Diamondback Energy Inc (FANG) 2017 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Diamondback Energy Fourth Quarter 2017 Earnings Conference Call. (Operator Instructions) As a reminder, this conference is being recorded.

I would now like to introduce your host for today's conference, Mr. Adam Lawlis, Director, Investor Relations. Sir, you may begin.

Thank you, Carlin. Good morning, and welcome to Diamondback Energy's Fourth Quarter 2017 Conference Call. During our call today, we will reference an updated investor presentation, which can be found on Diamondback's website.

Representing Diamondback today are Travis Stice, CEO; Mike Hollis, President and COO; and Tracy Dick, CFO.

During the conference call, the participants may make certain forward-looking statements relating to the company's financial condition, results of operations, plans, objectives, future performance and businesses. We caution you that actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found on the company's filings with the SEC.

In addition, we will make reference to certain non-GAAP measures. The reconciliations with the appropriate GAAP measures can be found on our earnings release issued yesterday afternoon.

I'll now turn the call over to Travis Stice.

Thank you, Adam. Welcome, everyone, and thank you for listening to Diamondback's fourth quarter 2017 conference call.

2017 was a transformational year for Diamondback. The company grew production 84% year-over-year within operating cash flow, decreased cash costs 11% year-over-year, more than doubled EBITDA and generated a return on average capital employed of 10.5% for the year. We successfully integrated multiple acquisitions that doubled our asset base and continued to execute a best-in-class metrics on a significantly larger capital plan.

Looking ahead to 2018, our strategy has not changed. We will continue to grow production within cash flow at industry-leading rates with best-in-class cash margins and cost control. Our 2018 budget assumes 40% production growth within cash flow at today's commodity prices with the flexibly to accelerate should commodity price allow.

Capital discipline remains central to our company's philosophy. Our long-term plan is to continue to increase our rig count to about 16 rigs within cash flow and then begin generating significant free cash. We believe at a certain point in the company's life cycle, it should generate a return on capital in excess of its cost of capital and subsequently return capital to its stakeholders.

Therefore, as a sign of appreciation for helping Diamondback become the company it is today, we are taking the first step in return of capital by instituting a $0.50 annual dividend to be paid quarterly beginning in the first quarter of 2018. Again, this is a first step for the company. We will continue to accelerate our activity within cash flow and have significant cushion to protect and grow this dividend as well as assess other avenues of capital return.

With these comments now complete, I'll turn the call over to Mike.

Thank you, Travis. We are operating 10 rigs today, 6 in the Midland Basin and 4 in the Southern Delaware Basin as well as operating 5 dedicated completion crews.

We plan to add an 11th rig late in the first quarter of 2018 to begin work in the Southern Delaware Basin. This year, we plan to run between 10 and 12 rigs, and as always, we'll continue to assess accelerating activity as commodity price allows.

Turning to Slide 8. Diamondback generated $928 million of EBITDA in 2017 on a total capital spend of $861 million. As shown on this page, capital discipline has always been a core philosophy of this company, and we have differentially grown production within cash flow over the last 3 years.

Slide 9 shows our total completed lateral footage and average lateral length over time as well as the number of wells drilled and completed each quarter. Diamondback continues to maximize efficiencies by drilling and completing longer wells with our average lateral length completed up 60% since the beginning of 2015 to an average of over 10,000 feet last quarter.

Turning ahead to Slide 13. We have new data from multiple well results across our Southern Delaware Basin assets, including longer-aged data from the Warlander well as well as early-time data on our first Wolfcamp B test in the Southern Delaware Basin. We expect to run 4 or 5 rigs in the Southern Delaware Basin in 2018. While the majority of our capital will focus on the Wolfcamp A, we also plan to test other zones such as of the second Bone Spring in Pecos County, the third Bone Spring in Reeves County as well as the Wolfcamp B in this coming year.

Our infrastructure development continues to advance in the Delaware Basin with all oil gathering systems expected to be complete in the coming quarter. Electrification, saltwater disposal and freshwater systems continue to be developed as we accelerate activity in the area.

Turning to the Midland Basin. We currently are running 6 rigs with plans to maintain this cadence in the near term. Slide 15 shows the continued impressive performance from our assets with wells in each area continuing to exceed expectations in reserve, audit or type curves.

On Slide 16, we introduced our Limelight Prospect. We have recently secured 19,000 net acres in Ector and Crane Counties, focused on an emerging Mississippian oil play. We plan to begin our initial appraisal of the acreage this year.

A core Diamondback belief is that the lowest cost operator wins. This is even more prominent as we have now moved into a true manufacturing mode. Over the past year, we have added to our already extraordinary staff and built several strategic business partnerships to allow us to operate in the years to come in an efficient, cost-effective manner.

With these comments now complete, I'll turn the call over to Tracy.

Thank you, Mike. Diamondback's fourth quarter 2017 net income was $1.16 per diluted share, and our adjusted net income was $1.56. Our adjusted EBITDA for the quarter was $302 million, up 30% quarter-over-quarter with cash operating cost of $8.28 per BOE.

During the quarter, Diamondback spent $246 million on drilling, completion and nonoperated properties and $61 million on infrastructure.

For the full year, we generated $28 million of free cash flow excluding acquisitions.

As shown on Slide 19, Diamondback's ended the fourth quarter of 2017 with a net debt to Q4 annualized adjusted EBITDA ratio of 1.2x and $1 billion of liquidity pro forma for our January tack-on to our senior notes due 2025. These proceeds were used to pay down a portion of our borrowings under our revolving credit facility.

Our full year 2018 production guidance of 108,000 to 116,000 BOE a day implies 40% year-over-year production growth within cash flow on an estimated $1.3 billion to $1.5 billion capital plan, of which $125 million $175 million is dedicated to our infrastructure.

With these comments complete, I'll turn the call back over to Travis.

Thank you, Tracy. Diamondback was able to execute on a transformational year as a result of our continued commitment to execution and low-cost operations. We believe the theme entering 2018 is no different from the theme throughout 2017, namely, that the best execution at the lowest cost in the commodity-based business wins.

Operator, please open the line for questions.

(Operator Instructions) And our first question is from the line of John Nelson with Goldman Sachs.

Travis, FANG had previously guided investors to expect the return of capital to begin once you achieve the optimal rig count for your asset base, which you're, I guess, now talking about 16 below where you expect to be over the course of this year. Can you just speak to the decision to pull back timing forward and if it's a sign that you're worried at the marginal dollar return? And this environment could be tighter because of service industry tightness or midstream takeaway concerns?

Yes, John, that's a good comment. We always want to grow at a rate that allows us to continue our cost leadership position. And we're not really changing the institution of the dividend, we're not changing our strategy to get to that 16 to 18 rigs, we just want to make sure we do so at the best -- most efficient capital rate that we can do so. I mean, if you go back in our history, we built this company through really an acquire-and-support strategy and we had tremendous support through our shareholders while we built the company. And we created a return of capital employed this year -- or rather in 2017 that was already in excess of our weighted average cost of capital, and we just believe that our next step in our company's evolution is a true return of capital to our shareholders by initiating a dividend. It's really a first step towards a larger capital return program once we've reached that kind of 16- to 18-rig cadence.

Great. And so should we think about the growth of that dividend at a pace faster than that rig count in the short term? Or is it just dependent more on kind of the commodity price environment?

Yes, we're certainly always going to be range-bound by oil price. But look, we're going to -- that's a board decision, but we'll talk about the board as to exactly how that dividend is going to grow. We just think it's important right now that we just -- that we commit to initiating the dividend and we commit to making that thing grow over time, not only get backed into a corner exactly what the dividend rate's going to grow at.

Fair enough. And given you all are kind of on the ground in Midland, [my thought of] I was wondering if you can comment on how you're seeing the labor environment currently, how tight things potentially are and if there is any concerns you can have for industry labor force over the first half of '18?

Yes. John, specifically, with boots on the ground out here in the Permian, anytime you see a cycle in oil price, which we've seen over the last 3 years, activity levels increase, rig count increase, all the ancillary businesses that support those rigs, they increase and it does create pressures. And I think that's one of the reasons pressures on human capital and pressures on operator capital and that's one of the reasons that we signaled a slightly higher CapEx this year is because we're seeing a tightness in some of these service lines. The typical culprits are [line slashes] to rigs and pressure pumping equipment. And while we have seen some increases certainly through 2017, there's another 40% of the business lines that really hadn't been able to generate much returns over the last 3 years and that's what we're starting to see also is that side of the business that's trying to rebuild their business to respond to this activity level rebuild their working capital and get their balance sheet in shape, that's what we're also seeing. So if commodity price rolls back over, we certainly expect service costs to halt the increase or maybe roll back over. And we know that there's a lot of equipment that's been built and coming online midyear, but we just thought it was prudent for our investors to know how we're thinking about the business on the 14th day of February.

That's helpful. And then just 1 housekeeping item, I'm not sure if I missed. Mike said there was a timing expectation on wells in the new Ector County prospect or the number of wells you guys anticipate to drill this year?

Yes. We'll update the market more later on. We're going to -- we're working on assessment, we're doing the technical work right now before we put the drill bit in the ground, but we'll update the market as soon as we have meaningful information.

And our next question comes from the line of Neal Dingmann with SunTrust.

Travis, question for you or the guys. Looking at Slide 12, could you talk about -- the one that talks about your inventory strengths, could you talk a bit on that, about how you all think about your inventory given you tend to have, to me, among some of the more conservative spacing out there. So I guess my overall question is on the bottom, you mentioned 38 -- over 3,800 gross locations, is that still assuming just on your conservative spacing, you still have that type of locations? And obviously, that could improve based on if you might downspace just slightly?

Yes. Certainly downspace represents an upside to our gross location count. You've heard us consistently communicate conservatism in the way that we lay these spacing assumptions out. The other thing that could impact gross locations as well is as you've seen over the last several years, we've continued to increase the lateral lengths, so we're still completing as many lateral feet as we originally had in our inventory. But the fact that we're drilling, in some cases like we reported now, over 13,000-foot laterals, those have an impact on the inventory. I still think it's very prudent to be conservative in the way that you communicate the number of locations that are available to be developed. And what I really hope, Neal, is that we're kind of migrating as an industry away from people counting locations and trying to do the NAV work-up and increasing stock price and really focus on that manufacturing process and that conversion of rock into cash flow at the most efficient margins, which is where Diamondback has tried to move that commentary.

Okay. No, I guess, I'd be remised if I didn't ask you a bit about M&A. And maybe, specifically with M&A, what type of deals are out there? And how large are the inventory deals that are still out there in the Permian? I just -- again, we haven't seen anything too much out of you or the rest of the group in a bit, so I'm just kind of curious any comments you make there.

Yes, of course, Neal, we don't talk about ongoing M&A. But just philosophically, the fact that you've not seen any trades occur really very, very recently, really much through 2017, really talks to the lack of true quality acreage that's out there to be added. And somewhat, from Diamondback's perspective, it's a curse or blessings because any M&A activity that we engage in, it has to be immediately competitive for capital within our own portfolio. And we've got such a strong portfolio, there's just not a good cross-section of assets that kind of fits in that top quartile of Diamondback's portfolio.

Okay. And one last housekeeping maybe for you or Tracy. Just on that CapEx that you put out there for the year, is that -- could you just talk about it. Is that going to be relatively linear? Or is there any kind of color that you all can give around that?

It's pretty linear, Neal. We're adding rig 11 here probably towards the end of Q1 and we don't anticipate a major boost after that. So a fairly linear spend throughout the year.

Our next question comes from the line of Drew Venker with Morgan Stanley.

Travis, with the return of capital starting a bit earlier than I think most people on The Street were expecting, is the appetite for acquisitions deemphasized? Or are those two related? Or how do you think about that?

Yes, there's really no relationship between our M&A strategy and our dividends because when we sit behind closed doors and talk about M&A opportunities, it's always about how can we do a smart deal that can generate differentiated returns to our investors and do so creatively, and the fact that we've instituted a dividend really doesn't change that strategy. We're still looking to do smart deals and accretive deals.

Okay. And Travis, as the business matures, do you foresee any change in the philosophy of how you fund acquisitions from primarily equity funding to cash-funded acquisitions over time? Or is that something more near term? Or has that even crossed your mind?

Yes, that's sort of a board discussion. But look, we're not looking to build a system that packs a lot of discretionary cash on the balance sheet. We're going to look at deals and we're going to try to fund them very thoughtfully, and if they're accretive to our shareholders, we expect they'll be widely accepted if we consummate.

Okay. And then just one on -- to clarify the spending philosophy. Do you expect to increase activity this year if we have higher oil prices from where we stand today? Or were your comments about increasing activity more flexible on the time line?

Well, we certainly want to maintain maximum flexibility. And we said we could accelerate activity, but we've got to accelerate activity in a time frame where commodity prices support it, but also service costs support that we can still generate the kind of growth we're talking about at industry-leading efficiency rates. So we've never been about growth for growth's sake, and Diamondback's never been a drill-baby-drill company. It's about very efficient and thoughtful prosecution of our development plan that generates maximum returns to our shareholders, and we've done it in 2015 when post-OPEC meeting and we started laying drilling rigs down. We did it again in 2016 when there was a dislocation between service cost -- or stimulation cost and oil price. And I think we've got a pretty good track record of demonstrating how we think about funding the business.

Our next question comes from the line of Michael Glick with JPMorgan.

Could just talk a little bit about the midstream investments you had planned for this year and how that should impact LOE as we move through the year?

Mike, our 2 oil gathering systems in the Delaware Basin should be completed by the end of this quarter so it should be beneficial to our LOE Q2 onwards from that respect. Electrification, we're working as quickly as we can to get electrification across our entire Delaware asset base. I would assume towards the end of the year, you're starting to get more and more wells hooked up through electricity and almost a full field electrified by the end of this year. On the water and the freshwater and water disposal side, we've got enough capacity today, we're building some lines to connect different parts of the infrastructure across the asset base, but I would assume that continues to be developed on a just-in-time basis.

Mike, I might just add to that, if you go back in our company's history and remember how we developed the Midland Basin, we've spent a lot of dollars upfront on infrastructure in order to generate the cost-leading margins that we're enjoying today. And so we're a couple of years behind that in Delaware because we just really started working March of 2017 doing that. But the corollary is very strong, correlation is very strong between investing in infrastructure, driving costs down and increasing margins in the Midland Basin that we've already shown we can do. That's the strategy in the Delaware also.

Got you. And then in Pecos County...

I'm sorry, if I just can add one example I forgot to add. I was going to say we've got some of that started in the third quarter, fourth quarter last year in the Delaware and some of the facility spend that we're talking about this year is actually carrying dollars from 2017.

Got it.

In the Delaware, yes.

And then in Pecos County, can you talk a bit about how your completion design is evolving and how ESP is impacting well performance?

Yes, we've seen a correlation between sand volume, fluid volume and EUR and so we're continuing to try to optimize that because there's a cost component to that equation as well. So we're trying to actually hunt for the right balance of increased cost and increased EUR with the corresponding increase in a project IRR. So I would say probably around 2,500 pounds of fluid in the Delaware right now is probably our most common. And then on the Midland Basin side, we're somewhere in that 1,600 to 1,800 pounds per foot on the Midland Basin side.

Got it. And then just last one from me. Just in your Limelight Prospect, just wondering if you could give us some more color on the genesis of the play?

Yes, our scientists actually identified the play about 3 years ago up in Andrews County. There's a couple of private equity companies that have actually gone up there and drilled some pretty good wells. And so with that knowledge, we continue to push along trend there and we found out, at a real low entry point, we found a similar play -- or the similar depositional environment that we're able to acquire grassroot leasing at a really attractive price. And so while for a $11 billion, $12 billion company Diamondback, it's not going to be huge needle mover, but it's a nice piece of business for us and it's going to compete for capital given success. So it's still too premature to talk because we haven't and we're still on our assessment phase doing above-ground technical work, but look for us to provide more color on that as soon as we get results sometime this year.

Our next question comes from the line of Gordon Douthat with Wells Fargo.

Just another question on the dividend and kind of how you think that plays out over -- as you built scale up to that 16-plus rig cadence, how do you look to balance kind of your growth profile with the free cash flow and returning capital longer term?

Well, the balance is always going to be how can we with some maximum rate we can grow at, at the same time maintaining our capital efficiencies and our cost margins. So we kind of have a natural governor on that, but the dividend is just a part of that overall return to shareholders. And like I said, once we get up to that 16 to 18 rigs, we've got multiple opportunities to return capital to investors beyond the dividend if that's the direction we go.

Okay. And just a question over in the Delaware. With a lot of the activity being in the upper -- or the Wolfcamp A, just wanted to get your thoughts on the upper versus the lower given some of your tests that have been online for a bit longer since the last update. So just want to get your views on developing those 2 zones.

Yes, we'd say they're pretty competitive. We have a 3D seismic shoot coming across the whole acreage position that we should be able to access towards the middle of the year, which should help us landing spots throughout the whole acreage block. But upper and lower today seem very competitive.

Our next question comes from the line of Asit Sen with Bank of America Merrill Lynch.

Can you hear me?

Now we can, Asit. We lost you again.

Can you hear me?

Our next question is from Derrick Whitfield with Stifel.

Congrats on a strong update. Circling back to your 2018 capital budget, what commodity price and services cost scenarios do the upper and lower bands of your CapEx reflect?

Yes. I mean, I'd say the upper end of the CapEx is a $60-plus world. I'd say the midpoint to lower end is where we are currently. Service costs, we're pretty conservative in assuming 12% overall well cost increase for the full year on the Midland side and 17% for the full year on the Delaware side. That's not happening necessarily in Q1. But if oil price stays where it is and where it's been the first 55 days of the year, we anticipate that some of the service guys are going to come calling for some price increases.

Got it, that makes sense. And then moving over to Page 9 of your presentation. You guys did a nice job of comparing completion cycle times between the Midland and Delaware. If you were to aggregate the best times by segment in the Delaware, to what degree could you improve that 800 to 1,000 lateral feet noted in the presentation?

Yes. I mean, they're operating very efficiently completing 800 to 1,000 feet a day in the Delaware. It's just the size of the jobs and the amount of fluid and sand you're pumping through the equipment and the horsepower that gets you that 800 to 1,000 feet. On the Midland side, we're doing jobs that are 1,600 to 1,800 pounds a foot, which is 40% less than the Delaware side. So it's logical that in Midland you can get about 40% more lateral footage a day.

Got it. And then my last question would be on the Limelight Prospect on Page 16. Could you comment on the primary interval you would target in and just give us a sense as to how productive this analog interval is in Andrews County?

Primary target interval is in that lower Barnett and Meramec interval. And it's public data up there. It's primarily drilled by Zarvona and Elevation, and we've looked at the wells and the well cost and what they've done, it looked like it would be -- it would compete for capital in our current program if we can duplicate similar success down here.

Our next question comes from the line of Bob Morris with Citi.

Travis, about 6 months ago you talked about 20 to 22 rigs being the optimum level for your current acreage footprint and I know now you're talking about 16 to 18 is the optimum level. Can you comment on why that's come down?

No, it's always been 16 to 18, Bob. Maybe it may also be that we're a few -- several months ago or several quarters ago, maybe we were drilling wells slower than we're drilling now and we're drilling them a lot faster now, so we're drilling a lot faster and utilize less rigs.

Okay. And then the second question, on the Limelight Prospect, you've got 19,000 acres, which is a relatively small footprint and you have yet to test that. Any reason you're announcing that today before the results, which might signal others to maybe bid up the acreage to increase your position there at some point rather than just holding off until you have some results?

Yes, it's just FD rules. We prefer not to, but we came with our 10-K and we're happy with the size of the position and looking to test it given our current size.

And then on the wells that have been drilled, you mentioned private equity operator in Andrews, what would you expect the oil, gas and NGL mix to be from these targeted zones in the Barnett and Meramec there?

Can't make a comment on that at this time. We're very, very early. It is oil weighted, heavy oil weighted.

Our next question is from the line of Jason Wangler with Imperial Capital.

Travis, I was curious last week on the Viper call, you talked about some drop-downs potentially from Diamondback down to Viper. As you think about the strategy at Diamondback, how do you think about those transactions in terms of the use of proceeds? And would even potentially use Viper shares directly to Diamondback as to make those transactions?

Yes. Jason, it's probably a combination. I think we definitely want to see a public marker value on the minerals that we have sort of at the Diamondback level, but also we can use that cash to accelerate and further improve the economics of both Viper and Diamondback. I think the exciting thing for us with these minerals we don't want to hold them at the Diamondback level too long and we're coming up upon running 4 or 5 rigs here in the Delaware and that's going to get some real mineral production going in '18 and allow those drop-downs to happen.

Sure. And then just on the infrastructure side, $125 million, $175 million this year. Is that a pretty decent run rate as we think about maybe 2019 or should that start to fall off as you kind of build out that infrastructure side?

No, that number should come down over time. This is, again, on our earlier comments, this is getting the systems in place just like we did in the Midland Basin side where you're putting in the major gathering systems, you're getting all your produced fluids out of trucks on the pipe and so these were all front-end development type expenditures.

Yes. I mean, just for round numbers, when you look what our Midland Basin spend to total capital, it's about 5% or 6% now on the infrastructure side, so we anticipate the Delaware to get there in short order.

Our next question is from the line of Tim Rezvan with Mizuho.

I was hoping to follow up on the midstream theme. When you were asked earlier, you focused on the electrification and gathering systems. How do you view water as a potential bottleneck in terms of sourcing and disposal? And how much of the CapEx on midstream is allocated to water?

Yes, we have more than enough water on our Pecos County asset. Actually, the Capitan Reef flows through the eastern side of the acreage. So from a freshwater perspective, we have more than enough that we need to prosecute our plan. And from a percentage of overall capital, I'd say, water's about 1/3 of our total capital, oil is another 1/3 and then the rest are tank batteries, gas gathering upgrades and the electrification.

Okay. And then on the disposal side, no concerns?

No concerns. We're continuing to drill SWDs, but also flow barrels south and east of our position, which I think will advantage us in the long term.

Okay, great. And then as my follow-up, you all gave guidance of the number of horizontal completions. You're clearly in manufacturing mode across the Midland Basin and possibly even in some areas in the A, on the Delaware Basin side. But how many of those wells would you consider to be more on the delineation side? You talked about the Bone Spring opportunity. Just trying to understand across that 3,800-well location count, how many of those horizons will you kind of be able to transition towards more exploitation mode as we move into 2019?

Yes. I'd say we wouldn't put locations in our deck if we didn't feel they were very economic and more of a development-type location. Just coming back to 2018 total wells, I'd say probably 10% are step-outs or tests of different zones that we haven't tested and mostly in the Delaware Basin.

The next question from the line of Gail Nicholson with KLR Group.

Just looking at the cost delta for '18 versus '17, you're seeing a larger cost increase at the midpoint in the Delaware versus the Midland. And is that just -- I mean, is that due to solely using locally sourced sand in the Midland and the cost savings there? Or are there other things going on between the cost increase delta on a per lateral foot basis?

Gail, it's a combination. We're assuming local sand on the Midland side really kicking in Q2. So you're going to get some savings there. On the Delaware side, we are pumping more of the bigger jobs, which relative to last year when we were assuming probably an average smaller job on the completion side.

Okay. Great. And then going back to the ESP-ing, you guys are seeing a significant production uplift in the Delaware following the ESP conversion versus gas lift. I know you guys are still doing up the electrical infrastructure in the Delaware. So is the -- do the current wells that you plan to bring online in '18, do you have the electrical infrastructure to support ESP conversion as they need to be put on pump? Or how should we think about that in terms of that potential incremental uplift as you move through time into that infrastructure build-out?

Gail, as we go through '18, we're going to -- we're moving toward electrification in the field. But currently, we do have some backbones built and we have some local generation runoff of field gas or diesel that is powering these ESPs. So we will absolutely have the availability of running the ESPs, but they won't to be on the high line powers, we'd call it into the latter half. Yes, ma'am.

Our next question comes from the line of Richard Tullis with Capital One Securities.

Travis, congrats on closing out the year on a strong note. Lots already been asked, but going back over to the cost side, when you look at the LOE for the fourth quarter, it still shook out on a barrel basis toward the low end of the 2018 range. Are you seeing cost pressures there that kind of point to more toward the midpoint or higher end of the range? And are there more workovers planned in 2018 versus '17?

Richard, what you're really saying is you've got to hear the commentary around our midstream. We're not fully built out in the midstream side yet. And a lot of that midstream translates -- a lot of that lack of midstream development in the first half of the year translates to higher LOE. So again, we're just trying to be transparent that the first half of the year certainly is going to be impacted by the fact we're still having the truck and we don't have electrification like Mike and Kaes were talking about. As we push forward into the second half of the year, we hope to start seeing the benefits of our midstream investments in the form of lower LOE, but we're just trying to give you the way that we see the landscape right now. Of all the things that you should think about Diamondback, the low-cost operation mantra is alive and well. And so even though LOE moved up a few nickels year-over-year, we're still focused on pushing that to the best-in-class margin level.

Yes, and really that's also Delaware volumes are growing and continuing to become a bigger piece of our total production pie so...

That's helpful. And just lastly for me, going back to 2018 drilling plans, any thoughts to test the Avalon in '18? And how are you thinking about that Lower Second Bone Spring target given the initial results from that Kelley State well?

Yes, no plans on the Avalon and we'll -- we're -- what's the update on we're looking to drill an offset to the Kelley State?

We're going to be drilling more Kelley State -- or more Second Bone wells. We're primarily, as I think you stated, Wolfcamp A because of lease obligations and also every Wolfcamp well that we drill we're getting more data on the Second Bone as we drill through and we're basically mapping out and we've got a 3D seismic that we anticipate having acquired and interpreted by midyear or so we're really still excited about the Second Bone, but as we've stated there, primary focus is going to be on the Wolfcamp A at least through the first half of 2018.

Our next question comes from the line of Charles Meade with Johnson Rice.

I wanted to take another crack at something that, maybe from a different angle, something that other people have asked about your kind of longer-term philosophy on balance sheet and capital structure. As I look at it, as you, guys, continue to grow and spend within cash flow, you naturally delever on a multiple basis when you look at your net debt-to-EBITDA. And so I'm curious is there's some lower level that you and the board have discussed that you don't want to go below to kind of maintain some efficiency in your capital structure? Is that a reasonable way to think about it?

I think that's a good problem to have. We haven't had discussions on the low end. I will say we do feel like the balance sheet can support us doing the little deals, right? I mean, last year, we did another $350 million or $400 million of acquisition at the Diamondback level that we didn't need to raise equity for and put them on our balance sheet and still delevered through the year. So we really think of the balance sheet as our ability to continue to block up acreage, buy out working interest and increase our efficiency that way.

Got it.

Charles, again, it's -- when you look at what we're doing in 2018, it kind of lends itself to that conversation because we got the high-growth rate within cash flow, we're doing it to highest margins and we're delevering the balance sheet and instituting the dividend. So these are good -- these are all good combinations that we're discussing at the board as we look into the future for how to best manage the balance sheet and our capital structure.

It's a great set up to have for your discussions. I wanted to ask one question about operations on Midland side hasn't been touched on yet. This -- you guys had a strong pad result, and I guess, how we're counting with the bullfrog -- was at the South bullfrog pad and you had Wolfcamp A and Lower Spraberry there, so I wonder if you could decompose perhaps those IPs between the Wolfcamp A and Lower Spraberry and give a hint if you're seeing anything new or different in the Lower Spraberry on that eastern half of the Midland Basin that might change your appetite there?

Yes. I mean, I think the Lower Spraberry keeps getting better and better on eastern side of the basin just as the Wolfcamp A keeps getting better and better on the western side of the basin. So going back to this bullfrog pad, we did a joint development with the Lower Spraberry and the Wolfcamp A. And on a pad level basis, I think that, that pad competes for capital if anything in the top decile of our portfolio. The As have a higher initial IPs, but the Lower Spraberry wells stay at a peak rate longer.

Our next question is from the line of Dan McSpirit with BMO Capital Markets.

A few question on decline rates, if I could. What do you estimate to be the decline rate on PDPs in the Delaware and Midland Basins and maybe on the oil stream alone?

Yes. Corporate decline's 35% overall.

Any breakdown by product stream there?

Oil will decline slightly, slightly more than the overall.

Okay, great. And what about new wells as more volumes are pumped downhole, that is -- how does the first year decline differ today versus previously? And is there any change to how the wells are flowed to the rest of the decline?

I think it's safe to say that we keep learning more and more as we drill more of these wells and they seem to be producing better longer on the Midland Basin side, if you look at how these wells have done on a longer-dated basis versus prior wells, 2017 was even better than '16 and '15.

Our next question is from Eli Kantor with DIR Advisors.

Given the interest in exploration and the recent success Viper had in South Texas, can you comment on Diamondback's appetite to look outside the Permian for other exploration prospects?

Yes. We're Permian focused, Eli.

Do you have a ballpark figure on what percentage of your Midland and Delaware Basin leases still within the areas that you highlight that's providing 1 million barrel-plus EURs?

Yes. I mean, 90% on the Delaware and probably 85% on the Midland.

And our next question is from the line of Asit Sen with Bank of America Merrill Lynch.

So I have 2 questions, first on the lateral length. Your average lateral length is creeping up nicely, 9,300 average this year plan. What is the longest lateral you planned for this year? And what are your thoughts on diminishing returns with longer lateral lengths?

Asit, our longest wells this year, it's a little unique because we complete about 12,500, sometimes it's closer to 13,000 feet. But a lot of these are wells that we have to drill from off-lease. So the actual drilled length of these wells sometimes are over 14,000-foot of lateral lengths and completed because we drill from off-lease on. So roughly 14,000 is kind of the top number. When you look at efficiency break-over right now, out to 10,000 feet, we definitely see a one-to-one relation Midland and Delaware. On the Midland side, the longer laterals, we still see that one-to-one out to that 12,500. Over on the Delaware side, just due to the fact that the large volumes of fluid that we have to move, we're still assessing it, but we're seeing on these longer wells that we have a muted IP per lateral foot in the very early time of these wells and it's just related to the volume and the restriction of the batteries. So they hold longer than the shorter wells, but the shorter wells will show a higher IP because we can move that same amount of fluid through those batteries just it's over a shorter footage.

Great. And secondly, Travis, conceptually looking out into next year and if you're thinking about adding a rig, let's say, every 3 to 5 months, what do you see as some of your biggest challenges outside of labor? I'm specifically focused on ancillary services.

Yes, we've got to have a very collaborative approach to building our rig fleet with our service providers. We treat each other as business partners and we've got to be able to grow at that cadence and maintain absolute cost leadership position. So we're not going to add that next rig or the next frac spread or that next whatever piece of equipment unless we're confident that through our supervision and through collaboration with our service partners, we can do so at the same efficient margin we're currently producing at. We just feel so -- it's just so fundamentally ingrained at us that we've got to have best-in-class execution at the lowest-cost operations that we're just going to let that be the governor on how quickly we grow volumes.

Our next question is from the line of Jamaal Dardar with TPH & Co.

Had a quick question on the Wolfcamp B well, I think in the Reeves County, pretty impressive result versus our expectations. Just wanted to get your thoughts on the need to potentially co-develop the A and the B across the Delaware?

Yes, I think we're spaced conservatively enough that we feel the need to co-develop. There's a significant vertical distance between the B and the A in that area. We no interference on this particular pad. We're excited about the B. I don't think -- it's not as good as the A, but it definitely provides us a second, along with the Third Bone Spring in the third zone that competes for capital in our ReWard acreage.

Okay, great. And just wanted to get a sense of any other spacing tests, I know that came up quite a bit, that you have conservative spacing out there. So just kind of want to get a sense of any operated results we should be looking out from you guys?

Again, no major spacing tests prior on the Midland Basin side. I think we're happy with where our spacing is today. On the Delaware, we're drilling 2 well pads so we're not getting a ton of spacing data, especially as we're looking to hold a few leases throughout our acreage position. So I'd anticipate more spacing tests in the out years.

Our next question is from the line of Michael Hall with Heikkinen Energy.

Kudos on the continued leadership. I guess, I wanted to look at Slide 10 a little bit in the context of some of the commentary and questions around LOE. Now you're showing effectively the same operating costs between the Lower Spraberry and Wolfcamp A and the Midland versus Delaware Basins, respectively. How -- is that -- is the operating cost used in that, assuming the improvements that you expect to see from the infrastructure uplift or the infrastructure install I should say?

Yes. Mike, we're just trying put out what we put out publicly from a cash cost perspective, and I don't want to get into the details of what LOE is on the Midland side versus the Delaware. So we put the overall cash costs to from the quarter as the actual for that illustrative example now. Obviously, the first year, LOE's a lot lower on a well than it is in the out years and on an overall company basis. So we just use the overall company numbers.

Okay. And I guess, how much LOE do you think you can take out from the infrastructure side of things over the course of 2018?

I think it's fair that LOE continues to trend down over the next few years. We're not going to stop until these wells are flowing back for free, but it's safe to say we will continue to make incremental progress throughout the year.

Okay. Then I guess, last follow-up on that is just around water cuts. Can you remind us what water cuts look like in the Pecos versus Reeves County asset?

Yes. Pecos and Reeves are about 4:1 versus the Midland Basin, about 1.5 or 2:1 water-to-oil ratio.

Okay. But no appreciable difference in Pecos versus Reese on your asset?

No, sir.

And our last question is from the line of John Aschenbeck with Seaport Global.

I had a follow-up on the Limelight Prospect, specifically on your comments about the Barnett and Meramec and Andrews County. Was curious if you think those formations are prospective on your acreage in Central and Eastern Andrews? Or if that acreage is just too far off the platform?

Maybe on the Western side, but we don't have enough information to make it a true answer at this point.

Okay, great. And then a follow-up there. In terms of the results that you've seen from private operators, I'm not sure if I missed it or not, but was curious what you've seen in terms of just initial production rates and then well cost as well?

Yes, I'm not going to comment on that. It's safe to say that we look at competitor results throughout the entire Permian Basin. And we're on top of it and making sure that we're up to speed on the latest tests, especially in areas nearby our acreage. So no, I'd say we wouldn't lease 19,000 acres without some confidence that other operators have done a good job.

Okay. Fair enough. Understood. And that kind of feeds into my last one here, I was wondering if there's been any Mississippian results around your position in Ector and Crane? Or will you be essentially pioneering the effort in those counties?

We'll be the first in this area as far as in this play that we've mapped. There have been some other tests, earlier tests, way back when, when the Barnett play was taking some vertical tests. But we've used all the data from earlier vertical wells and the date available to assess the position. And we will be drilling a pilot hole with core on our first test. So we'll use that to further fine-tune our landing.

Thank you. And that concludes our Q&A session for today. I would like to turn the call back to our CEO, Travis Stice, for his final remarks.

Thanks, again, to everyone participating in today's call. If you have any questions, please contact us using the contact information provided.

And thank you, ladies and gentlemen, for participating in today's conference. This concludes the program, and you may all disconnect. Have a wonderful day.