, Dave. Subash, if you go from Q1 to Q2, Dave commented that our total decline on oil will be about 25,000 barrels of oil per day. We actually have a turnaround schedule for Jackfish 2 in the second quarter, which will account for about 10,000 BOs per day. But if you look at the Delaware Basin and the STACK position on oil production, they're essentially flat over the last portion of the year, the second half of the year. So as Dave mentioned, it's a positive story for the Company.

I think the -- if you look and specifically talk about the Eagle Ford, you'll notice that we had outstanding results in the second half of 2014, and that carried into Q1 of 2015 -- I'm sorry, second half of 2015 that carried into the first quarter of 2016. And if you go back and look at that, the pace of activity was about 50 to 55 IDs per quarter. The number of wells we brought on in Q1 of 2016 was only 22, and that happened to be early in the quarter. So we ramped down activity, along with working -- that work with a partner there.

So the Eagle Ford has taken a larger -- projected to take a larger drop from Q1 of 2016 to Q2 of 2016. But again, as we bring -- we've taken a completion holiday there. As we bring completion units back into the field in the latter part of Q2, we'll see that production stabilize, from Q2 through Q4, in the Eagle Ford. Month to month, it's going to be pretty cyclical, depending on the pace of new wells that we bring on.

Thanks, guys.

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

Good morning, guys.

Good morning.

Let me just follow up on that broader question on the production profile, as it relates to the Eagle Ford. How many of the 90 do you see inventory -- [duck] inventory do you expect to complete from June until year-end?

In the Eagle Ford, as I mentioned, we were completing about 50 to 55 wells per quarter, and Q1 is about 22. And we'll take a holiday through Q2 of no new wells brought on in Q2. But then we'll see about -- roughly speaking, about 35 and about 15 in Q3 and Q4. So it's really lumpy.

We've got two drilling rigs. We've got two drilling rigs working in the field. And as we build up a little bit of inventory there, we will tend to work that down with one to one-and-a-half frac crews, and maintain a fairly flat duck inventory from the beginning of the year to the end of the year. It just will be a little bit lumpy from month to month.

And are those -- those are firm plans with you and your partner? Or do they depend upon the crude price or otherwise? I'd presume not, given your hedges.

That's our current plan. But I've got to point out to you that we're -- right now, in the technical side, we're lock step with BHP. We had the same thought process going forward. So I think that's the plan that we're going to execute on. And of course, if commodity prices change, we've got the ability to be flexible with that.

Right. And what would the production decline from Eagle Ford look like with no additional wells? Or is it -- no additional completions in 2H?

I think if you look at it, our Q4 to Q4 decline, just on the Eagle Ford, just on oil, was roughly about 30%. That doesn't include a lot of new IDs in the second half of the year. Be a little bit more than that, and I think we've published in the past that our first-year decline on Eagle Ford wells is very high. It's above 50% per year, first and second year decline.

So as I mentioned, we had an aggressive activity schedule through 2015. And without continuing that pace of activity, we're just seeing a lot of fairly young, immature wells in the high portion of their decline come on right now. And we're not having the new IDs to maintain that total flow rate.

Of course, what Tony described to you was a first-year decline rate of 50% for new wells. And you would have a number of wells that are not on their first-year production. They'd be in the flatter part of the decline curve. And so your number would be probably a little bit less than that on an overall basis.

Great, guys. Appreciate the color. Thank you.

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

Thanks. Good morning, everybody.

Good morning,.

Dave, you've talked in the past about -- [I saw] a horrible question about, when do you go back to work? But you guys have been a little more specific about requiring the asset sales to be done, pretty much irrespective of where the oil price goes to. So I just wonder if I could ask you to revisit your thoughts there?

And obviously, it's all predicated on your confidence level in getting the asset sales done. So do you go back to work in an oil price recovery before the asset sale is done? Or do the asset sales still have to come first?

The asset sales still have to come first. And now, having said that, I recognize this is a show-me environment, and we understand that very well. But I reiterate our confidence in the asset sales, that we are going to get those asset sales executed, without going into a tremendous amount of detail of the discussions and negotiations. And we are -- we think that is something that is working very positively, and we're confident that we're going to get those done in the time frame that we've described.

But that is the first priority, is to make sure that we do that. After that, then there are a number of things that will factor into increasing our activities, commodity prices, capital costs, operating expenses, many more. But directionally, you could look for us to start adding incremental activity when oil prices are $50 or higher.

Now, that doesn't mean we go back from the two operated rigs to 20 operated rigs immediately at $50. That means we would start adding operated rigs at that point. I said during the comments that the most likely first place that we would add the rigs would be in the Delaware Basin and then the STACK play, where obviously well results are just outstanding, and amongst the best in the industry, in both of those places.

And so we would incrementally add rigs as we -- as prices increase. But it would probably take $60 oil or more to really get back to a capital spend level of close to $2 billion, versus a $1 billion where we're at now, which would really, with our maintenance capital sitting somewhere between $1.5 billion or $2 billion, that would allow us to flatten the production.

Although frankly, we're not -- our number one priority is not just flattening the production on a 6 to 1 conversion rate. We're much more interested in, first, the financial strength of the balance sheet. And then second, making sure that every dollar that we invest is generating strong economic returns. And we included a graph in the operations report that gives you a feel that, again, we have some of the -- not only are we in some of the best plays in onshore North America, but we're in the heart of some of the best plays. We're in the core of the core of these plays.

So we certainly have what we think is good of an economic opportunity as anybody out there. But again, first, it's going to take the asset sales. Second, starting adding rigs at $50, again, of small increment then, and then continuing to ramp up as prices increase into our strong plays.

Appreciate the full answer, Dave. Thank you. My second one's really a quick follow-up to Evan's question on the Eagle Ford. Obviously, your full-year guidance presumably had the production floor of the trajectory that you've shown for the Eagle Ford baked in already. But you did mention in the prepared remarks, or in the release, that there was some planned downtime on infrastructure. I don't know if I missed that. But can you quantify what the volume impact is of that downtime in Q2? And if whether or not it's meaningful? And I'll leave it there. Thanks.

Yes, there is a minor amount of planned downtime. It's probably on the order of a little less than 5,000 barrels a day overall, but that is part of the impact, as well.

Great. Thanks.

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

Yes, good morning. Perhaps Tony, I was wondering if you could comment on just overall well results and returns that you're seeing in the over-pressured versus the normally pressured STACK? And perhaps where Devon's well results, from an operated and non-operated, have been concentrated?

Thanks for the question, Arun. That's -- I guess if I had to characterize the results that we're seeing, they're very consistent. If you look at our type curve of about that 1,300 to 1,500, we've brought on about five operated wells and five non-operated wells. All of those are at the type curve or better.

The footprint -- again, when we look at all the attributes of the STACK play, the project is working all across the play. But the attributes that describe the subsurface are drastically changing.

And the rock composition changes from the Northwest to the Southeast. The pressure gradient for the whole play is largely over-pressured. It does tend to increase in pressure as you go to the Southwestern portion of the field. And then as you move from the Northeast to the Southwest, you've got a changing fluid composition.

All of that's working across the field. If you look at ours, we're seeing type curve type results, very consistently. I think the best completion we brought on this quarter was about 2,100 BOEs per day. So we're feeling pretty good about that.

We find that the sweet spot that we've identified in our operating report for the STACK play has got the best combination of all those attributes, which incorporate depth and cost to complete. So we think that's going to be the high return portion of the development right now.

(multiple speakers) What I probably can just add in here, one of the things we tried to clarify by including a map in the operations report is that it's a gradational amount of overpressure throughout the play. And there's a map, I think on page 7, that shows it very clearly. That essentially all of our acreage is located in the over-pressured part of the play. It's just the degree to which it is over-pressured, and the degree to which it's over-pressured increases as you move from Northeast to Southwest.

Now, as you move further to the Northeast in our acreage position, you get more into the normal pressured oil window. That can work, too. I think, frankly, Newfield has had some good results up there, as well, and very economic results. But essentially, all of our acreage is in the over-pressured part of the window. It's just the degree to which it's over-pressured. So if you look at that map, I think that's helpful.

Okay. That's very helpful. And then just my follow-up, I was wondering if you could go through the staggered lateral testing in the Eagle Ford? Just maybe comment on that pilot, and expectations going forward, to develop the Eagle Ford using that spacing type of pattern?

We're encouraged. We drilled 25 wells, on a staggered approach, in the lower Eagle Ford. We've got a 3D earth model there that the technical team has built, and we've got an accurate description of where all the well bores have penetrated. And if you're just staying within the lower Eagle Ford section, whether you're in the upper portion of that interval or the lower portion of that, the results have all been the same.

So we are -- have now incorporated the staggered approach into the lower Eagle Ford, and results will be coming in on the 25 wells in the next couple of quarters. But early indications are, that's extremely favorable. So we're seeing reservoir pressures that would indicate that we're not seeing interference or influence from each of those wells.

One thing that we're going to be testing in the last three quarters of this year will be how to incorporate the upper Eagle Ford shale into that development. And there's not a lot of shale barriers between that upper Eagle Ford and the lower Eagle Ford sections. So we're encouraged, and I believe BHP is going to be supportive of this work, is to pilot an upper Eagle Ford Shale completion along with our staggered approach in the lower Eagle Ford. And that will be the -- what we think will be, ultimately, the design that we will go forward for the remaining development of the resource basin.

Okay. Thank you very much.

Your next question comes from the line of John Herrlin from Societe Generale. Your line is open.

One on the STACK. How gradational are the members vertically? And -- or how well defined are the various members between the upper and the lower? And will this affect -- given the pressure gradients you've already discussed across your acreage, will you have to have multiple pad development plans, depending on where you are?

John, I think we're getting -- we've got a great description of the surface there. And a lot of that's through the vertical wells that had been drilled. A lot of it on the south end of the field have been through the 800 wells that we've drilled in our Cana Woodford project. So we've got a great earth model that we built. We continue to refine that with new data.

I think the guys are very comfortable seeing five individual potential landing zones, three of those in the upper Merrimack, two in the lower. I think the technical teams are very confident with that. A lot of the data, to date, has been in the what we call the Merrimack 200, with some data in the Merrimack 300. So we think we had that well understood.

The portions that I think us and the industry are needing to appraise would be the very upper member of the Merrimack, what we call the Merrimack 100, and also the lowest member in the lower Merrimack, which is the Merrimack 500.

And I think if you look at the pressure distribution across the footprint there, I think it's a gradational map. If you take an ISO bar map of that, it's nothing where you go from normal pressure to high pressure in a short distance. It's just a gradual trend from east to west.

So I think that's being incorporated. You'll handle that with three-strain design on the Western side of the field. On the shallow and east side of the field, you'll handle it with a two-strain design. So it will be a little cheaper activity on the east and the west. But it's nothing that's, I think, onerous in terms of the future development concept.

John, to add on, geologically if you look at the logs, we have a good handle on where each of these zones is developed. That's not really the issue. The issue is more just, how productive are each of these zones? What spacing can you do in each of these zones?

And conceptually, if I can just broaden the discussion just a little bit, to give you guys an idea of what we're doing, both in the STACK play and the Delaware Basin. We have so many zones of STACK pay in there, in both of these areas, that we are conducting as many of these pilots as we can early on, to assess how to properly develop these areas.

It would be real easy right now to just skip the pilots, go in, drill everything on four wells per section in one zone, produce wells with great rates of return, and then wake up three years from now and you've blown through your inventory.

That's not what we're doing. We are taking a much more thoughtful approach of understanding the productivity and the spacing in each of these zones. So that we can develop each of these areas rather than what may be -- and this is -- I'm talking very conceptually here -- what may be, instead of four to five wells per section in a single zone, where you could have many more wells per section, perhaps 20, 25, 30 wells per section, after you understand the proper spacing of each of these, and each of these intervals. And how many of these you can develop within the same area.

And so that's what is -- we think is appropriate, at this time of lower activity, to really do these spacing tests and really understand. Because it has a huge impact on the ultimate resource that's going to be recovered in each of these plays, and on the value associated with each of these plays.

And so that's conceptually where we're trying to go with all these tests.

Thanks. That's what I was hoping to hear. My next question is on Canada. Obviously, you have Jackfish 2 turning around. But with the fires, are you going to -- do you anticipate having any issues with what's going on at Fort McMurray now? And that's it for me.

John, I think I just got a report from our operating team in the last day, and most of the activity that you're talking about is north of Fort McMurray. So there's nothing that we're worried about. We watch it every summer, and it's been a dry spring. So that area is tuned into it. And we have turnarounds scheduled again in June of this year, so we'll make sure we're free and clear before we start that activity.

Thanks.

Your next question comes from the line of Charles Meade from Johnson Rice. Your line is open.

Good morning, gentlemen. If I could ask another question on the STACK. I'm curious, after you get your asset sales done, if it would also be an option to perhaps clean up some of the holes in your STACK position? If you look at it, you guys are having great results there. And I have to imagine that some of those holes in your footprint have to be more valuable to you than they'd be to other people. So I guess I'm asking, what would be your appetite for that? Or is it an opportunity?

Charles, I think it's -- that's the -- that is an opportunity. It's the way all of our technical teams work in these core areas. So we're continuing to work with some of the offset operators and trying to core up where we can. We like the idea of having the ability to drill longer laterals in all the areas that we work.

So we're working with some of our offset partners on more of a holistic scale. We've got a great footprint there, and we've got a lot of running room. So it's not like we need to go out and acquire something that size or materiality, but we will continue to look for opportunities in core up, just like you mentioned.

Having said that, I want to make clear, Charles, to you and everybody else, we're done with major acquisitions. So what we're talking about here is just trying to core up with our acreage in these existing plays, where, as you say, the acreage immediately adjacent to our existing acreage may be more valuable to us than others. But as far as major acquisitions, that's -- we're done with that.

Got it. And so that might take the form of trades? Or so you can lengthen lateral and share the working interest or something like that?

Absolutely.

Got it. And then if I could ask a question about the Leonard, which I don't think anyone's asked about yet. Could you give us -- so you guys raised your type curve there, and you seem like you're more positive on that than we were maybe -- or you were a few months ago.

Can you put that play in context with the other Delaware Basin plays? I think where -- my baseline is that the Bone Springs is still the big dog out there, followed by the Wolfcamp. But is the Leonard, or are the recent results in the Leonard, changing that?

Charles, I think we've reported now on three recent Leonard tests there, and we've been extremely happy with that. And you can see this one that we reported on in the operations report is outstanding. It's a two mile long lateral. It's in the Thistle area. We have about -- I believe about 60,000 prospective acres in the Leonard play.

So in terms of scale, it probably doesn't -- it's not the same magnitude as the second Bone Springs. But in terms of well returns, it's every bit the same thing as the second Bone Springs.

And the industry has done a really good job of de-risking the Leonard and the Wolfcamp around us. There's been some industry spacing tests that we've got the data on that have helped us understand where we go from here. Our location count that we had commented on in the past, specifically for the Leonard, has really been directed towards the work that we see in what we call the Leonard B zones, but the A and the C are prospective as well.

Industry is actually working in the A and C, and our tests that we commented on have been in the B. So there's the potential to drive the location count up, both on a risk and an un-risked basis. And again, as we start thinking about our development plans to ramp up activity, the Leonard and the second Bone Springs will be at the top of our list, in terms of incremental well returns.

That's helpful detail. Thank you.

Your next question comes from the line of Brian Singer from Goldman Sachs. Your line is open.

Thank you. Good morning.

Good morning.

One of the points you made that you're looking forward to accelerate activity is comfort that you can secure supplies at rational costs. And wanted to see if you could comment on that point? And maybe, to try to phrase the question, to the degree you were thinking not about a $1 billion budget but a $1.5 billion budget, do you think you could execute on that within the -- what you would expect to achieve the returns you're looking for? And then what if it were a $2 billion budget? Where, if anywhere, do you see any constraints?

Obviously, the lower the level of incremental activity, the more confidence that we have that we can go out and execute at the very similar type costs that -- what exists today. And as you probably double the activity, we most likely would be doing that in an environment where we're not the only one that's increasing activity. The rest of the industry would, as well. And so the ability to do so for the same service cost, given the great reduction that we've seen in the service companies in terms of their capabilities, the availability of services, the availability of people, that becomes more challenged.

So I don't think any of us have an absolute answer as to what the implications of that are. But it's just something I can say with great confidence, that we'd be assessing very carefully, to make sure that we are producing still strong returns on these outstanding assets that we have. So I would anticipate, if we're going to increase from $1 billion to $1.5 billion, there may be some increases associated with that, but they're probably much more manageable increases.

If we go up to $2 billion, we'd just have to see. But again, we're in as good a position as anybody in the industry. This is not a problem that's unique to Devon. This is a problem that's going to exist for everybody, as prices recover and the service industry attempts to recover and rehire people and retool their industry, as well, that we're all going to have to be assessing. So Tony or Darryl, do you guys want to add some more to that?

Yes, this is Darryl. I would just say, as we see it right now, the only area where we think, if there's a big upturn in activity, that would cause us some immediate concerns would be in the stimulation side of the business. We think there's adequate rigs that are available, even though they are now stacked but not cannibalized, and we're talking the 1,500 HP rigs. We think there is ample supply of those, if we had to double -- if, for example, the industry would double their capital expenditure program.

We think the tubulars are in, really, pretty good shape. While there has been some decrease in the amount of labor that's available, we think, with modest increases, that labor would be back over a period of time, whether that's 6 months or 8 months.

The stimulation area is a different animal right now. We think that's been cut about 33%, in terms of capacity. How long it takes to get that 33% back, we don't know. But that would be the one area that initially would cause us some concern on the cost side of the equation.

That's really helpful color. Thank you. My follow-up is on [scoop ins] -- or on the STACK play. If we think about the changes in pressure regimes, the changes in GORs over a well's life, the strong oil rates that you've shown from -- at least on an initial production rate basis and your legacy production. How should we expect oil as a percent of the total mix to evolve, as we go over the next one to two years?

Brian, I'd tell you, we're watching that pretty close. And the STACK play in the Merrimack is too young to specifically comment. I will highlight, though, that all the fluid data that we have seen across the play has been to the optimistic side of our initial interpretation.

So all the new IPs that we're commenting on have oil contents of 60% or greater. We characterized, over the life of this field, that we would see something in the order of about 40 -- roughly 40%, 45% oil. Not sure how this goes, but we'll have to watch that.

But so far, across the play, we've been highly encouraged. And I tell you, the one anomaly that we've seen has been really testing the far Southwest portion of the Merrimack there. We've seen oil contents much higher than what we see in the Cana Woodford. Which really we haven't talked much about our legacy acreage position in the Woodford, but that really sets that whole couple hundred thousand acres of ours up for prospective higher yield production in the future. So really, it's a positive story for the play and specifically for our footprint.

Thank you.

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

Hi. Good morning, David. David, is there any scenario under which you don't sell access? Are we now just at the point of crossing the I's and dotting -- crossing the T's and dotting the I's on that deal? And is there some alternative whereby you would want to keep it? Thanks.

You're never done until you're done. And so we -- it's important to remember here that we're not -- it's not just as simple as perhaps the sale of an E&P asset. We're actually entering into a long-term transportation agreement with the purchaser of this asset. And so given that, we're establishing a relationship that's going to exist, and we have to make sure that all the provisions in the contract work for both sides. So that's certainly something that we continue to work through.

I can tell you, so far, that we're -- we have been working with a party for quite some time, and we have had additional interest from some other parties, as well. So we're very optimistic about where we stand in the overall process with this.

It's just a lot of things you have to make sure you get right. And also, we also have -- beyond the tariffs associated with Jackfish itself right now, we obviously have another project setting up there, in the Pike project, that we think is as high a quality as the Jackfish project. And this is a project we haven't sanctioned yet, but it's something that perhaps -- and we consider strongly sanctioning it in a more normalized commodity price environment. So that has some bearing on -- the associated tariffs on that, on how that would be valued by the potential purchaser.

So there's -- we're working through all those type things. But I can tell you, discussions are going extremely well on multiple fronts right now. And so you're never done until you're done, and it's obviously more than just dotting an I and crossing a T, I would you say.

Discussions are having some pertinent issues in the contract. But discussions so far have been very, very positive, and we still think that it's very realistic to have it done by end of the first half.

Good. Thank you for that. A follow-up, which is separate. You mentioned, as you ended your comments, the leverage of Devon to oil prices. Were you talking ex-hedging? And can you just go over your hedging strategy again, given the way things have changed? Are you intending maybe to carry more leverage to upside in oil prices now? Or are you going to be aiming for a similar level of protection as you've had previously? Thanks.

Our overall strategy, Paul, is unchanged. We target -- and it's not an absolute -- but we target to be approximately 50% hedged by the point at which we enter any given year. And that's to help underpin the cash flows to the Company, to give us confidence around the capital spend that we can execute.

Now, we have, in historical years, with the exception of coming into 2016, but many other years, we've had a very, very successful hedging program. In 2015, as you know, we had over -- well over $2 billion of hedge gains. And so it's a program that's worked very well.

We have added some very attractive Q2 gas hedges now. We have more than 30% of our expected production hedged at around 269 per Mcf. And for the remainder of 2016, more than 25% of our oil production is protected primarily through collars, with a weighted average ceiling price of $44 and a protected floor of around $39. So we're going to add, on an opportunistic basis, throughout 2016, hedges where we see appropriate.

I can also tell you that we have recently implemented a change where we're going to do a certain level of our hedging program -- not the entire program, but a base level of our hedging program on a more programmatic basis. Where we will enter in a level of hedges each quarter, and we'll probably hedge forward as far as six quarters, and do it on a consistent programmatic basis. But we'll still have a good portion of the program that's going to be done more on an opportunistic basis, as we have historically done as well, with the overall target to be around 50% hedged as we enter in any given year.

Got it. So basically, you're retaining that 50% target. You just may change the trading strategy to be more ratable, I guess, to a given extent.

Yes, a little bit of change, not a huge change, but a little bit. Adding some programmatic, and a little bit less on the opportunistic side. And by the way, Paul, on those sensitivities, those are ex hedges. Those are without hedges.

Got it. Understood. Thank you.

Your next question comes from the line of James Sullivan from Alembic Global. Your line is open.

Hey, good morning, guys. Thanks for getting me in here. Just one quick follow-up there on the sensitivities. Obviously, so you just clarified that it doesn't include the hedges you guys have laid on. But it does include, I'm assuming, the expense, the leverage you guys are getting on -- from the expense cuts that you guys have made to date, I assume, right?

Yes, it would be excluding the hedges that we have layered on. That's correct. And it's really based on the realized price that we are getting.

Okay. Great. Thanks. So just on a totally different topic -- most of the questions have been asked and answered. But what are you guys seeing on the -- in the NGL markets? Obviously, you guys have a lot of leverage to that product in the STACK, especially in the [old Cana] position and everything. But obviously, there's the ethane and propane prices have come back a little bit.

Could you just give us your macro thoughts on that overall product category? How you see things going into the second half of 2016 into 2017 with the potential for demand increases?

Yes, this is Darryl, and you are exactly right. We have -- a large component of our production is NGLs. It's around 20%. Just some background, about 50% of that is ethane, between 25% and 30% is propane, and the rest are butanes and natural gasoline.

In the macro view, we continue to see that improve, although we still think in the short term, over the next few months, you're going to see a greater amount of supply than demand. However, that demand is starting to increase as we bring on additional petrochemical plants and we continue to add export capacity via water. That has increased in the last three years, from about 200,000 barrels a day, the export capacity, up to about pretty close to 1 million barrels a day.

By the end of this year, early next year, we'll have added another 250,000 barrels a day of export capacity on the water. About half of that is propane, butane and gasolines. About half of that is ethane. So we're starting to see the export opportunities bring supply and demand back into balance. And so we think there's going to be more upward pressure on NGL products, over time, than we've seen in the last year-and-a-half.

Great. Thanks, guys.

Your next question comes from the line of David Tameron from Wells Fargo. Your line is open.

Hi. Thanks for taking my question. Most have been answered. One final one. On the Barnett, if we were to see a ramp in gas prices, would you -- what would it take to accelerate activity there? Or would you use that additional cash flow to -- and allocate to one of the crude plays?

David, we look at our -- the entire portfolio. So when we generate incremental cash flow, we look at the entire portfolio. And I would suspect that the entire boat would be lifted. We like the Barnett. We think it's got low risk opportunities. I think we've commented, in the past couple of calls, that we really have de-risked and completely understand the vertical re-frac opportunity.

And we've got about 30 of the horizontal re-frac opportunities under our belt, and we think we've understood how to do that. We've got a real positive relationship with our EnLink partners there, so we would consider the Barnett. We also have some opportunities in Cana, in the drier portion or the leaner portion of that property, as well, that would be just as commercial.

Okay. So I guess -- okay. Fair enough. Appreciate the answer. Thank you.

Your next question comes from the line of Ross Payne from Wells Fargo. Your line is open.

You guys have answered my question on the hedging, but glad to see you're going to be raising that through the rest of the year. Thank you.

Thank you, Ross.

Your next question comes from the line of Derrick Whitfield from GMP Securities. Your line is open.

Thank you, and good morning.

Good morning.

Speaking to the STACK Merrimack, in your upside case of 14 wells per section on page 8, how many flow units or intervals are you guys assuming in that density pilot? Is it simply two as the [car team] indicates? And more specifically, is it the Merrimack 200 and 300 intervals?

It's going to vary. It's a little bit hard to describe, but it depends on where you are in the play as to which of the Merrimack zones you're going to develop, because different zones are developed aerially on different parts of the play. And what we're trying to describe in that is whichever is the primary -- and it could be the 200, it could be the 300, it could be the 100 -- whichever the primary, where we're testing at eight wells per section.

And we're also testing a secondary zone, and up to six wells per section. But exactly which interval that is will vary across the play, depending on where it's developed geologically.

And then just order of magnitude, Dave -- and I understand it varies with regard to where you are in the play. But how many industry results do we have in the Merrimack 100 and 500? Because that seems to be the least delineated, based on your comments.

I think that's correct. I don't know the exact well count, but we have about 140 data points across the industry. We actually have an ownership position in about 100 of those 140. In fact, we have data in most of the 140.

We've operated about -- I think about 30, 35 operations. But again, it's largely being confined, at this point, to the 200 and 300. Order of magnitude, I think we probably have less than five data points in both the 100 and the 500 zones.

Thanks for taking my question.

Your next question comes from the line of Jamaal Dardar from TPH. Your line is open.

Good morning, guys. Most of my questions were answered, but just wanted to touch on the Delaware Wolfcamp. It looks like appraisal drilling will be somewhat limited this year. But just wanted to think on timing of tests there, given some really positive results we've seen, particularly in Lee County. So just wanted to get a sense on your expectations on prospectivity and results in that part of the basin? Thanks.

Jamaal, we've really focused on our work in the second Bone Spring. We continue to find that second Bone Spring, and now the Leonard, will be the top incremental returns that we can generate in our portfolio. We really like how the industry has de-risked around us the Wolfcamp, and as you mentioned, it's come up across the New Mexico border. We watch all that work.

If you look at the -- or if you consider the future development plan for the STACK column of opportunities, it will all hinge on what your outlook is for commodity prices going forward. And so in the mid cycle to low cycle case, we've got a lot of work to do in the second Bone Spring and the Leonard sands.

And as we move from the mid cycle to the high cycle, we've got a lot of opportunity in the Wolfcamp that will be incorporated into that. So we're encouraged by you the Wolfcamp. We just don't find the commerciality to be as competitive in the Wolfcamp as we do in the Bone Spring and the Leonard.

But that cycles back to the comment I started to make earlier, which is how many different zones that we have here in the Delaware Basin, as well as in the STACK play. And what we're trying to do is get an idea of what the productivity is of each of these zones, what is the optimum spacing in each of these zones. And we're being very thoughtful about our approach to this so that we are developing and -- fully developing the resource and the value associated with these. Versus the alternative of just drilling very quickly in one zone, and four wells per section or some fairly broad spacing, and essentially developing -- sub-optimally developing the entire inventory that we have.

We're not doing that. We are being very thoughtful, very careful, because we are sitting on truly world class resources here, in the hearts of some of the best plays, and we want to generate as much value as we can, long term, from these resources.

Just one thing to quickly add to that, Dave. We've talked to you about, in the past, about the tension and the drive for technical excellence, and that has been translated into public data that I think all of you have access to. If you go look at IHS reported information, quarter to quarter, we have talked about the 90 day IPs that we're generating on our inventory, continues to improve and out-compete over peer group.

If you look at the trend over the last four years, we've gone from a mid-pack performer to 2015, we're number one in terms of 90 day IPs. And that's a combination of the great portfolio that Dave just mentioned, but it's also attributed to the competency of our technical team that we're extremely proud of those results.

We are now at the top of the hour, and while we didn't get to every caller and we apologize for that, we are going to bid you a good day. We thank you for your interest in Devon and all the good questions. If you have any other questions, please don't hesitate to follow up with one of us in Investor Relations. Thank you, and have a great day.

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