Howard J. Thill - Devon Energy Corp. David A. Hager - Devon Energy Corp. Tony D. Vaughn - Devon Energy Corp. Thomas L. Mitchell - Devon Energy Corp. Darryl G. Smette - Devon Energy Corp..

Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Subash Chandra - Guggenheim Securities LLC Evan Calio - Morgan Stanley & Co. LLC Doug Leggate - Bank of America Merrill Lynch Arun Jayaram - JPMorgan Securities LLC John P. Herrlin - SG Americas Securities LLC Charles A. Meade - Johnson Rice & Co. LLC Brian Singer - Goldman Sachs & Co.

Paul Sankey - Wolfe Research LLC James Sullivan - Alembic Global Advisors LLC David R. Tameron - Wells Fargo Securities LLC Ross Payne - Wells Fargo Securities LLC Derrick Whitfield - GMP Securities LLC Jamaal Dardar - Tudor, Pickering, Holt & Co..

Welcome to Devon Energy's First Quarter 2016 Earnings Conference Call. At this time, all participants are in a listen-only mode. This call is being recorded. I'd now like to turn the call over to Mr. 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. 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 forecast 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 is 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% year-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'll 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 rationale 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 are 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 1 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're 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 towards 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 open 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 lifespan of heavy oil assets, it is important that we judiciously work through these contractual details to ensure both parties are comfortable with the 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 – maintain a strong balance. 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-rich deleveraging of the balance sheet from the asset sales and upside from further delineation of the STACK play, 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. Your first question is from Ed Westlake from Credit Suisse. Your line is open..

Yeah, I just wanted to start with the STACK update. You've said that the results are bigger, they're oilier and the down-spacing 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 down-spacing 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 overwhelmingly have a positive feel about the results that we see. And I think the operating report that we published last night continues to show that our results are above type curve expectations.

The interesting thing about this, with 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 per-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 into the type curve if not better.

We published a little bit of early information on the Born Free test, which was a staggered type test in the Meramec, and very positive there that we did not see the energy cross 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.

And we also have two additional pilots that we'll 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, 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 a 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 the 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, add to that?.

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..

Yeah, thanks.

A follow up on the question specifically, maybe I missed it but, for shorthand, did you put out a 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 MBoes..

Okay. I can go back and take a look. My follow-up is the Q2 decline and, I guess, as we come off of 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?.

Yeah. To give you an idea, we are seeing 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 nameplate 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 and 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?.

Yeah, 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 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 IDs to 55 IDs per quarter.

The number of wells we brought on in Q1 of 2016 was only 22 wells, 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 just 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..

Hi. Good morning, guys..

Good morning..

Let me just follow up on the prior question on the production profile as it relates to the Eagle Ford.

How many of the 90 DUC inventory do you expect to complete from June until year-end?.

In the Eagle Ford, as I mentioned, we were completing about 50 wells to 55 wells per quarter. In Q1, it's about 22 wells and we'll take a holiday through Q2 of no new wells brought on in Q2, but then we'll see, roughly speaking, about 35 wells and about 15 wells in Q3 and Q4. So it's really lumpy. 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 DUC inventory from the beginning of the year to the end of the year, just be a little bit lumpy from month to month..

And are those – those are firm plans with you and your partner? Do they depend upon the crude price or otherwise? I presume not, given your hedges..

That's our current plan, but I just – I've got to point out to you that we're – right now, on the technical side, we're lockstep 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..

Great.

And what would the production decline from Eagle Ford look like with no additional wells or no additional completions in 2H?.

Well, I think if you look at it, our Q4 to Q4 decline just on the Eagle Ford just on oil is roughly about 30%. That doesn't include a lot of new IDs in the second half of the year. It'll be a little bit more than that. And I think we 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..

What Tony described to you as 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 of production. They'd be in the latter 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 – it's that 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. So I just wonder if I could ask you to kind of 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 sales are 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, we think that that is something that is working very positively, and we're confident that we're going to get those done in the timeframe that we described. But that is the first priority is to make sure that we do that.

After that, then there are a number of things we'll factor in to 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 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 the $1 billion 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 6:1 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, we think, as 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, a small increment then, and then continuing to ramp up as prices increase into our strong plays..

I 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 for 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 whether or not it's meaningful? And I'll leave it there. Thanks..

Yeah, 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..

Yeah, 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. 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 Boes to 1,500 Boes per day, 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 of 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 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've 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..

One of the things we – what I'd probably 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 over-pressure throughout the play.

And there's a map, I think, on page seven 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 is 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..

Well, 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 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 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 section, so we're encouraged and I believe BHP is going to be supportive of this work as to pilot an Upper Eagle Ford shale completion along with our staggered approach in the Lower Eagle Ford.

And that will be what we think will be ultimately the design that we will go forward for the remaining development of the resource base..

Okay. Thank you very much..

Your next question comes from the line of John Herrlin from Société Générale. Your line is open..

Hi. One on the STACK.

How gradational are the members vertically 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 kind of 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 it'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 drilled in our Cana-Woodford project. But 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 Meramec, two in the lower. I think the technical team is very confident with that. A lot of the data to-date has been in what we call the Meramec 200 with some data in the Meramec 300.

We think we have that well understood. The portions that I think us and the industry are needing to appraise would be the very upper member of the Meramec, what we call the Meramec 100, and also the lowest member in the Lower Meramec, which is the Meramec 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 isobar 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-string design on the western side of the field. On the shallow and east side of the field, you'll handle with a two-string design, so it will be a little cheaper activity on the east than the west. But it's nothing that's, I think, onerous in terms of the future development concept..

John, I guess, just to add on, geologically, if you look at the logs, we have a good handle on where each of these zones has 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 play 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 I'm talking very conceptually here – what may be instead of four wells to five wells per section in single zone, you could have many more wells per section, perhaps 20 wells, 25 wells, 30 wells per section after you understand the proper spacing in each of these intervals and how many of these you can develop within the same area.

And so that's why it's, 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, Jackfish 2 turning around, but with the fires do you anticipate having any issues with what's going on in Fort McMurray now? And that's it for me..

John, I think just got a report from our operating team 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 has tuned into it, and we have turnaround scheduled again in June of this year, so we'll make sure that 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 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 of size or materiality, but we will continue to look for opportunities in core 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 our acreage in these existing plays, where, as you say, the acreage immediately adjacent to our existing acreage may be more viable to us than others.

But as far as major acquisitions, we're done with that..

Got it. So that might take the forum of trades 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 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 Spring is still the big dog out there followed by the Wolfcamp, but is the Leonard or are the recent results of 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, 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 2nd Bone Springs, but in terms of well returns, it's every bit the same thing as the 2nd Bone Springs. And 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 camp that we 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 a un-risk basis.

And, again, as we start thinking about our development plans to ramp up activity, the Leonard and the 2nd 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 for to accelerate activity is comfort that you can secure supplies at rationale 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 $1 billion budget but a $1.5 billion budget, do you think you could execute on that within what you would expect to achieve the returns you're looking for? And what if it were a $2 billion budget, where if anywhere do you see any constraints?.

Well, obviously, the lower the level of incremental activity the more confidence that we have that we can go out and execute at very similar type costs 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 costs, given the great reduction that we've seen in service companies in terms of their capability is 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'd probably be much more manageable increases. If we go up to $2 billion, we 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 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?.

Yeah. This is Darryl. I would 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, for example, the industry would double their capital expenditure program. We think the tubulars are in 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 six months or eight 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 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'll tell you, we're watching that pretty close and the STACK play in the Meramec 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 characterize, over the life of this field, that we would see something in the order of about 40%, roughly 40%, 45% oil. I'm 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'll tell you that the one anomaly that we've seen has been really testing the far southwest portion of the Meramec 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 of 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 Ts and dotting the Is on that deal? And is there some alternative, whereby, you would want to keep it? Thanks?.

Well, you're never done until you're done and so 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 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 sitting 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'd consider strongly sanctioning in a more normalized commodity price environment. So that has some bearing on – and the associated tariffs on that – on how that would be valued by the potential purchaser. So 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 say. It's having discussions around 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 the 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 have had previously? Thanks..

Well, our overall strategy on that, 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 of 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 had a very, very successful hedging program. In 2015, as you know, we had 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 $2.69 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 protective pullover on $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 is 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?.

Yeah, that – yeah, a little bit of change. Not a huge change; a little bit. So we're 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 from the expense cuts that you guys have made to-date, I assume, right?.

Yeah, 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 kind of totally different topic, most of the questions have been kind of asked and answered, but what are you guys seeing in the NGL markets? Obviously, you guys have a lot of leverage to that product in the STACK, especially in the whole Cana position and everything.

But, obviously, the ethane and propane prices have come back a little bit.

Can 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?.

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 un-allocate to one of the crude plays?.

David, we look at our 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 leaner portion of that property as well that would be just as commercial..

Okay. So, I get – 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.

So, speaking to the STACK Meramec, in your upside case of 14 wells per section on page eight, how many flow units or intervals are you assuming in that density pilot? Is it simply 2, as the chart indicates? And more specifically, is it the Meramec 200 and Meramec 300 intervals?.

Well, 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 Meramec 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 Meramec 200, it could be the Meramec 300, it could be the Meramec 100, whichever the primary 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..

Thanks.

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 Meramec 100 and Meramec 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 industry. We actually have an ownership position in about a hundred of those 140 data points. In fact, we have data in most of the 140 data points. We've operated about – I think about 30, 35 operations.

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

Thanks for taking my question..

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

Hey. Good morning, guys. Most of my questions were answered, but I just wanted to touch on the Delaware and Wolfcamp. It looks like appraisal drilling will be somewhat limited this year. But just kind of want to think on timing of tests there given some really positive results we've seen, particularly in Lea County.

So just wanted to get a sense on your expectations on prospectivity and results in that part of the basin? Thanks..

Jamaal, we have really focused on our work in the 2nd Bone Spring. We continue to find that the 2nd Bone Spring and now the Leonard will be the top incremental returns that we can generate in our portfolio. We really like how industry has de-risked around us, the Wolfcamp. And as you mentioned, it's come up across the 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 all hinge on what your outlook is for commodity prices going forward. And so, in the kind of the mid-cycle to low-cycle case, we've got a lot of work to do in the 2nd 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 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, just 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 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 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..

Got just one thing to quickly add to that, Dave. We talked to you 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've talked about the 90-day IPs that we're generating on our inventory. It continues to improve and out-compete all of our peer group. If you look at the trend over the last four years, we've gone from kind of 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..