Diamondback Energy, Inc.

Good day, ladies and gentlemen, and welcome to the Diamondback Energy First Quarter 2019 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session, and instructions will be given at that time. If anyone should require operator assistance during today's conference, please press star, then zero on your telephone keypad. As a reminder, today's conference is being recorded. I would now like to introduce your host for today's conference, Adam Lawless, Vice President of Investor Relations. Sir, you may begin.

Thank you, Sydney. Good morning, and welcome to Diamondback Energy's first quarter 2019 conference call. Representing Diamondback today are Travis Dye, CEO, Mike Hollis, President and COO, and Case Van Hoff, CFO. During this 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 in the company's filings with the SEC. In addition, we'll make reference to certain non-GAAP measures. Reconciliations with the appropriate GAAP measures can be found in 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 first quarter 2019 conference call. After closing the Energen acquisition in the fourth quarter of 2018, we ensured that Diamondback got off to a fast start in 2019 and showcased the strength of our operations organization and the low cost structure on a larger scale. We navigated the $30 drop in fourth quarter oil prices by immediately cutting activity to start 2019 while still growing production 5 percent from our December 2018 exit rate of 250,000 barrels a day, all while integrating our $9 billion acquisition of Energen and the addition of over 300 employees to the Diamondback family. I'm going to pause and take a minute to give credit to all of the employees within Diamondback for working together with the new, significantly larger group of colleagues in executing on this plan seamlessly. Both the Diamondback and former Energen employees have learned best practices from each other, and the results have shown through in the capital and operating costs presented in our first full quarter as a combined company. Our first quarter results and revised expectations for capital costs reflect the execution of the synergies presented in the merger presentation with Energen last August. Diamondback is on pace to exceed our previously disclosed synergy targets earlier than expected, and we will look to continue to push efficiency and drive down cash operating costs. Diamondback spent $627 million on CapEx in the first quarter and generated $675 million of EBITDA with $8 per barrel cash operating costs, including $0.55 per barrel G&A. We completed 82 wells in the quarter and are maintaining our expectations to bring on between 290 and 320 wells this year from a $2.7 to $3 billion capital budget. Capital discipline is important to Diamondback and we have no intention to exceed this budget or well count in 2019 regardless of commodity price. From a corporate development perspective, we executed on our grow and prune strategy by signing definitive agreements to divest the conventional assets acquired from Imogen, as well as non-core acreage in Crockett and Reagan counties. These transactions are expected to close by July 1st, and as a result, we have lowered our full year production guidance to account for the production expected to be lost from these properties in the back half of the year. We also lowered our full-year LOE guidance by 25 cents a barrel to account for the higher operating cost structure of these assets. Secondly, we also contributed the oil gathering and salt water disposal assets acquired in the Energen acquisition into our midstream subsidiary, Rattler Midstream, with market-based contracts in place. we are actively working on dropping down the remaining mineral and royalty assets held at the Diamondback level to VIPER and expect to do so at some point in 2019. Most importantly this quarter, our Board of Directors has authorized up to a $2 billion capital return program to be executed in the form of a stock repurchase program through the end of year 2020. This program is a direct reflection of the confidence we have in our business plan and free cash flow outlook given the improvement in commodity prices from our original 2019 budgeting process, our capital budget control, and the expected improvement in our oil realizations as legacy fixed differential contracts have rolled off and we move more of our barrels to the Gulf Coast. With this announcement, We have set a clear use of proceeds for this free cash flow and expect to generate over $750 million of free cash flow from operations in 2020 at $55 WTI. Over the long term, the consistent growth of our dividend will remain our primary return of capital objective, but this repurchase program represents the next step in our total return strategy and the evolution into a large cap pure play. At a higher level, our capital allocation philosophy is grounded on achieving peer-leading year-over-year growth, supporting a growing dividend, reducing debt consistently, and continuing to replace and maintain a deep inventory of Tier 1 acreage. Excess free cash flow above this will be returned to stockholders. Diamondback will not spend every dollar of free cash flow on growth or acquisitions. Could simply, we feel buying back our stock is the best acquisition opportunity we see today, given our outlook and multiple visible catalysts ahead. With these comments now complete, operator, please open the line for questions.

Thank you, ladies and gentlemen. If you have a question at this time, please press the star and the number one key on your telephone keypad. If your question has been answered or you wish to remove yourself from the queue, please press the pound key. To prevent any background noise, we ask you please place your line on mute once your question has been stated. Our first question comes from Neil Dingman with SunTrust. Your line is now open.

Morning. Travis, go right into what you had mentioned, the biggest news obviously on the release being the material stock buyback announcement. Could you all speak to your expectations for future production growth in the out years ahead? Assuming you continue with this impressive buyback, I guess what I'm getting at is, do you all still forecast growth to stay around that 26% stated target level that you've laid out today or, I guess, in the slides, assuming that this material shareholder return initiative would continue?

Sure, Neil. Obviously, we're not going to give multi-year guidance on what our growth rate is going to be, but I think if you look at If you look at what our growth rate was last year, you know, between 40% and 50%. This year it's around 26%. Look, the law of big numbers eventually catch up with you. And, you know, we're still going to be growing in the upcoming years, but I think the key word here is growth. You know, I think we're going to continue. We are going to continue to spend less than we make, and we're going to continue to return capital to shareholders as part of our total return philosophy.

Okay. And then just one follow-up. Could you talk about maybe just on a good capital budget? What I'm kind of looking at is basically in your capital budget you've disclosed. I'm wondering if you include acreage acquisitions, equity investments, Venom acquisitions, the whole bit. I think you were around, what, 300-ish or something in the first quarter. I'm just wondering, is that a good run rate? And then really trying to frame that in the context of, of generating the cash flow and, you know, needing that to buy back the stock?

Hey, Neil, I'll take that one. Yeah, I mean, the capital budget, $2.7 to $3 billion, is drilling and completion, midstream, and infrastructure. And on top of that, we have our equity investments in the Grey Oak and the Epic pipelines, which are, you know, going to be held in our Rattler subsidiary. And, you know, we really don't consider one-time proceeds, whether that's asset sales or asset purchases in that budget. So, Really, the key message is free cash flow is going to be operating cash flow less the CapEx budget and the dividend that we plan to grow continuously.

So, Kay, is that cash flow that you'll use to buy back the stock, you won't do that with debt or something?

No, no plans.

Great. Thank you all.

Thank you. And our following question comes from the line of Brian Singer with Goldman Sachs. Your line is now open.

Thank you. Good morning. Following up on the plan to return cash to investors, can you just talk a little bit about the priorities of paying down the revolver versus share repurchase? And then how are you expecting to time the share repurchase portion relative to expected versus actual free cash flow and expected versus actual asset sales and monetization proceeds?

Sure, Brian. You know, we've committed to reducing our debt. I think our Our leverage ratio is around 1.9. We'll probably get that reduced here pretty quickly. Casey, you want to answer the back part of that?

Yeah, the revolver right now is 1.9 billion, Brian. We're going to get that down by 700 or 800 million with one-time proceeds. On the free cash flow piece, it's really what we see in the model in Q2 through Q4 of this year and in 2020 at nearly any commodity price, let alone strip. The majority of that free cash flow is going to go back to shareholders in the form of this buyback.

Great, thank you. And then shifting to the assets and the broader consolidation landscape, you've never been shy to participate in consolidation. You talk about the grow and prune strategy. Can you just talk about the landscape that you see out there, both in terms of further pruning asset transactions, like which you announced here with the non-core asset sales, bolt-on acquisitions to further add scale, and then potential for larger scale M&A?

You know, we've been pretty clear that doing the little acquisitions, you know, the bolt-ons where we can, you know, take advantage of Diamondback's operation prowess are just part of our DNA. So we're going to continue to do those. You know, as any good capital allocator, I think it's important to always look at your portfolio and look at those late-life assets to figure out whether or not they make the most sense in your hands or someone else's hands. We just did the majority of those late-life assets or low-value assets by selling $322 million of them. Then on the larger deals, I'm not really going to speculate on the larger deals that are out there. I think very clearly my job is to create value. We're working for the shareholders that own the company. Today, we really feel like that's best accomplished through testing class execution or low-cost operations, and delivering on the outlook that we just presented. My job really, I can't really speculate on what goes on on NHPM&A. It's rather to discuss what I know and what I can control and what my responsibility is, which is to drive shareholder value.

Great. Thank you.

Thank you. And our following question comes from the line of Derek Whitfield with Steeple. Your line is now open.

Good morning, all, and congrats on your strong update and decision to pursue a meaningful share repurchase.

Thank you, Derek.

For Travis, this is an open-ended question for you on a related topic to Brian's last question. As you guys know, M&A has been a topic of increasing interest among investors. Based on really your success and the progression you've made from mid-cap to bellwether status, Could you share with us your views on the merits of zero premium mergers among your former mid-cap peers to create advantage for former companies and the scale and overhead synergies that come along with that? And I think to some degree we all live in spreadsheets, but I imagine the execution is quite a bit harder than perceived.

Yeah, certainly execution is a lot harder than the spreadsheet. I think we learned that in our early days. Again, Derek, I just want to focus on what I know. My job is to represent what Diamondback does and control these best-in-class operations in a really pristine execution. Really, all I know about what's going on in the larger space is what I read in the press. I don't want to be the industry spokesman talking about what goes on in the M&A world. I'm really focused on what message I can deliver to the shareholders that own Diamondback. And that's what we're trying to accomplish.

Completely fair. And then as my follow-up perhaps for Mike, I mentioned this to you guys last night, but your track record in driving increasingly lower completed well costs has been remarkable. If you were to sim Frankenstein wells in both basins, where would that theoretically place your well costs in per foot lateral?

Absolutely, Derek. On both basins, we always look at that technical limit well. We always strive to push that. What we find is that technical limit keeps moving. We're past some of the technical limits we had a year or two ago, so they keep moving. I don't have a direct answer for you because we're a learning, growing organization that's going to continue to drive that efficiency and cost control. But With that said, the answer is continually lower than it is today.

That's very helpful. Thanks for your time.

Thank you. And our following question comes from the line of Gail Nicholson with Stevens. Your line is now open.

Good morning, everybody. Travis, I think it's great that the concentration is on what DynaVac can do, and you guys do it so well. When you look at the business as a whole, What do you think is that one area that you can continue to improve on, that low-hanging fruit that might still exist, you know, when you look at the next 12 to 18 months from a standpoint of cost structure, lowering expenses, but just overall improving that cash margin and driving incremental shareholder return?

Yeah, you know, Gail, it's not just one thing, and I think that's actually, you know, where you can get yourself in trouble if you just inordinately focus on one thing. It's really the combination of It's really a combination of all the things that fit into that low-cost operations and really good execution. I believe we've got an organization that understands their role in delivering on those. Our focus is continually on those items that drive efficiency. Even if sometimes if you have to spend more because it's an emerging technology, you know, if it translates to a low overall cost, well, you know, we'll embrace that as well too. So it's not that we're just trying to, you know, squeeze every penny. We, of course, try to do that, but we also look for, you know, the best way to do things that are going to have the greatest impact on our overall portfolio. And I'm really impressed with our new organization that essentially doubled in size in November as to, how quickly everyone now, all the Diamondback employees, embraced that concept.

And then looking at the DrillCo wells that were brought online this quarter, very solid results. Can you just give a little bit more color around that area and kind of what you guys think about that going forward, and then what needs to be done from the standpoint of infrastructure build-out down there?

Yeah, obviously we're very impressed with the initial wells that we drilled down there, some of the best wells we've actually drilled in Vegas County. And, you know, we're going to continue to develop that with our business partner. And we've got some midstream down there that our Rattler business is actively developing now. And also Viper has been acquiring minerals down in that area as well, too. So it's a good example of how Diamondbacks, you know, different companies are really driving a lot of value for our investors. Great.

Thank you.

Thank you. And our following question comes from the line of Jeff Gramp with Northland Capital. Your line is now open.

Morning, guys. Travis, in your prepared remarks, you said not only is there a strict focus on maintaining spending within the CapEx budget, but also that you wouldn't go over your completed well count guidance. And I guess just wanted to make sure we're understanding mechanically. If you guys were at a point where dollar-wise you'd be within budget, but efficiency curtail drilling rigs and or completions and that type of scenario and how does that kind of set up how you guys think about setting up the 2020 program?

Yeah, Jeff, we're not planning to go over that 320 gross well count for the year. I think it would be very hard for us to hit the lower half of our budget with that higher half of the completed well count. That's certainly our target. So we like to think about things at the midpoint and beating the midpoint on the best side of that guidance. So, you know, with a $2.7 to $3 billion budget, we're thinking internally here, we've got to beat $2.85. Okay.

And on the prune side of the equation there, obviously you've got the nice sale in the books. Is there anything else that you guys feel kind of compelled to turn into cash in the next say, six to 12 months. I imagine you guys are always open for business if someone made you a good offer on some backstated inventory. But is there any kind of proactive effort internally to prune any other additional assets?

Yeah, again, Jeff, as I said, as good capital allocators, you've always got to be aware of that. But I'll tell you right now, where our G&A is focused is we've got a lot of other initiatives we're working on right now. I'm very proud that we were able to get that divestiture done. It represents you know, represents delivery on one of the synergies that we talked about at the acquisition time. And so, you know, like I said, any opportunity, you know, we'll take a look at. But right now we're focused on delivering on some of these other corporate objectives, like maintaining our, you know, focus on low-cost operations.

All right. Understood. Thanks for the time, guys.

Thank you and our next question comes from the line of Ryan Todd with Simmons Energy. Your line is now open.

Thanks. Maybe a follow-up on cost and capital. CapEx performance on the quarter was clearly impressive, particularly on the DMC side, which probably makes sense given how cost energies are tracking. But can you talk about the primary drivers of a lower-than-expected CapEx, whether you see all those as sustainable, and although it's early – whether, you know, what you see as the potential downside risk to the full year budget, I guess at least the bottom half of the budget.

Yeah, Ryan, you know, we made a promise in December that we were going to cut activity and cut activity right away. And, you know, we delivered on that in the first quarter. We dropped two spreads immediately and dropped three drilling rigs. You know, I think the combined organization, we've learned a lot of things from the Energen folks and vice versa. and we've started to push down costs on the service cost side. So a lot of it's going to be permanent, but some help from the service side in the first quarter.

Great. Thanks. And then maybe not meant to be a follow-up on M&A, but really one on scale. There's another operator in the Permian Basin that recently referred to optimal scale as being somewhere between 6 and 20 rigs in the basin and the benefits. decreases, you move much beyond that. We've got another large operator that seems to be suggesting that they worry about having the longer-term scale necessary to compete in the Permian. You guys obviously have a good amount of scale there. How do you think about your scale and position long-term in the basin and the type of scale that you think you need or have to compete?

Yeah, Ryan, I'm not going to comment on any peers' commentary. That's up to their opinion. For us, speaking about Diamondback Energy, we certainly have seen a benefit of scale between where we were in August prior to the Energen merger and post that deal. We're certainly seeing the benefits on the cost side and a ton of benefits on the operation side of the two companies being put together.

Look, Ryan, we've grown the company from essentially no horizontal rigs to where we are today, over 20 horizontal rigs, and And regardless of what the right cadence is, and I think that's dependent on each company, our objective is, whether it's one rig or 20 rigs, is to be the low-cost operator of that rig. And our unique organizational focus remains on being best-in-class executors and the lowest-cost operators, whether we're running one rig, 20 rigs, or 40 rigs. So I don't know how to calibrate what the right number of rigs are, but I do know that whatever number of rigs down the back is running, we're going to be best in class and the lowest cost operator.

I appreciate that. Thanks, Travis.

Now, just to add to that, the other thing is that scale also requires you being able to be in control of your infrastructure, which is the reason that we have an infrastructure company set up so that we can maintain control of that. The larger you get, the bigger and bigger piece of importance to your strategy and your execution development is being able to control the infrastructure. And that's why we've got a nice infrastructure company inside Diamondback. Thanks.

Thank you. And our next question comes from the line of David Deckledom. This is Cohen. Your line is now open.

Morning, Travis Case, everyone. Thanks for taking my questions. Of course. Just curious on, you know, you guys seem to be ahead of schedule in realizing the savings on the Midland side. I guess you're expecting to take another $20 per foot out of the well cost heading into 2020. Where do you see that most likely coming from at this point? It looks like the contract side of it on the service side has been realized. So just looking, how do we take another $20 out? And then when you look at the Delaware basin well costs, certain elements that we've realized on the Midland side haven't yet made their way over to the Delaware, particularly it looks like on service costs and to some extent on cycle times. When do you see that sort of catching up on the Delaware side?

David, I'll take the first question first. The additional $20 on the Midland side was what we captured in January. So that is already in place, and we demonstrated that this quarter. On the Delaware side going forward... Again, we're not quite as far along in the development on the Delaware side as we are on the Midland side. So, again, baseball terms kind of third, fourth inning. So, we're seeing a lot of changes in how we're drilling the wells, pad development, completion techniques, casing designs, removing casing strings, reducing what we're doing on these wells and getting better results. So, you're going to see a higher rate of change over the next near-term period in the Delaware compared to the Midland side. But the numbers that we presented today is what we saw in first quarter.

Good. I appreciate that. And then just my second question. If you think about heading into 2020, you guys put out the PDP decline of about 36% this year and 32%, I think, going into 2020, if I recall. Is that solely a function of the cadence of wells coming online, or is there sort of an assumed benefit from managing the base a bit better in terms of nonproductive downtime?

It's really just the benefit of having more wells on longer and slowing down the natural growth rate, right? I mean, if you look back to 2016 to today, we went from four operated rigs to 22. You know, that's going to really – increased the treadmill over that time period. Now with us at 21 rigs today and not looking to add six or seven rigs a year anymore, naturally your PDP decline rate is going slow. So we see that declining by about 5% from 2019 to 2020. Thanks, guys. Thank you, David.

Thank you. And our following question comes from Asit Sen with Bank of America. Your line is now open.

Thanks. Good morning. Appreciate the free cash flow guidance for 2020 at $55 WTI. Just wondering what CapEx or rig count assumption has been factored in that number? And also, any additional synergies beyond the secondary synergies that you have laid out? Are you factoring anything in?

Hey, Asit. You know, I mean, the biggest things we're factoring in is, you know, we're at 21 rigs today. I don't expect us to add more than one or two rigs in 2020. From a capital perspective, you know, it's natural that if oil stays where it is, that service costs, you know, may recalibrate a bit to the higher side, so there's some conservatism baked into that number. You know, most importantly, our oil marketing contracts get significantly better in Q2 this year, but looking into 2020, you know, we'll be exporting a majority of our barrels down to the Gulf Coast, so that's going to help us from a realization perspective.

Okay, and... My next question is actually on slide 14, where it looks like the average completed lateral length has stayed fairly steady over the past several quarters. Is there an opportunity to push that number higher? And just wondering if you have any thoughts on where you see optimal pad size evolving based on your current footprint on both sides of the basin.

All that might handle the optimal pad size, but from a completed lateral length, we're going to be around that 9,500 foot level for a while. You know, our goal from a business development perspective is to make sure we have 10,000-foot laterals at least across our whole portfolio. So, you know, we're going to be moving at the margin, but, you know, every 100 feet certainly makes a difference from a capital efficiency perspective.

And I said on the Midland Basin side, we have well pads as large as 12, 16 well pads. Again, it's area-specific. There's a lot of factors that go into what makes you optimal, and that's what the team does a great job of figuring out what that is in each one of our geographic areas. If you go to the Delaware Basin, of course, the wells produce a lot more fluid than we have on the Midland Basin side, so typically the pad sizes will be smaller. So there typically we're a two to three, somewhere up to four well pads right now. Over time, that may grow, but it won't grow to the level that we have on the middle and basin side in the near term.

Great. Thank you.

Thank you.

Thank you. And our following question comes from Tim Resvin with Oppenheimer. Your line is open.

Hi. Good morning, folks. I wanted to switch topics a bit and move to the Carlisle JV. You announced a couple of very strong wells last night. And on the heels of that, I was wondering if you could give a bit of a refresher on kind of what could happen with that JV, how material kind of that could be, and really if it could influence sort of drilling within or kind of around that JV area in Pecos County.

Hey, Tim. We're certainly pleased with those well results. It's really going to be up to our partner in Carlisle to elect to go to the next tranche of wells, and we're expecting that imminently. Over the long term, I think we're confident enough in the northern half of that acreage that if we didn't have a partner, we'd drill it ourselves. We've bought a lot of minerals and have a lot of midstream in place, and the well results compete with the main block.

Okay. And then on the next tranche, how many wells would that be?

It would be just drilling out the northern half and some southern half wells. Okay.

Okay.

From a Diamondback perspective, it would be a very low capital amount.

Okay. Fair enough, fair enough. And then just to hammer the repurchase kind of theme a bit more, I know, Travis, you've talked about them. You see the accretion in perpetuity from the repurchases. What kind of price sensitivity do you see around that if we assume all else equal but, you know, shares increasing? you know, come back to that 2018 high, you know, 135 or higher, would you still plan to execute this, or do you feel like there is sort of a tactical nature to the intensity based on what the share price is doing?

Yeah, so look, we're committed to this capital share return program, and I think we've allowed ourselves enough flexibility to figure out what the best way to drive that value to our shareholders is going to be, whether it's in you know, form of cash or share repurchases. And that's something the board will continue to evaluate. But the key here is that this is, you know, this is not just a one-time event. This is the board signaling that this is an ongoing return of capital strategy that's underpinned by our free cash flow growth profile and our production growth profile well into the future.

Okay. Thank you.

Thank you. And our following question comes from Drew Venker with Morgan Stanley. Your line is open.

Hi. Good morning, everyone. I just want to follow up a little bit on the M&A. You've had excellent success pursuing and delivering on the synergies you promised with the EnerGen merger. It's not always the case that with large corporate M&A, the synergies actually come through and they're quite visible. And from our perspective, it seems like there's still a number of opportunities where you could put your operational model and cost structure on other assets and extract a lot of value. At the same time, with your large buyback announcement, it seems like you think your stock is really underappreciated. Can you just talk about how you think about the potential opportunities in the space and how you balance that with where you see your stock price right now?

Yeah, Drew, again, it's just not my role to speculate on, you know, basin-wide M&A activities. I think, you know, the signal that we've put forth today is that we believe that repurchasing our shares represents the greatest value in the M&A front, and that's the $2 billion acquisition that we're talking about.

Certainly, Travis, we would agree. Your stock is very cheap. So in terms of the $2 billion buyback, when you talk about that figure specifically, you talk about funding it with both free cash flow and proceeds from asset sales. Is that $2 billion a number that you think you have line of sight to? Does that incorporate a potential upside if proceeds from asset sales and free cash flow surprises to the upside? Or is there an upside to the $2 billion number? How do you guys think about that?

You know, Drew, that's the number for now. If we outperform, then, you know, we'll go back and talk to our board and adjust accordingly. But, you know, we see at STRIP and with the catalyst we have on the proceeds side, you know, we certainly see visibility to executing on that number through the end of 2020. Excellent.

Thank you. Thank you, Drew.

Thank you. And our next question comes from Jeffrey Lambujan. with tutor Pickering Holt. Your line is now open.

Good morning. Thanks for taking my questions. My first one is just to follow up on the free cash flow in 2020 at $55 WTI commentary. I know that a lot of the moving pieces like the service recalibration, for example, as you just mentioned, would flex alongside changes in crude pricing, but are there any sensitivities that you can share with us around that free cash flow figure as you think about variability in WTI?

You know, Jeff, we've always reacted to WTI to flex up or down at the margin. I think what's changing now is that our plan is pretty set. And, you know, there's not going to be a wild swing in rig count up. Now, there might be a wild swing in rig count down if we have to adjust because commodity falls out of bed. But, you know, overall, you know, we feel like we're creating an execution machine that's going to complete, you know, a little over 300 wells this year and a little bit of growth on top of that next year.

Got it. Appreciate that. And then my second one is just on the timing of activity. Is there any additional detail you can speak to on both how Q1 played out and maybe what your thoughts are just on the rest of the year, just towards giving us a sense of what we could expect in terms of production trajectory from here and how timing could play into that?

Yeah, no, I certainly think we're going to grow into Q2. You know, we completed 82 wells in Q1 with 19 of those wells coming on in the last two weeks of the year. So we're certainly going to grow into Q2. Q3 will be the first month without the 6,500 barrels a day of production that we listed as for sale. You know, that's expected to close July 1st. So I expect us to grow into Q3, just not as much as Q2, and then another consistent quarter into Q4. Appreciate it. Thank you, Jeff.

Thank you. And our next question comes from Charles Mead with Johnson Rice. Your line is now open.

Good morning to you, Travis, and your whole team there. I wonder if I could ask you about some Delaware Basin assets that we don't seem to talk a lot about, at least with you guys, and that's really that north-central loving into Lee County. My sense is that's some of the most valuable assets. valuable acreage you per on a per acre basis in the permian but you don't really seem to have that the scale there that you have in like your reward area or in your other places in the middle basis so with with what you see do you are those assets more likely you think to be on the on the growth side of your strategy or more likely on the prune side you know i we certainly have uh

a substantial enough position that we can execute on a capital plan there. It's not as big as our other core development areas. Our business development team is actively working to trade and block up that acreage to increase the operated positions. I think we, with the energy and acquisition, we acquired a lot more non-op than we traditionally had had at Diamondback, so we're doing our best to translate that non-op position into a slightly larger operated position. You know, we're certainly not opposed to operating in New Mexico because of the well results in that area. And, you know, we're kind of planning to do that if we can build that position a little bit.

Got it. That's helpful insight. So if you can transition it to operated, then it would make more sense.

But, Travis, I want to go back to... Yeah, there's an operated position there today. You know, our job is to make sure that operated position grows and so it's more attractive for us to develop long-term.

Got it. Got it. And then, Travis, I want to go back to a comment you made once in your repair remarks, and you repeated here in the Q&A when you said that buying back your own stock is the best acquisition opportunity you see. And, you know, I laughed a little bit the first time you said that because I thought to myself that there's probably some other operators looking and seeing the same thing. But I wanted to ask my question to you. is what are the metrics that you use or that you're willing to share with us that you use to look to span that space between looking at an acquisition opportunity that's a publicly traded equity, even if it's your own, versus looking at a discrete asset purchase?

Well, certainly the cash flow profile of any acquisition target now is among the top things that we evaluate. We're We want cash flow per share accretion. But then all the other things still need to matter, right? I mean, it's got to be accretive on reserves and it's got to be in the top quartile of our portfolio so that we can immediately allocate capital to it and bring our operations excellence to the asset. So I think as we've reached the scale that we're at right now and this continued commitment of living within cash flow, that we've demonstrated honestly since 2015. The cash flow component of acquisition targets is really important.

I think on top of that, Charles, if you think about it from an engineering perspective, we feel that we're trading in the high teams PV with a 9% cost of capital. So buying back our stock is a great use of that capital.

And back on the targets, I can't count the number of times I've used the word accretive You know, it's got to be an accretive trade, and there's several of those metrics I laid out. You know, we've got to look for accretion on that. And then, you know, we'll never do anything that will put Mike's organization at risk of not being best-in-class executor.

Honestly, guys, that's helpful insight, that focus on the near-term cash flow accretion. So I appreciate those comments. Thank you, Charles. Thanks.

Thank you. And our next question comes from Richard Tullis with Capital One Securities. Your line is now open.

Hey, thanks. Good morning, everyone. Just quickly back to the CapEx theme, maybe for case. Obviously, capital spending trend is off to a very favorable start in 1Q. How does it set up the cadence for the rest of the year? Is there perhaps some bigger infrastructure spend in any one particular quarter?

Yeah, Richard, you know, I think from the infrastructure perspective, you know, the Rattler budget, which is the midstream budget, is going to be fairly consistent through the year on a quarterly basis. We spent about a quarter of that budget in Q1. On the infrastructure side, you know, we expect that piece to pick up a bit in Q2 and Q3. You know, that number was about 19% of the total budget for the year. And then on the DNC side, you know, I think we're going to have a little bit higher working interest and a little bit higher average lateral length in the second quarter. So, you know, I think it's logical that the DNC gross capex number picks up a bit with that higher working interest.

Okay, thank you. And for Travis, at the Doug Permian conference a couple weeks ago, there was a private operator discussing some solid Barnett oil well results they were seeing near your limelight acreage. What is your outlook for that acreage? I know it's not a big position, but how do you see that acreage plan out, and when do you expect to begin appraisal there?

It'll probably be a fourth quarter event this year, maybe first quarter next year. But we're still excited about that block we put together at really, really low cost. And we're pleased to see offset results that continue to support our thesis as to why that was a good area to explore.

All right. Very good. That's all I have. Thanks a bunch.

Thank you, Richard. Thanks, Richard.

Thank you. And our following question comes from the line of Michael Hall with Heikkinen Energy. Your line is now open.

Thanks. Good morning. And well done on the execution this quarter. Just curious, you still have a decent amount of inventory, I guess, particularly in the Midland Basin and kind of the other category. Just curious if you have any plans for praising any of that or de-risking any of that over the course of 2019.

You know, Michael, I think we've always been a fast follower and we're very focused on the highest rate of return zones. You know, we're certainly co-developing more zones, MSLS A and B. I think in that other category, we've seen some really good results from some offset operators that might change our plans in the future, but not in a meaningful way. I think, you know, from an overall capital allocation perspective, the highest rate of return zones are still going to get the vast majority of our capital.

All right, understood. And then I guess more of a technical question. Just curious on the buyback. It sounded like your intention is to get started with that here in the near term. In light of some of the remaining potential transactions over the course of the year, are there any restrictions in terms of timing on when you can implement that buyback over the course of 2019?

Not to my knowledge today. You know, we expect to implement the buyback and start buying back stock in the second quarter here.

All right. Sounds good. Thanks, Chad.

Thank you. And our next question comes from Jason Wengler with Imperial Capital. Your line is open.

Hey, good morning, all. Just had one as you kind of move forward with the share repurchase and you think about on the hedging side of it. Obviously, the basis differential should just keep getting better based on what you've talked about. But, you know, how should we think about how you think on the hedging side as you kind of shift to this new kind of formula for the company?

Yeah, I mean, it changes a little bit. You know, fortunately for us, by 2021, I don't think we're going to be worrying about the basis hedge anymore with all our barrels, you know, at the Gulf Coast. In 2020, there'll still be some barrels priced at the WTI Midland price. But as it relates to hedging, you know, you'll see that we hedged about 25% of our, you know, 2020 production in the quarter with pretty wide callers. You know, I think protecting the downside is more important to us than than the, you know, straight swaps. But, you know, we're still going to probably try to hedge about 50% of our production on a go-forward basis and most of that via the collars and then a little bit of swaps on top.

I appreciate the collar. I'll turn it back. Thank you.

Thank you. Once again, ladies and gentlemen, if you have a question at this time, please press star and the number one key on your telephone keypad. And our next question comes from Leo Mariani with KeyBank. Your line is open.

Hey, guys. I was hoping to see maybe if you could put a few numbers in terms of the completion cadence. I know you guys said you had 82 wells in the first quarter. Is there any help you can sort of give us on maybe the number that we would expect to see in sort of 2Q, 3Q, and 4Q this year and

Yeah, Leo, you know, we don't give quarterly guidance. You know, I'm going to stick to the plan that we're going to complete 290 to 320 growth wells. You know, we're probably leaning towards the higher half of that at the lower half of our budget, and that's our plan right now. You know, from a cadence perspective, we're running eight spreads. You know, it's about the number that we're going to run, so it's going to be a pretty consistent turn in lines throughout the year.

All right. And I guess just with respect to, you know, the the initiatives on the buyback. I think you guys talked about $700, $800 million of debt reduction, you know, this year. Obviously, you got the $322 million asset sale, and there's some other drop-downs and some other initiatives, you know, sort of working here. But just kind of wanted to understand, you know, the $2 billion magnitude. So should we assume that any asset sale proceeds above the debt reduction of $700, $800 this year and then any other free cash flow that in 2019 that pretty much all goes to the buyback. And then as you work into next year, should we assume that there's some, you know, type of dividend increase that's to occur and really all the rest of the free cash flow goes to the buyback? Is that the right way to think about it?

Yeah, I mean, I don't want to commit to a number of how much we're going to buy back quarter over quarter. You know, I think in 2019 we're looking to get started really quickly here and then In 2020, as we consistently grow and have a consistent amount of free cash flow throughout the year, the buyback program becomes more programmatic, and that, along with the dividend, becomes a part of our multi-year total return philosophy. All right. Thank you. Thank you, Will.

Thank you. And I'm not showing any further questions at this time. I would now like to turn the call back to Travis Dice for closing remarks.

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

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program, and you may all disconnect. Everyone have a great day.