Devon Energy Corp (DVN) — Q2 2016 Earnings Call Transcript

Thank you, Chrissy, and good morning, everyone. I hope you've had a chance, as always, to review our earnings release information last night and this morning. That information includes our forward-looking guidance as well as our detailed operations report. Also on the call today are Dave Hager, President and CEO; Tony Vaughn, Chief Operating Officer; Tom Mitchell, EVP and Chief Financial Officer; and a few other members of our senior management team. I would like to remind you that questions and comments on this call today will contain plans, forecasts, expectations, and estimates that are forward-looking statements under U.S. securities law. These comments and answers are subject to a number of assumptions, risks, and uncertainties, many of which are beyond our control. These statements are not guarantees of future performance, and actual results may differ materially. For a review of risk factors relating to these statements, please see our Form 10-K and subsequent 10-Q filings. And with that, I will turn it over to Dave.

Thank you, Howard, and welcome, everyone. The last several months have been very active for Devon. We've continued to deliver strong operating results from our top tier North American resource plays, and we significantly outperformed street expectations on our asset divestitures, which dramatically improved our financial strength. Overall, it was a great quarter of execution for Devon. I will touch on three key messages today: efficiency gains, the portfolio transformation, and the quality of our asset base. First, we continue to achieve significant efficiency gains across Devon's entire portfolio. Productivity from our top two franchise assets, the STACK and Delaware Basin, was once again outstanding. We commenced production on approximately 20 wells for these prolific assets during the second quarter, with 30-day rates averaging nearly 1,500 BOE per day. Not only did these high rate wells deliver excellent returns, they also exceeded our type curve expectation by a wide margin. Combined with positive base production performance across our entire portfolio, we were able to drive production above midpoint expectations for all products in the second quarter. Importantly, these productivity gains were attained with substantially lower costs. Drilling and completion costs at our U.S. resource plays have now declined by as much as 40% from peak rates, and we are now on pace to save nearly $1 billion of operating and G&A expenses in 2016. The second key takeaway is that Devon's portfolio transformation is now complete. In December of last year, we announced a bold move to materially add to our position in the STACK play with the Felix acquisition, as well as the Rockies, along with our intent to monetize non-core assets across our portfolio. Since that announcement, we have successfully integrated Felix assets into our portfolio, and the prolific new-well results from this asset continue to support our view that the STACK play is the best emerging development play in North America. We have also done a tremendous job executing on our non-core asset divestiture program. We have reached agreement to sell $3.2 billion of assets, well above the top end of our $2 billion to $3 billion guidance range, and these accretive transactions have significantly strengthened our investment-grade balance sheet. The majority of proceeds will be used for debt reduction. While there has been tremendous volatility in energy markets over the past year, I have unwavering conviction that these strategic actions were the correct long-term decisions for Devon. Finally, I want to leave you with some thoughts about the quality and depth of Devon's go-forward asset base, which we believe is unmatched in the industry. With the recent high-grading of our portfolio, we sharpened our focus on Devon's top resource plays, all concentrated in North America's best basins. Led by our world-class STACK and Delaware Basin assets, we have exposure to more than 1 million net acres and thousands of low-risk opportunities that can deliver sustainable long-term growth for Devon. Importantly, we are taking significant steps in 2016 to accelerate future development in the STACK and Delaware Basin. In the STACK, we are participating in more than 10 spacing pilots to optimize our 2017 development plans in the over-pressured oil window. In the Delaware Basin, our total reservoir access concept, otherwise known as TRAC, has future development plans in place to efficiently develop up to nine intervals of STACK pay in a given area from superpads. Looking beyond the massive opportunity set in STACK and Delaware Basin, we also have attractive investment opportunities in the Eagle Ford, Rockies, and Barnett Shale. More importantly, these high-quality assets possess the ability to generate substantial amounts of free cash flow. Outside of our formidable U.S. resource plays, our top-tier heavy oil asset in Canada provides tremendous optionality. These capital-efficient assets can produce large amounts of cash flow and also possess significant growth potential, with greater than 1 billion barrels of undeveloped resource in the economic core of the Alberta oil sands. Overall, Devon's go-forward asset base is well-balanced between scalable growth assets and top-tier cash flow generating assets. Given the quality of our go-forward asset portfolio, we have no shortage of attractive investment opportunities across our asset base. And with the success of our asset divestiture program, our strong financial position allows us to accelerate investment in these best-in-class resource plays. As we previously announced in June, we are increasing our upstream capital investment by approximately $200 million to a range of $1.1 billion to $1.3 billion in 2016. This incremental capital investment will be deployed entirely in the STACK and Delaware Basin, beginning in the third quarter. By year-end, we expect to add as many as seven operated rigs between these two areas. The annualized upstream capital spend associated with this activity at year-end is approximately $1.6 billion. While it is still too early to provide any formal targets for 2017, I can tell you that this level of investment is sufficient to generate growth in oil production and stabilize Devon's top line production profile by mid-year 2017. In summary, I am pleased with the way Devon is positioned to navigate the current environment and prosper in the future. We have a great collection of assets, an experienced team that has a track record of delivering excellent results, and have the financial capacity to efficiently convert our resource-rich opportunity set into production and cash flow. With that, I'll turn the call back to Howard.

Thanks, Dave. And before we head to Q&A, I'll take just a few moments to address one of the most often-asked questions the IR team has received since our release, and that's our production profile. As we reached our sales values on divested assets in excess of our targets, there are certain assets we haven't sold and therefore we have rolled into the Devon go-forward look. Also, the production estimates we previously issued showed a full year of the divested assets, while we have already closed several and anticipate closing the remaining assets soon. The largest component of retained assets previously in the other category are select Midland assets, which have a relatively shallow decline rate and are high margin. To be perfectly clear, we see both U.S. and Canadian production stabilizing in the fourth quarter of 2016. Our projected activity levels at year-end 2016 indicate we project top line production for our retained assets to stabilize by mid-year 2017, led by growth in U.S. oil. A key contributor to mitigating gas and NGL declines in the first half of 2017 will be the Hobson Row development in the STACK that we anticipate bringing on in early 2017. We expect to return to top line growth in the second half of 2017. Of course, these projections are predicated on an expectation that we see strengthening in commodity prices, which will allow us to add the three or four additional rigs in the fourth quarter of 2016 we disclosed in our Q2 earnings materials. Based on that level of activity at year-end, you could expect an annual spend of somewhere around $1.6 billion. I hope this helps, and of course, if you have more detailed modeling questions, Scott, Chris, or I are happy to visit with you after the call. With that, and heading to Q&A, I'd ask you to please limit yourself to one question and an associated follow-up.

Good morning, and thanks for taking my questions.

Morning, Pearce.

Morning, Pearce.

Howard, thanks for that color just now on the three rigs and then potentially on the additions and then potentially going to the seven rigs. Dave, as you look at the current forward strip to year-end and then look out to next year's pricing, do you think if those prices hold, that you would add those four rigs, or would you need to see a little bit higher price to do that?

No – yeah, great question, Pearce. We see that our cash flow at the current strip being approximately that, that we could add these rigs and live within cash flow. It varies, obviously, a little bit day-to-day, and we're in a little bit of a downturn right now. But we're approximately at the point where we'll be cash flow neutral. So we could add those rigs.

Thank you. And then my follow-up is you highlighted on the 2017 guidance, or preliminary 2017 guidance, and I know it's not formalized at this point. But, on oil production, would you be able to hold Q4 2016 oil production flat and then grow from there? I mean, I'm trying to get a sense of what the – if you spent that $1.6 billion, what the oil production profile would look like, or would it continue to decline from the Q4 2016 levels until the middle part of next year and then start to come back up?

No. We would essentially stabilize production at the Q4 levels, Q4 2016 levels, and then later in the year, it would start inclining, later in 2017.

And that'd be stabilizing oil production at Q4 levels, but not total production?

That's correct. That is oil production. As Howard said, we would stabilize the BOEs around mid-year 2017. So we'd still experience some decline. Where we're not investing in gas particularly, and to a lesser degree, the NGLs, then it would be stabilized by mid-year 2017 and then start an incline on the BOEs as well at the back half of 2017, and we'd be exiting at a significantly higher rate than mid-year.

Excellent. Thank you so much, Dave.

Yes.

Yeah. My first question, Dave, is to ask you about the maintenance CapEx number. You'd previously set about a $2 billion number to keep production flat on a BOE basis. Now you're signaling $1.6 billion. I was wondering if you could maybe highlight what's driven that pretty meaningful reduction in maintenance CapEx as we think about 2017.

Yeah, great question on that, Arun. We're continuing to drive efficiencies in our business, internal efficiencies. We've talked about the 40% reduction in drilling and completion costs of about 50%-50% between lower service costs and internal efficiencies. I can tell you as we sit here today, we're finding even more internal efficiencies that are continuing to drive that maintenance capital lower, as well as the fact that we're exceeding the type curves on our wells. You combine the cost savings we're still finding with the fact that our wells – we're in the best parts of the best plays. And they're exceeding our expectations. So that's continuing to drive the maintenance capital down.

Great. And my follow-up, Dave, is on a pro forma basis, $4.6 billion in cash. It sounded like from the operations report, you'll use roughly $2 billion or so for debt reduction and $1 billion of the $3.2 billion in proceeds could be reinvested. Would you feel comfortable, for example, in 2017, if you feel good about oil in the low to mid-$50s of outspending by $1 billion or so to take some of these proceeds, just given that you have so much cash on the balance sheet?

Well, we do think that – and we do have the other cash on the balance sheet from essentially the equity offering. We do feel that it's very important to maintain our investment-grade rating. And probably longer term, we would still look at using some of those proceeds to pay down debt. So we are at this point thinking that we want to live within cash flow. We said we'd start adding back activity if we had confidence prices were going to be somewhere around $50. We have added back activity, or we're planning – we've added back some. We plan to add back more. If we do see prices sustain over $50, and gas prices, actually – the recovery in gas has helped out significantly as well with our cash flow. If we see gas prices sustain near the levels where they are now, we may be able to even add a little bit more activity in 2017, but that would be living within cash flow, though. So we don't see a significant cash flow outspend.

Great. Thank you very much.

Two type curve questions, if I may. Obviously, let's start with the Bone Springs; you talk about some of the wells 50% ahead, Leonard 70% ahead. We just had OXY's presentation showing that 180-day cumes, I think from memory, are double on all their designs. So maybe just talk through what's the constraint on perhaps raising the overall type curve. It might just be that across the inventory you still have down-spacing, tests, et cetera. And then I have a question on the STACK.

Ed, this is Tony Vaughn here, and I think you hit it right, is the activity and the number of new completions that we have brought on of late have been fairly small. But we're extremely pleased with all the performance that we have, especially in the Leonard. Not only are all the well results that we're making public in the Leonard well above our type curve; the industry around us is really experiencing the same thing. We'll make these type curve adjustments both here and in STACK just as we get a little bit more comfortable with that and get a few more reps behind us. The operational performance of our new activity in both the Delaware and the STACK is well above our expectations on our current type curves.

Okay. And then on the STACK, what was the average lateral length of the Q2 results? Because obviously, again, exceeding type curve, but if you go to longer laterals, those should be more capital efficient.

I think you're exactly right. Historically, industry has – we've got about 200 wells in the STACK play to date. About 60% of those are the long laterals on our well count, Ed. We have about – just under 50 wells that we operate, and we have about – just under 50% of those are long laterals. Difficult to put an arithmetic average on the full population of that, but it's probably somewhere around 6,000, 6,500 feet. A lot of the early wells that were drilled were in the appraisal mindset. They were also in the lease saving mindset. Now that we're getting a lot of that information behind us, being more comfortable with the subsurface, I think Devon is really looking forward to optimizing our completions and our lateral lengths. The design that we're going forward is to use as many of the long laterals as possible.

Yeah, and Ed, I'd just add, I think what Tony's saying here is a lot of the 10,000-footers we've drilled here were probably not as productive as we'd anticipate 10,000-foot laterals to be in the future. Some of those are wells that were drilled by Felix without the benefits of 3-D. Early completion designs were not what we feel the optimum design is. So even though there were some 10,000-footers in the mix, they were not of the quality we would anticipate from a go-forward basis.

Thank you.

Yes. Good morning, guys, and thanks for taking my questions. Just very quickly looking at 2017, you outlined the $1.6 billion bogey, if you will, on spending. But what sort of obligations do you have for spending above that $1.6 billion? Just trying to think about how much that could go up or down as you look to stay within cash flow.

Well, we're totally flexible on that, Pete. We don't have any obligations. I think that's one of the great attributes of Devon, is we have essentially all of our acreage held by production. We have a minor amount in the Felix acquisition where we need to have some activity. But we're going to have way more activity than is required to get all our acreage held by production. We don't have any, obviously, long-term projects going on in the company, so we are totally flexible, as cash flow presents itself, as to ramping up activity. And of course, we don't like to think about it as much, but if prices do retreat, we have the flexibility to decrease activity as well. It is strictly driven by – we have the projects. We have as good of projects, we think, as anybody in the industry; it's just a matter of what cash flow is available to put against those projects.

Okay. One thing you guys have done a great job in the past of is kind of stack-ranking your returns of your given plays here. As the STACK has continued to look extremely good, the Delaware Basin looks extremely good, would you mind just dusting that off and reminding us where they all stand in order of preference? And maybe, ultimately, where does the PRB come into the mix looking into 2017 as you've grown to have a very big position there but very little activity?

Pete, I think nothing's really changed there. If you look at the returns on a strip basis, we really haven't commented on the absolute number of that. The returns that we see in the Parkman, the Delaware, the Eagle Ford, and the STACK play are all comparable to each other. If you look at the sensitivity to the number of locations that we have available, that does change. If you look in the Parkman, we've done some of the best return work we've done there, but the inventory is not as deep and as robust as it is in the Delaware and the STACK play. So really all four of those plays are ones that we've got the flexibility and the ability to drive value for, which presents an opportunity for us, I think, to prosecute and to understand the subsurface even better while still getting a lot of meaningful and competitive returns.

Of the four, Pete, the Powder River Basin is the most sensitive to oil prices, because it's about 90% light oil. When we were – earlier in the year after we did the acquisition, with prices down mid-$30s or so it wasn't competing for capital. As we get back over $50 a barrel, the economics on that improve dramatically because of the high oil cuts there. That's what puts it into the – it's very sensitive, but it puts us back up into one of the top-tier plays when we get a $50-plus environment.

Great. Thanks, Dave, and thanks, Tony, as well.

Not as deep in inventory. But still, good economics at the well level.

Great. Thank you.

Good morning, Dave, and to the rest of your team there.

Hi, Charles.

Thank you. I apologize if I'm belaboring this point a bit, but I'd like to just see if I could distill some of the comments you've made on this call. The $1.6 billion number, that was really useful for what you could do, but I'd like to try to understand or make sure I understand what really is driving your appetite for what you actually would choose to do. I think I heard you say you're going to spend within cash flow regardless of where the commodity prices go. But is there a scenario where you just wouldn't have the appetite to drill more in the case where – or you wouldn't have an appetite to add rigs if the commodity price went down?

Well, we look at – let me clarify. There's really two things that we look at when we determine our capital allocation and the levels of capital. One would be the returns on – at the project level. We compare projects across the entire company, take into account any sort of operational considerations or limitations, and then we fund the highest-return projects across the company. We do that to the extent that we can live within cash flow. The second step of the process is what our cash flow is going to be. I've said the $1.6 billion is – and prices are moving around every day, so you can't – you can rerun these numbers every day and get a slightly different answer. It is approximately the level at which we can live within cash flow in 2017 at the current strip and fund the top tier projects that we have identified with the nine rigs that we could be adding by the end of the year. We plan to add up to that nine-rig level unless we see a significant change in commodity prices between now and then.

Right. That's helpful, Dave. I imagine these moves in commodity prices are even more fun for you guys than they are for us.

We're having a barrel of laughs.

If I could ask a question on the Delaware Basin, you guys introduced this total reservoir access concept. Does that – that's new this quarter, but one of the things that I think has been a challenge particularly, as I understand, in your part of the Delaware Basin has been extending the standard-length 5,000-foot laterals out to 10,000-foot laterals. Is that a correct perception that it's harder than other places to get to the 10,000-foot laterals? And does that interact or play some part in your TRAC concept?

Charles, about a third of our position or our footprint in the Delaware Basin will accommodate the long laterals. It's a little bit tougher to put those together as you move north in Lea and Eddy County in our footprint, but in the southern portion of this where this new superpad or TRAC concept would be utilized in 2017, it's a little easier to do that. What we're trying to describe here is a concept as you think about having all of the stacked pays that we have both here and in the STACK asset in Oklahoma, there will be a more creative and efficient way to develop our surface facilities. We're walking into this with this concept. It provides us a lot of flexibility as we grow. It also allows us to have flexibility as the business environment changes. For the most part, we're going to, through the permitting process, to achieve or get approval for more of a field development concept. We'll be left to get individual APDs by well as we choose to develop that. You're right about our footprint. It's a little bit less contiguous on the north end of our position. But in the south end of Lea and Eddy, it should be very well suited for this type of concept.

The other thing that's great about it, too, Charles, is if you – we showed it on the maps that we put it into our investor presentations – particularly in the southern parts of Lea and Eddy counties, we have so many prospective zones. As we said, we have up to nine prospective zones between the Delaware Sands, the Bone Spring, Leonard, and the Wolfcamp. We're still doing appraisal work determining how many wells per section in an individual zone and how many of these zones in a vertical sense also can be developed in any one geographic location. The numbers you start seeing can sometimes boggle the mind. We're hesitant to put the numbers out there until we finish more appraisal work. But there could be a tremendous amount of resource that we're developing on each section out there. What necessitated this superpad concept is how are you actually going to develop that resource? It's a really exciting future, both in the Delaware Basin and in the STACK play because of this.

That's helpful color, Tony and Dave. I appreciate it.

Thanks. Thanks, everybody. Good morning.

Good morning, Doug.

Dave, I want to make sure we're understanding this maintenance capital issue right, because the numbers sound – if my math is right, you're basically indicating you can hold production flat at an oil price in the mid to high $40s. I've been checking through all the numbers. Is that directionally where you're headed?

Well -

Go ahead. I was going to tell you how I get there, but -

Yeah, I think that may be a little bit lower than where we're at. I'm struggling a little bit to get into the details of that right now.

Let me walk you through very quickly, Dave, how I get there.

Okay.

Previously, you said $40 was your CapEx breakeven this year. But that included the contribution from Access of about $800 million. Your sensitivity is about $80 million per dollar. Previously, you had said that you would hold flat at about $60. So when I work through all those numbers, it kind of implies $1.6 billion is somewhere in the mid to high $40s.

Yeah, I think the big thing that's changed, off the top of my head here, Doug, is gas prices have gone up significantly. That has provided significant incremental cash flow to us, as well as some improvement on the NGL side. It's probably less a product of oil prices – the breakeven – maintenance capital on oil prices going down as it is the fact that our assumptions around what gas prices we can achieve, along with the oil, has allowed higher cash flow to keep production flat.

That makes a ton of sense. Okay. Thanks for clarifying. My follow-up is really going back to the STACK and the move to 10,000-foot wells. Obviously, you've partnered with Continental on a bunch of those wells. What do you think the costs are that you can deliver these wells at? And I guess this is a related question; what's holding you back from moving up your type curve, given what you're seeing from others in the play?

Doug, we're finding that the well costs vary quite dramatically from the shallow eastern portion of the field all the way across to the southwest portion of where Continental is. We're finding that we can drill the wells for about $5.5 million per well with the two-string design on the eastern half of the field. If we have to add a third string as we go past kind of a dividing line that separates the east from the west, add that third string, it adds about $1 million. As we go from a 5,000-foot lateral up to a 10,000-foot lateral, that's about $1 million to $1.5 million incremental on top of that. That might give you a range in the cost as we work across that field. We continue to see positive results in our well performance from the oily section in the northeast to the little bit – the gassier, more volatile as you move into the central portion of the field. When you put all the attributes together, we still believe we are in the heart of the high-return portion of the field. We think all those attributes really lead to what will be the most commercial development going forward for all the competitors there.

And, Tony, just on the type curve, is it just a matter of waiting on more well results?

It is. From an operational perspective, it's nice to see almost – virtually every well result that we have is not in the type curve. It's well above the type curve. We're going to modify that with performance. We have been pleasantly pleased. A lot of variables are going into that, but I've got to tell you, the predictability of the results is really narrow. We think the P10 to P90 range in the 90-day IP is about 2.4, which is extremely tight for a fairly young play. The predictability of the play is unusually good compared to a lot of the resource plays that we've been involved in.

Appreciate the answers, guys. Thank you.

Yeah, thanks. I was wondering if I could ask a question on the STACK. Obviously, you highlight the great performance in the well results you've had in addition to your massive acreage position. You all are producing around 90,000 a day there, but when you step back and look at it – and I'm assuming you've kind of generalized some of the numbers – but where do you think that ultimately could grow to? How big is the prize here on your acreage there?

Scott, I think when we did the acquisition analysis, we tried to visualize what that would look like as well. We think with our position, and the Woodford continues to expand. The well performance gets larger. We're seeing more resource potential in the Meramec and the Osage. We believe that we can probably push up north of 150,000 towards 200,000 BOEs per day as all these zones continue to be de-risked and incorporated into our development plans. A lot of that, Scott, is contingent on the commodity price environment that we're in and the pace of activity that we can prosecute that large resource base.

Okay. That's great color. And my follow-up is on the Eagle Ford. Obviously getting a lot of less attention right now. I'm curious on where it could fit into your long-term portfolio, especially considering your operating partner appears to be de-emphasizing onshore development at this point. How do you look at that? And if I could add a question to that, if your partner decided to, let's say, exit the Eagle Ford, what would your reaction be? What would Devon do?

Well, that's – appreciate the question, Scott. I don't think it's probably appropriate for us to comment on hypothetical situations there. But the Eagle Ford, we've had some tremendous results. We have a position there that is really like we want to do in all of our plays. It's in the best of one of the best plays in onshore North America. If you look at the historical well results that we've delivered out there, we have a large proportion of the best wells that have been drilled in the play. We certainly have liked our position. Right now, we're just in a position where, given the capital constraints that we had earlier in the year, ourselves and our partner, we decreased drilling activity significantly. Along with that, then, the completion activity. We thought we were going to resume completion activity here in Q3. It's been pushed back about one quarter now. That's a very short-term challenge. But it's going to help us a little bit in 2017 as some of those volumes get pushed out of 2016 into 2017. I don't think it's a significant event towards the long-term strategy of the Eagle Ford. We still see some high-return type opportunities in the Eagle Ford. We're maturing our way through the best part of the inventory right now. We see some upside from the diamond pattern we described in the operations report, which was really staggered laterals in the lower Eagle Ford, along with an upside in the upper Eagle Ford. We think there's some upside that exists to the resource out there. Although it doesn't have the – and we knew it at the time of the acquisition – it just doesn't have the running room that we see now in the Delaware and the STACK play. But we still like it very much, and we'll see how things develop beyond that.

I appreciate the response. Thanks.

Hey. Good afternoon, guys, and thanks always for the color.

Sure.

My first question is a follow-up on the Meramec. Given your understanding and the success of the Alba pad, what do you guys think is the ultimate limit here for development spacing? And what size pilot program will you need to change your development assumptions off of four? Should we expect that in those 4Q results, given your industry pilots?

Evan, we've commented that we were testing update wells per section in a single interval. We're getting a lot of good data from the pilots now, so we've seen results on the Born Free, which gave us confidence that we can prosecute the zones on top of each other with no problem. The Alma spacing test helped us understand that five wells per section is not dense enough, even in today's commodity price environment. We're getting some information in now on the pump house, which is seven wells per section, and we'll be able to give you a little bit more feel for that. One of the pilots we got some early data on was what we called the Skipper pilot, which was an eight well per section. We highly encourage that eight wells will work in the right commodity price environment. It will probably work as technology continues to improve and we can improve our frac or completion designs and maintain a more complex near-wellbore frac. The four we initially commented on, when we did the acquisition, is light. We think we're at least at six or north of that right now. The pilots are coming in. We'll have about another three pilots showing us some information in Q3. Some more in the first quarter of 2017. We're starting to get comfortable with the areas that we're going into a full development on. We'll use this TRAC concept in the STACK development as well. We think we'll have the ability to prosecute up to roughly 27 wells in a section as all these zones continue to work. The play's working really well, and the pilot data is all positive and leading us towards our development plan.

That's all really helpful information. My second question, you guys significantly increased your Barnett refrac type curve. Should we read this as the play is progressing closer to the point where you'll be willing to monetize a portion of your acreage position, given that you can get paid for that refrac potential?

Well, we like our position. As we said, our transformation is complete. We like our portfolio the way it looks right now. We're always – my kind of flippant expression in all this is we like all our assets, but we're not in love with any of them. So we certainly are – we like where we are with everything. We have no current plans to do anything with the Barnett or any of our other assets, but that's not to say we aren't always thinking at the same time. If there's some way that we can improve our results as a company, we'll think about it. I can tell you there's nothing right now that says we're going to divest. No current plans around divestiture or anything in the Barnett.

Thanks, guys. Good update today.

Yeah, while you're listening in, Evan, I took a look at your write-up this morning and just wanted to make sure I clarify a couple of things in there. One is the – I think you heard me make some comments there about the predictability of our results in the STACK. While it's not going to be uniform across the play, it is extremely predictable. There's a note about the debate regarding our acreage position and whether or not it falls in the overpressured window. There may have been an impression that there's a north-south line, to the east of that it's underpressure and to the west of that it's overpressure. That's not the case. Our subsurface data understand, and if you look in the isobar map, you can clearly see that the far northeast is normal pressure, but it quickly goes into about 0.5 psi per foot and gradually moves into about 0.7, 0.75 psi per foot to the southwest. Just wanted to clear it up. In our mind, there's no debate about whether or not we're in the overpressure window.

No, that's helpful, and I did pick up on your predictability comments early in the call, and I appreciate that.

Hi, morning. Just along those lines, just in the ops stuff that you talked a little bit about the Meramec and some – I guess you used the word 'variability.' So that's what I jumped on. But can you – or maybe that was my word – but can you just talk about the Meramec? I know you've alluded to it a little bit; can you give us more color as to what you're referring to in the ops update?

I'm not sure what your specific question is, David. Could you repeat it?

Yeah, just – I pulled up to the page. It says IP and well costs can vary significantly across the play. We've heard others talk about the variability of the Meramec. Maybe the better question is can you talk about the Meramec, how you see it playing out across the play?

What Tony is trying to say here – I'll try my words – is that there is variability, but it's predictable variability. You aren't going to necessarily get the same well results across the entire play, but the variability of what you would expect in a given part of the play is very low given the phase of maturity that we're in, in the play overall.

Yeah, Dave, just to elaborate, as you characterize the reservoir, there's a lot of variation in the reservoir thickness by zone. There's a lot of difference in the fluid content as you move from northeast to southwest. The bottomhole pressure changes, as I just mentioned, from east to west. There's a lot of variation in that. The actual total depth to get the wells down varies from the east to the west dramatically. But overall, most of the results we see in the core of the field, especially in our footprint, have extremely tight predictability.

Okay. No, that's helpful. And then back to the Barnett. If you start thinking about $3.25 gas or $3.50 gas – or what's the magic level at which, just on a returns basis, that play would start to compete with capital as far as you think about 2017 and 2018?

It's got commercial returns today. As we have done all of our vertical refracs, we know those are about at cost of capital, if not just a bit above. The horizontal refracs are getting much more predictable, and we know those are at cost of capital and above. It's more of a question, David, how competitive that is in the overall portfolio. As commodity prices increase, a lot of our other opportunities get more attractive as well. But that's a real opportunity for the company going forward in the future. The materiality of that is we got about 3,000 wells out there that have the ability for us to go back into them.

Okay. Sorry – I didn't mean to interrupt you. So just to clarify when you start talking, 2017 right now, the strip's at $3.15, $3.16. At that level, you're getting commerciality?

We are. We can get cost of capital returns.

Well above cost of capital returns at those kind of prices. The challenge is trying to compete on a super team here. We got a bunch of all-stars in here, and it's a pretty good player, but it's not going to see the ball as much as – we've got the Golden State problem going here.

Thanks for the re-frame. I appreciate it.

Yeah, hi. Just have a question on completion designs. One, can you define your hybrid completion? And, two, with the STACK and also the Woodford, you're putting in a lot more sand. Do you have any sense of what you think the economic limit is for how much profit you can put in?

I can give you a feel. I'll remind us of an experience we had in mid-2014, when we started increasing the sand loads in our Delaware completions. We ran up to – we went from about 600 pounds per lateral foot in early 2014 up to about 3,000 pounds per lateral foot through 2015. This information gave us a good understanding of the performance change in that design, but also helped us understand the matrix associated with the commodity price environment. We've backed off in the Delaware from that 3,000 pounds per lateral foot. We think we can get the most commercial returns in the current business environment done at about 1,500 to 2,000. It varies across the field. If you move over into the Anadarko Basin, we're using a slick water job in our Woodford type work, and we're continuing to increase our proppant loads there. We're up to about 2,000 pounds per lateral foot. After drilling and completing over 800 wells, this last large pad we brought on had the best results we've ever had in the Cana-Woodford play. In the STACK play right now, we're using a hybrid type job, so we've got a little bit of a gel with the total fluid being more dominated with slick water. We're increasing our sand loads there up to about 2,600 to 2,750 pounds per lateral foot and enjoying increasing success there. We're getting a lot of this information, and we're trying to make the highest return per well, not necessarily just to pump large jobs.

Does the hybrid take longer to clean up?

I don't believe it does, John. We'd have to get a little bit more feel from our technical guys, but I think our hybrid fluids are breaking with temperature, and I don't think there's a problem there. So I haven't heard of that complaint.

Great. Thank you.

Great. Thanks, gentlemen. Maybe a couple smaller ones, could you talk about the infrastructure buildout in STACK in the Permian, how it matches up with the potential rig count additions in the second half of 2016 and 2017? Any potential limitations or bottleneck as you look forward over the next couple of years?

If you start in the Delaware, one of the things that has changed over the last eight to twelve months, Ryan, has been the buildout of the infrastructure. The majority of our work now, we have power grid systems to all our wells. We also have the majority of our fluid being transported by pipe. The infrastructure we built out in the Delaware Basin is now complete. There are no local takeaway issues associated with our work that we anticipate doing in the next couple years. The Delaware now has caught up to the infrastructure, the returns are good, and the cost to drill and complete wells is down. In the STACK play, the Cana-Woodford part of that is very well developed out. We have a great water system there. We're building out our concept for the Meramec play right now. That's in the design phase. We're working very closely with our midstream partner, EnLink, to understand what long-term takeaway opportunities might be. We don't believe that's a consideration for our development until probably 2019. We're working toward that, and we'll have the appropriate solution identified. The partnership with EnLink is providing a lot of value across our asset base.

That's perfect. Thanks. And then maybe one logical follow-up on that, you've seen significant downward pressure in both LOE and G&A unit cost over the past 18 months. How much more room do you have to run there in terms of pushing costs lower in the Permian? You've gone from kind of $15 to $8 a barrel over the past six quarters. Can that go to $6 or $4 or further? Any thoughts on what we should expect over the next 12-plus months?

I'll start off, then hand it over to Tony. On the G&A side, the bulk of the reductions we've seen there were related to reductions in head count, and we're just now starting to see all that flow through the financials. We have the staffing in place to execute the program now, and we could handle somewhat higher levels of activity as well, up to around 15 to 20 operated rigs. We certainly don't see a reduction in head count anymore, as long as we keep on this path to recovery we are right now. We have the staffing in place to execute our capital program. I'll turn it over to Tony to talk a little bit more on the LOE and where we may be able to go.

Ryan, there's a real passionate push in the company right now to manage cost. While we don't have much of a capital program in comparison to what we had in 2014, a lot of our attention here in the last twelve months has really been towards managing our base business. We’ve stood up an operations excellence group that has done a great job facilitating this effort to drive costs down. All our men and women in the field locations are really doing a good job participating with us. As we built out our water handling capacity across all our fields, we have more of our water going through pipe. We've released close to 300 rental generators just in the Delaware Basin alone. We're doing thoughtful work there. We have a supply chain group that's closely linked with our operating team, reducing compression costs through renegotiating some contracts and doing the same thing for chemicals. We're working on the water we have to transport and handle, where work does cost in. We have a great, focused effort going. We believe a lot of wins are still left to get just through attention to detail and through designing changes and managing our business even better than we have in the past.

Great. Thank you.

Well, we appreciate everyone's attention. We apologize we couldn't get to everybody in the hour, but happy to follow up with you after this. If we can do anything else for you, please let us know, and have a great day.