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Diamondback Energy Inc
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Good day, ladies and gentlemen, and welcome to the Diamondback Energy First Quarter 2019 Earnings Conference Call. [Operator Instructions]. As a reminder, today's conference is being recorded. I would now like to introduce your host for today's conference, Adam Lawlis, Vice President of Investor Relations. Sir, you may begin.
Thank you, Sidney. Good morning, and welcome to Diamondback Energy's First Quarter 2019 Conference Call. Representing Diamondback today are Travis Stice, CEO; Mike Hollis, President and COO; Kaes Van’t Hof, 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 will 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% 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 and 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 cost reflect the execution of the synergies presented in the merger presentation with Energen last August. Diamondback is on pace to achieve 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 billion 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 Energen as well as noncore acreage in Crockett and Reagan counties. These transactions are expected to close by July 1, 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 $0.25 a barrel to account for the higher operating cost structure of these assets.
Secondly, we also contributed the oil gathering and saltwater disposal assets acquired in the Energen acquisition into our midstream subsidiary, Rattler Midstream, with market-based contracts in place.
Lastly, 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 important in this quarter, our Board of Directors has authorized up to $2 billion capital return program to be executed in the form of a stock repurchase program in 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 the 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 commune pure-play.
At a high level, our capital allocation philosophy is grounded on achieving pure leading year-over-year growth, supporting a growing dividend, reducing debt consistently and continuing to replace and maintain a deep inventory at 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. Put simply, we feel buying back our stock is the best acquisition opportunity we see today given our outlook and the multiple visible catalysts ahead.
With these comments now complete, operator, please open the line for questions.
[Operator Instructions]. Our first question comes from Neal Dingmann with SunTrust.
Travis, go right into that what you had mentioned, the biggest news obviously in the release being the material stock buyback announcement. Could you all speak to your expectations for future production growth in the out years, 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 in the -- I guess in the slides, given -- assuming this material shareholder return initiative would continue?
Sure, Neal. Obviously, we're not going to give multiyear guidance on what our growth rate is going to be. But I think if you look at what our growth rate was last year, between 40% and 50%, this year, it's around 26%, look, the law of big numbers eventually catch up with you. And we're still going to be growing in the upcoming years, but I think the key word here is growth. 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? I'm trying to -- what I'm getting to -- what I'm trying to look at is basically in your capital budget you've disclosed, I'm wondering if you include acreage acquisitions, equity investments, VNOM acquisition, the whole bit, I think you are around, what, $300-ish billion or something in first quarter. I'm just wondering is that a good run rate and then really trying to frame that in the context of generating the cash flow and needing that to buy back the stock.
Yes. Neal, I'll take that one. Yes, I mean the capital budget, $2.7 billion to $3 billion, is drilling and completion, midstream and infrastructure. On top of that, we have our equity investments in the Gray Oak and the EPIC pipelines, which are going to be held in our Rattler subsidiary. And we really don't consider onetime 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 Kaes, 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.
And our following question comes from the line of Brian Singer with Goldman Sachs.
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. We've committed to reducing our debt. I think our debt to -- our leverage ratio is around 1.9, and we'll probably get that reduced here pretty quickly. Kaes, do you want to answer the back part of that?
Yes. The revolver right now is $1.9 billion, Brian. We're going to get that down by $700 million or $800 million with onetime proceeds on the free cash flow piece. It's really what we see in the model in Q2 through Q4 of this year and then 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. And then shifting to the assets in the broader consolidation landscape, you've never been shy to participate in consolidation. You talked 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 what you announced here with the noncore asset sale, bolt-on acquisitions to further that scale and then potential for larger-scale M&A?
We've been pretty clear that doing a little acquisition, the bolt-ons, where we can take advantage of Diamondback's operation prowess, are just part of our DNA, so we're going to continue to do those. 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 more sense in your hands or someone else's hands. And what we just did, the majority of those late-life assets or low-value assets by selling $322 million of them. And 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 with working for shareholders that own the company. And today, we really feel like that's best accomplished through best-in-class execution or low-cost operations and delivering on the outlet that we just presented. My job, really -- I can't really speculate on what goes on in the industry M&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.
And our following question comes from the line of Derrick Whitfield with Stifel.
Congrats on your strong update decision to pursue a meaningful share repurchase.
Thank you, Derrick.
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 midcap to bellweather status, could you share with us your views on the merits of zero premium mergers among your former midcap peers to create advantaged pro forma 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.
Yes. Certainly, execution is a lot harder than the spreadsheet. And I think we learned that in our early days. But again, Derrick, I just want to focus on what I know, and that's -- my job is to represent what Diamondback does and control these best-in-class operations and really pristine execution. And really, all I know about what's going on in the larger space is what I read in the press, and 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, say, the shareholders that own Diamondback. And that's what we're trying to accomplish.
Completely, sir. 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 cost has been remarkable. If you were to assume Frankenstein wells in those basins, where would that theoretically place your well cost in peripheral lateral?
Absolutely, Derrick. So on both basins, we always look at that kind of the technical limit well, and we always strive to push that. And what we find is that technical limit keeps moving. So we're past some of the technical limits we had a year or 2 ago, so they keep moving. So 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.
And our following question comes from the line of Gail Nicholson with Stephens.
Travis, I think it's great that the concentration -- what Diamondback can do, and you guys do it so well. When you look at the business at a whole, what do you think is that one area that just continues to improve on, that one -- that low-hanging fruit that might still exist 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?
Yes. Gail, it's not just one thing. And I think that's actually where you can get yourself in trouble if you just inordinately focus on one thing. It's really the combination of all the things that fit into that low-cost operations and really good execution. And I believe we've got an organization that understands their role in delivering on those. And so our focus is continually on those items that drive efficiency even if sometimes if you had to spend more because it's an emerging technology. If it translates to low overall cost, well, we'll embrace that as well, too. So there's nothing, we're just trying to squeeze every penny. We, of course, try to do that, but we also look for the best way to do things that have -- 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 drilled co well that are well-aligned this quarter, very solid results. Can you just give a little 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 run out down there?
Yes. Obviously, we're very impressed with the initial wells that we drilled down there, some of the best wells we've actually drilled in Pecos County. And 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 which -- it's a good example of how Diamondback's different companies are really driving a lot of value for our investors.
And our following question comes from the line of Jeff Grampp with Northland Capital.
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 I understand it mechanically, if you guys were at a point where dollar rise should be within budget but efficiencies were driving the completed well count higher. Should we expect Diamondback to curtail drilling rigs and/or completions in that type of scenario? And how does that kind of set up -- how do you guys think about setting up for the 2020 program?
Yes. Jeff, no, 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 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 with the $2.7 billion to $3 billion budget, we're thinking internally here, we got to beat $2.85 billion.
Okay. And on the prune side of the equation there, obviously, you 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, 6 to 12 months? I imagine you guys are always open for business if someone made you a good offer on some backdated inventory. But is there any kind of proactive effort internally to prune any other additional assets?
Yes. Again, Jeff, as I said, as big 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. That's -- I'm very proud that we're able to get that divestiture done. It represents delivery on one of the synergies that we talked about at the acquisition time. And so like I said, any opportunity, we'll take a look at. But right now, we're focused on delivering on some of these other corporate objectives, like maintaining our focus on low-cost operations.
And our next question comes from the line of Ryan Todd with Simmons Energy.
Maybe a follow-up on cost and capital. CapEx performance in the quarter was clearly impressive, particularly on the D&C side, I mean -- which probably makes sense given how cost synergies are tracking. But can you talk about the primary drivers of a lower-than-expected CapEx, whether you feel those are sustainable? And although it's early, whether -- what you see is the potential downside risk to deploy our budget or I guess at least the bottom half of the budget?
Yes. Ryan, we made a promise in December that we're going to cut activity and cut activity right away. And we've delivered on that in the first quarter. We dropped 2 spreads immediately and dropped 3 drilling rigs. 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. And then maybe not meant to be a follow-up on M&A but really one on scale, your -- 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 as the benefit 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 are -- obviously have a good amount of scale there. I mean 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?
Yes. Ryan, I'm not going to comment on any peer's 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 operations side of the two companies being put together.
Look, Brian, we've grown the company from essentially no horizontal rigs to where we are today, over 20 horizontal rigs. And regardless of what the right cadence is, and I think that's dependent on each company, our objective is whether it's 1 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 1 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 Diamondback is running, we're going to be best-in-class and the lowest-cost operator. 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. Larger you get, the bigger and bigger piece of your importance to your strategy and your and execution development is being able to control the infrastructure. And that's why we're -- that's why we've got a nice infrastructure company inside Diamondback.
And our next question comes from the line of David Deckelbaum of Cowen.
Just curious on -- you guys are -- 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 the -- 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. And the $20, the additional $20 in the Midland side was what we captured in January. So that is already in place, and we've demonstrated that this quarter. On the Delaware side going forward, so again, we're not going as far along in the development of the Delaware side as we are on the Midland side. So again, based on 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.
Got it. I appreciate that. And then just, my second question. If you think about having in 2020 that -- you guys put out a 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 of it 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 4 operated rigs to 22. That's going to really increase the treadmill over that time period. Now with us at 21 rigs today and not looking to add 6 or 7 rigs a year anymore, naturally, your PDP decline rate is going slow. So I mean we see that declining by about 5% from 2019 to 2020.
And our following question comes from Asit Sen with Bank of America.
Appreciate the free cash flow guidance for 2020 at the $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?
Asit, I mean the biggest things we're factoring in is we're at 21 rigs today. I don't expect us to add more than 1 or 2 rigs in 2020. From a capital perspective, it's natural that if oil stays where it is, that service cost being recalibrated a bit to the higher side. So there's some conservatism baked into that number. Most importantly, our oil marketing contracts get significantly better in Q2 this year. But looking into 2020, we'll be exporting a majority of our barrels down to the Gulf Coast. 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 in both sides of the basin.
I'll let Mike 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. Our goal from a business development perspective is to make sure we have 10,000-foot laterals at least across our whole portfolio. So we're going to be moving at the margin, but every 100 feet certainly makes a difference from a capital efficiency perspective.
And Asit, 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 the optimal. And actually, the team does a great job of figuring out what that is in each one of our geographic areas. And 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 2- to 3-, somewhere as up to four well pads right now. Over time, that may grow, but it won't grow to the level that we have in the Midland Basin side in the near term.
And our following question comes from Tim Rezvan with Oppenheimer.
I wanted to switch topics a bit and move to the Carlyle 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.
Tim, yes, we're certainly pleased with those well results. It's really going to be up to our partner and Carlyle to elect to go to the next tranche of wells, and we're expecting that imminently over the long term. And 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. From a Diamondback perspective, it'd be a very low capital amount.
Okay. Fair enough, fair enough. And then just to hammer the repurchase kind of seem a bit more, I know, Travis, you've talked with them, they've -- you see accretion and perpetuity from the repurchases. What kind of price sensitivity do you see around that if we assume, all else equal, but shares come back to that 2018 high, $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?
Yes. 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 the form of cash or share repurchases. And that's something the Board will continue to evaluate. But the key here is that this is not just a onetime event. This is the Board's 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.
And our following question comes from Drew Venker from Morgan Stanley.
I just want to follow-up a little bit on the M&A. You've had excellent success pursuing that 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 that 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 buyback announcements. We'd like to think your stock is really under appreciated. Can you just talk about how you think about the potential opportunities in the space and how you balance that with the way you see your stock price right now?
Yes. Drew, again, I just don't -- it's just not my role to speculate on basin-wide M&A activities. I think 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 a $2 billion acquisition that we're talking about.
Certainly, Travis, we'd agree. Your stock is very accretive. So in terms of the $2 billion buyback, can you talk about the -- that figure specifically? Can you talk about funding it with full free cash flow and proceeds from asset sales? Is that $2 billion number, you think you have line of sight to? Or is that -- incorporate a potential upside of proceeds from asset sales of free cash flow to prices to the upside? Are there upside to the $2 billion number? How do you guys think about that?
Drew, that's the number for now. If we outperform, then we'll go back and talk to our Board and adjust accordingly. But we see at strip. And with the catalyst we have on the proceeds side, we certainly see visibility to executing on that number through the end of 2020.
And our next question comes from Jeoffrey Lambujon with Tudor, Pickering, Holt.
My first one is just a follow-up on the free cash flow in 2020 at $55 WTI commentary. I know that a lot of the moving pieces like service recalibration, for example, 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?
Jeoff, 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 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 if this commodity falls out of bed. But overall, we feel like we're creating an execution machine that's going to complete 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 what we could expect in terms of production trajectory from here and how timing can play into that?
Yes. No, I certainly think we're going to grow into Q2. We completed 82 wells in Q1, with 19 of those wells coming on in the last 2 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. That's expected to close July 1, so I expect us to grow into Q3, just not as much as Q2. And then another consistent quarter into Q4.
And our next question comes from Charles Meade with Johnson Rice.
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 lugging it into Lea County. My sense is that's some of the most valuable acreage 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 within the basin. So with what you see, do you -- are those assets more likely, you think, to be on the grow side of your strategy or more likely on the prune side?
We certainly have a substantial enough position that we can execute on the 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 Energen acquisition, we acquired a lot more non-op than we traditionally have had at Diamondback. So we're doing our best to translate that non-op position into a slightly larger operated position. We're certainly not opposed to operating in New Mexico because of the well results in that area. And we're kind of planning to do that if we can build that position a little bit.
Got it. That's helpful. And so I'd say if you can transition it to operated, then it would make more sense. But Travis, I want to go back to...
There's an operated position there today. 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 in terms of -- I want to go back to a comment you've made once in your prepared 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 I'll have to a little bit -- first, I'm going to say 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, and -- but then all the other thing 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 assets. So I think as we reach to scale that we're at right now and this continued commitment of living within cash flow that we've demonstrated -- announced it since 2015, the cash flow component of an 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-teens 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. It's got to be an accretive trade and there's certainly those metrics I laid out to you, we've got to look for accretion on that. And then we'll never do anything that'll put Mike's organization at risk of not being best-in-class executor. So...
Honestly guys, that's helpful insight. That -- it's that focus on the near-term cash flow accretion. So I appreciate those comments.
And our next question comes from Richard Tullis with Capital One Securities.
Just quickly back to the CapEx theme, maybe for Kaes. Obviously, capital spend in 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 1 particular quarter?
Yes. Richard, I think from the infrastructure perspective, 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, we expect that piece to pick up a bit in Q2 and Q3. That number was about 19% of the total budget for the year. And then on the D&C side, 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 I think it's logical that the D&C gross CapEx number picks up a bit with that higher working interest.
Okay. And for Travis, at the DUG Permian Conference a couple of weeks ago, there was a private operator discussing some solid Barnett oil well results that we're 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 playing 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. 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.
And our following question comes from the line of Michael Hall with Heikkinen Energy.
Well done on the execution this quarter. Just curious if you still have a decent amount of inventory, I guess, particularly in the Midland Basin and kind of the other category. I'm just curious if you have any plans for appraising any of that or derisking any of that over the course of 2019.
Michael, I think we've always been a fast follower, and we're very focused on the highest rate of return zones. We're certainly codeveloping more zones and as well as A&D. 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 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. We expect to implement the buyback and sort of buying back stock in the second quarter here.
And our next question comes from Jason Wangler with Imperial Capital.
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 later, basically, and you've talked about. But 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?
Yes. I mean, it changes a little bit, fortunately, for us. By 2021, I don't think we're going to be worrying about the basis hedge anymore with all our barrels 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'll see that we hedged about 25% of our 2020 production in the quarter with pretty wide collars. I think protecting the downside is more important to us than the straight swaps. But 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.
[Operator Instructions]. And our next question comes from Leo Mariani with KeyBanc.
I was hoping to see maybe if you could put a few numbers in terms of the completion cadence? I know you guys certainly had 82 wells in the first quarter. Is there any help you can sort of give us on maybe that number that we would expect to see in sort of 2Q, 3Q and 4Q this year?
Yes. Leo, we don't give quarterly guidance. And I'm going to stick to the plan that we're going to complete 290 to 320 gross wells. We're probably leaning towards the higher half of that at the lower half of our budget. And that's our plan right now. From a cadence perspective, we're running 8 spreads. 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 the initiatives on the buyback, I think you guys talked about $700 million to $800 million of debt reduction this year. Obviously, you got the $322 million asset sale and there are some other drop-downs and some other initiatives sort of working here. But just kind of wanted to understand the $2 billion magnitude. So should we assume that any asset sale proceeds above the debt reduction of $700 million to $800 million 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 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?
Yes. I mean, I don't want to commit to a number of how much we're going to buy back quarter over quarter. 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 multiyear total return philosophy.
And am not showing any further questions at this time. I would now like to turn the call back to Travis Stice 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.