Diamondback Energy Inc (FANG) — Q4 2018 Earnings Call Transcript

Thank you, Tuwanda. Good morning, and welcome to Diamondback Energy's fourth quarter 2018 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 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 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 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 fourth quarter 2018 conference call. 2018 was another transformational year for Diamondback. We successfully closed three large acquisitions in the fourth quarter, including our acquisition of Energen, which combined nearly doubled our core acreage position. Diamondback now has over 364,000 net acres in the core of the Midland and Delaware Basin along with another 96,000 net acres of Permian Assets, the majority of which are on the Central Basin platform which we are working to optimize as part of our growing Permian Strategy. Diamondback grew production 53% year-over-year without giving effect to the Energen merger, and exited the year producing over 250,000 BOEs per day in December after closing the merger. Our reserves are up almost 200% year-over-year to just shy of 1 billion barrels of oil equivalent and our organic reserve replacement ratio for 2019 was over 450%. Drill bit F&D was essentially flat year-over-year at $7.28 a barrel and improved developed F&D was $10.44, highlighting the combination of our acreage quality and capital-efficient cost structure. Commodity prices declined dramatically in the fourth quarter, and as a result of this volatility, Diamondback outspent the cash flow for the quarter. This was against our core operating philosophy and we reacted as quickly as possible after closing the merger by announcing a reduction in activity for 2019, subsequently dropping three operating drilling rigs and two completion crews over the course of the last two months. Moving to 2019, we trimmed our capital budget versus previously described expectations in December and we still expect to grow production 27% year-over-year while also paying a 50% larger dividend than we did in 2018, all within operating cash flow. As Michael explained in detail later on in his call, we are realizing more synergies faster than expected after closing the Energen merger, all of which are reflected in our capital budget and projected operating costs in 2019. 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. With these comments now complete, I'll turn the call over to Mike.

Thank you, Travis. Turning to Slides 8 through 10, we give an early update on both the primary and secondary synergies presented when we announced our merger with Energen last August. The highest value primary synergy presented during the merger announcement was a reduction to Midland Basin well cost. Based on the midpoint of our 2019 cost per completed lateral foot guidance for the Midland Basin of $785, Diamondback expects to save $215 per foot versus Energen’s second quarter 2018 actual cost, or over 95% of what we expected to achieve per foot by early 2020 in the merger presentation. This savings is not only attributed to the immediate implementation of Diamondback's best practices on Energen acreage, but also due to efficiencies the Diamondback team has learned and implemented from Legacy Energen best practices. Additionally, the benefit of size, scale, and buying power on service cost has been greater than originally anticipated. Running these savings through 40% of our Midland Basin well count for the year results in almost $150 million in capital savings. In the Delaware Basin, we are seeing enough improvements to move what was originally a secondary synergy into the primary synergy bucket. In 2019, we expect to save between $55 and $60 for completed lateral foot versus actual Energen well cost, primarily due to multi-well pads, longer laterals, completion and casing designs, as well as the cost benefit realized associated with larger scale. Overall, we expect Delaware Basin well cost to decrease by almost 7% versus 2018. Again, due to improved efficiencies, completion design, and service cost concessions. As also seen on Page 8, Diamondback has realized all of the expected $30 million to $40 million of G&A synergies earlier than anticipated, which are fully reflected in our 2019 guidance. Looking ahead, we have line of sight on even more combined capital, operating, midstream, and mineral synergies and we look forward to updating the synergy scorecard with these initiatives in progress. With these comments now complete, I'll turn the call over to Tracy.

Thank you, Mike. Diamondback’s fourth quarter 2018 net income was $2.50 per diluted share, and our net income adjusted for non-cash derivatives and other items was $1.21 per diluted share. Our consolidated adjusted EBITDA for the quarter was $468 million and our cash operating costs were $8.10 per BOE, including LOE of $4.51 and cash G&A of $0.67 per BOE. During the quarter, Diamondback spent $424 million on drilling, completion, and non-operated property, and $101 million on infrastructure and midstream. For the year ended 2018, we spent $1.4 billion on drilling, completion, and non-operated properties and $306 million on infrastructure and midstream. Diamondback ended the fourth quarter of 2018 with $192 million in standalone cash, and approximately $1.5 billion of outstanding borrowings under its revolving credit facility, resulting in $700 million of liquidity. Finally, Diamondback’s Board of Directors has declared a cash dividend for the fourth quarter of $0.125 per common share payable on February 28, 2019, to shareholders of record at the close of business on February 21st, 2019. Operator, please open the line for questions.

Good morning and congratulations to the team on the velocity of synergy capture. Quite impressive.

Thank you, John.

Starting maybe Travis, with your view on share repurchases in the capital pecking order and in particular your share count is up about 70%. Your stock is down about 20% in the last year. So with that in mind, just curious how the company thinks about share repurchases, both with potential monetization proceeds as well as 2020 free cash flow.

Yes certainly John it's key to get to that point first, before we have meaningful conversations with Wall Street, exactly on what we're going to do. But I think, what we've signaled in the past is that shareholder-friendly initiatives such as share repurchases, continued focus on increasing the dividend, all of those things are within our bandwidth of what we can do in the form of returning cash to our investors. And as we progress through 2019, and start seeing the focus on 2020, and the significant free cash flow generation that is going to occur then, I think that's a more appropriate time. But we've committed to continue to grow the dividend and continue to focus on the shareholder-friendly initiatives.

Fair enough. And then second question, I think the original guidance targeted something around $50 WTI to be kind of cash flow neutral. We're a bit above that on kind of strip today. I guess philosophically, the company going to continue to target a $50 type commodity price or would you all average potentially if oil prices remain a bit stronger?

No, I think at this point, John, we know we've got a pretty good long-term strategy laid out at $50 a barrel and I think as commodity prices improve in the back half of this year, maybe into 2020, you could look at us to perhaps add one to two rigs in 2020 and beyond with this significant free cash flow I was talking about. But I think, the point that we made in our December call, which represented a strategic pivot for Diamondback specifically, addressed the waiver free cash flow that's coming, that the pivot is that we're not going to redeploy that all back into the ground. We're going to start returning that to our shareholders. And we began that again this year by increasing our dividend as well. So that's the pivot that we've made, and we're committed to continue to look at that even as commodity prices improve.

Thanks. Congrats again on the quarter.

Great. Thank you, John.

Thanks. Good morning all, and congrats on a strong quarter and outlook.

Thanks, Derrick.

Perhaps for Travis, with regard to your secondary and other synergies, would it be fair to think that those synergies could exceed $2 million in aggregate?

We put a scorecard together, and it's what we call our synergy scorecard. It's on Slide 8 of our investor deck, and we're going to continue to lean into delivering all the synergies that we described in the acquisition call there in August. And look, I'm optimistic that we can continue to improve on all of these metrics. We've talked about in my prepared comments, that we're working on a dropdown from the back to Viper and the midstream assets are all rolled in. So these are all those secondary synergies that we've already got tremendous traction behind delivering on those in 2019. But we're going to continue to update the market on this synergy scorecard and as these things materialize we'll look forward to telling a really good story around these additional synergies above and beyond what we talked about in August.

Yes, I think what's important Derrick is that we base the trade on the merger with Energen on the cost synergies and the execution side of the business. And the other synergies mentioned, minerals and midstream are really more on the financial side. So we predicated the deal on the execution and operation side and that’s where we’re most focused on today.

Great. And then, shifting over to the Delaware regarding the Bone Spring shale well that you guys announced in Pecos, that's a particularly strong well given the decline attributes of that interval. How does that result change your view on capital allocation to the area if at all?

Well, we're certainly excited about that, and the reason we’re excited is that's a zone or a couple of zones we didn't ascribe any value to the original Delaware acquisition. So, we’re excited that we’re seeing really good positive results. And we’re going to be cautious, I mean, as we further define that zone, but I think we probably got a half a dozen or so on the drill schedule this year and we’ll monitor results. And just like we always do, we’ll react quickly if we get greater returns from those zones, we’ll allocate more dollars to the highest rates of return stuff. So, it's good news all around. It’s good news because it's unrecognized upside that we’re now bringing to the table and it's good news for our inventory count in Pecos County.

Great. Thanks for taking my questions and a very strong update.

Thank you, Derrick.

Good morning, everyone. Travis, my first question is about the infrastructure spending. Could you provide some insight into your guidance for this year? I recall there was a higher infrastructure expenditure last year. How do you expect that to trend across the company moving forward?

Yes, Neal, I’ll take this one. Our infrastructure spend and midstream spend is going to be $400 million to $450 million for 2019. Infrastructure is a bit higher on the battery side. If we are doing bigger pads and we’re drilling in areas that have no existing wells. I mean, that was one of the primary reasons we did the Energen trade, was how much completely undeveloped acreage they had and results in us needing to build a lot more batteries than expected. The midstream budget should decline over time and hopefully that’s in a separate business going forward. But overall, probably 60%, 65% first half weighted on the total infrastructure and midstream spend and then 40% in the back half for the year.

Great deals. And then, Travis, just an overall question, you mentioned in the press release about obviously refraining from outspending cash flow, enough to be one of the first two to adjust the plan. I guess when you look at this plan, I mean, how do you sort of balance? I definitely appreciate that. But how do you balance that with more just sort of the continuity or stability of your plan versus changing that rig count or that activity more frequently to keep balancing that?

Well, we’ve got to make sure we don’t interrupt the efficiency of the Diamondback machine. That's one thing that the Diamondback is really known for, is our outstanding execution. And so we can’t disrupt the machine. But by that same token, Neal, we can’t outspend cash flow either. We’ve not done that for four years, but we had an aberration in the fourth quarter last year. We would have actually dropped activity quicker in the fourth quarter last year, but we were on multi-well pads and that makes no sense at all to stop completions on a multi-well pad. So, we take that into account and you typically don't see that from the outside looking in. But we’re committed to capital discipline. This is a mantra that we have been demonstrating since the OPEC announcement in the fall of 2014 and the subsequent price collapse. That's Diamondback, that's what we are known for.

Very good. Thank you.

Good morning. Just looking at LOE and kind of your thoughts on how that will trend around 2019? And then outside of the potential sale of the Central Basin Platform. Are there other things that you are working on to further improve LOE in the future?

Yes. Gail, I’ll let Mike answer that question, but you’ve heard me say before until someone actually plays this to produce these barrels, we’re going to always lean into our LOE and try to make that lower tomorrow versus what it is today. So, I'll let Mike give you the real answer to that. But we always focus on LOE.

Absolutely, Gail. Again, we are attacking it on two fronts, again volume, increasing health as well. But a lot of it's on the dollars that we spend. So again, bringing Energen and Diamondback together, we've done a really good job of grabbing synergies and finding ways to do things better, so there's areas and things that we've learned from the Energen folks that we're implementing today, as well as the other way around. So, what we hope to see is a lower gross dollar amount spend as well as a growing production volume. So, to kind of give you an idea, the Central Basin Platform accounts for about $0.50 of our LOE today. So again, assuming a sale of the Central Basin Platform, that would come off of our guide. But on a go-forward basis again, it's going to be a nice slow drop in LOE, assuming we can implement all of the initiatives that we're working on today.

Great. And then just looking at the potential drop down into Viper, when you look at Diamondback's ownership in Viper, is there an appropriate level that you guys want to maintain on a go-forward basis?

Yes, Gail. I think it's fair to assume that Diamondback owning 59% of Viper, we certainly enjoy owning as much of that business as possible. And if the parent company is generating free cash flow, I don't see a need for the parent company to take back cash in any transaction there. So, certainly I think Diamondback is looking to increase its ownership in Viper post the drop down.

Great. And just one last one, several quarters ago you guys brought up the Limelight prospect and doing some appraisal activity in 2019. I'm just kind of curious how that fits into the portfolio today?

Yes. We're probably going to test it sometime in the middle of this year.

Great. Thanks, guys.

Thank you.

Thanks. Good morning. So I have two questions, one on synergy. Mike, I think you mentioned about increased buying power and just wondering now that you're more scale could you talk about specific incremental efforts on the supply chain, rebidding contracts, etc.? And then, how you are thinking differently about the mix of long-term and short-term contracts?

Certainly. When we examined the two companies separately, we selected different services and vendors based on quality, service, and pricing. We made these adjustments from the start for both Diamondback and Energen. Due to the size and scale of our operations, we've noticed a significant change in costs that correlates with the decline in commodity prices. We've returned to the vendors to bid on a larger package, resulting in increased charges. It's challenging to pinpoint an exact figure, but we've inquired about the difference if Diamondback operated alone, and it appears that about 20% of the cost change is due to our size and scale. Regarding our service commitments, we maintain a hedge book for long-term contracts and well-to-well arrangements, but typically, we're looking at commitments of six months to a year for most services.

Okay. Thanks. And, Travis, as a big picture question, as the industry moves more toward manufacturing style, where do you see use of technology and what are you most excited about? In the last quarter, you talked about dual fuel operation in one of the rigs in Delaware; could you perhaps update us on the economic benefits you're seeing so far in plans going forward?

Yes. I'll let Mike talk specifically about our dual fuel operations, but listen, technology in our industry in particular any manufacturing business can have a chance to make a huge impact on the efficiency of the operations and we think that that's going to happen inside our industry as more and more advanced technologies come to bear. And those things are whether it's the way that we transport fluids, the transport media, the actual proppants, the technology which we steer these wells in zone, the real-time feedback and all the way up to artificial intelligence, these are all things that we believe are going to make a large change in the efficiency of the manufacturing process called producing and drilling for barrels out here in the Permian. I'll let Mike answer the dual fuel question.

So Asit, the dual fuel we are currently running two frac fleets. So dual fuel, we have I believe five rigs currently running dual fuel. So again, where it makes sense, where we have the availability and the equipment already converted, we're making those moves anywhere it makes sense to do it today. On the implementation of new technology, of course, we use real-time data analytics on the drilling side, the completion side, basically all of the things Travis mentioned a second ago, the answer is yes on all of those from how we're doing our processing of our seismic data to how we steer, complete and land these wells. So, the answer is yes, we're seeing a faster change of progress today than we've had in the last decade or two, which is what you would expect. But we see great things coming, we're not going to guide to any of those changes because we don't have them here today, but we're very hopeful for what's coming.

Appreciate the color. Thanks.

Thanks, Asit.

Good. Thanks. Maybe a high-level question: over the last couple of quarters, you've mentioned that you've shifted your focus somewhat toward greater free cash flow generation. How do you view the targets for longer-term free cash flow generation at this point? Is it realistic for you to aim for a free cash flow yield that is competitive with the broader market? Additionally, how do you perceive the timing of this, whether you actively pursue it or if it evolves naturally within the portfolio?

It's really a combination of both; it's going to happen. We've intentionally scaled back our activities to boost our cash flow, and it will also occur naturally as we look ahead. As I mentioned earlier, we are likely to add one to two rigs in 2020 and beyond, while we will still be focused on generating substantial free cash flow, which is what excites us about our new company partnership with Energen. This significant free cash flow generation will begin in 2020 and continue thereafter.

Thanks for the question. As a follow-up, you've historically been a strong consolidator in the basin. How do you view the current mergers and acquisitions appetite and environment, especially now that you've just completed a deal? Earlier, you mentioned that using free cash flow could enable you to pursue more cash-driven deals rather than stock-driven ones. Is that still a key part of your strategy, or has it shifted? Any insights on this would be appreciated.

We are currently focused on executing small trades to enhance our operations, enabling us to drill longer laterals more efficiently. We're also working on swaps and trades involving some of the scattered acreage we obtained from the Energen assets, which our land teams are heavily involved in. From a broader perspective, the M&A scene has been quite subdued. This is largely due to operators needing to align with their cash flow capabilities. The days of acquiring undeveloped acreage with minimal drilling activity, which haven’t proven beneficial for cash flow, are over. While we have a responsibility to our shareholders to seek out valuable deals, at the moment, we aren't seeing many opportunities and are concentrating on smaller trades instead.

Thanks, Travis. I appreciate that.

Hi. Good morning, folks. First question I had is on realizations on slide 13 of your deck. You gave some kind of guidance quarter-by-quarter through 2019. I was wondering, if you could talk about the assumptions I guess, in the first and second quarter of 2019 because you appear to have more Midland exposure in the second quarter of 2019, but you're guiding to tighter differentials. So maybe just kind of broadly talk about sort of what assumptions you have that are underlying this guidance?

Yes, Tim. The assumptions are based on market prices as of last Friday, which you can use to estimate price. Recently, the Midland differentials have narrowed significantly and are expected to remain tight. A few of our agreements will expire at the end of the first quarter, and one will see a reduction in differential at that time. After assessing the substantial expansion of our capacity and understanding enterprise's plans for NGL conversion, we decided to stop entering into fixed differential agreements. We are comfortable having most of our output linked to the Midland market as we have navigated the anticipated takeaway challenges from 2018 and 2019.

Okay, that's helpful. I appreciate that. My next question is for Travis. As Diamondback has matured and with your focus on return on capital employed and free cash flow generation, can you discuss how the Board is considering discretionary compensation metrics for senior management? I'm trying to understand the medium-term priorities.

Tim, I appreciate your comments on transparency. We have built Diamondback on three core principles: best-in-class execution, low-cost operations, and transparency, which have been part of our foundation from the start. I value your remarks about transparency. In 2015, we were among the first companies to shift our compensation focus away from growth in volumes and reserves. We removed those criteria from our scorecard and replaced them with efficiency measures, which serve as proxies for returns, such as return on capital employed. This approach will continue in the future. While we haven't finalized the scorecard for 2019, I expect the Board to revisit the important aspects that drive high returns for our investors while maintaining strong operating metrics and execution standards. This strategy has benefited us well over the past several years.

Okay. And just to provide a bit more clarity, could you explain what you mean by good returns for investors? Are you referring to return on capital employed, cash margin, or something else?

The efficiency measures we implemented in 2015 served as a basis for calculating our return on capital employed. This was done to establish a track record for our return metrics. We've consistently included return on capital employed figures in our investor presentations for quite some time. While we have not finalized our plans for 2019, it will definitely be focused on maximizing returns for our investors.

Okay. Thanks for the comments.

Hi, guys. Good morning. Travis, I was hoping you could potentially frame or just give a little bit more color on the mineral dropdown opportunity. I guess I'm really just trying to get a sense of how impactful this could be for you guys? Thanks.

Yes, Mike. I mean there is a significant amount of minerals still held at the Diamondback level prior to the Energen deal. It's probably about 2,000 net acres that Diamondback just owns still at the parent level. The Energen deal adds another $60 million to $80 million or so of cash flow. So we're trying to right size that deal. I think it's going to be a very sizable trade, meaningful to both Viper and Diamondback and near billion dollar type trade.

I appreciate that. Following up on Gail's question, it seems that the structure of the deal would involve taking more Viper shares compared to cash. Is that the correct way to think about it?

Yes. We've had some discussions at the Board level about how we will achieve that value, but that seems like a reasonable assumption at this stage.

Okay. Great. And then shifting gears to the Northern Delaware, the results there look pretty awesome. And just curious what the game plan looks like for the Northern Delaware in 2019. Maybe we could just talk about expected activity levels, wells put on line, etc.

Yes. I'm really excited about this quarter's release, and while results aren't the main focus, I want to highlight the four wells we've delivered in the Pecos area, which is now the strongest part of Diamondback's portfolio. After managing those four wells, we found they produced over 400 barrels of oil per foot. These are the best wells we've ever drilled. Therefore, that area will receive as much capital allocation as we can provide as quickly as possible.

Got it. Maybe just a quick follow-up on that. Are you comfortable giving kind of a ballpark number how much acreage you have exposed around there?

I'll just kind of talk rig count; we're going to run probably four or five rigs in that area. It's probably 50,000 or 60,000 total acres in the quarter there.

Great. Thanks, guys.

Hi, everyone. I wanted to follow up on the free cash flow comments you guys had made, and appreciate maybe it's too early to talk about specifically how you'll be returning cash, but maybe you can talk about your targets for leverage and if you're still hoping to strengthen the balance sheet further and how your Viper stake plays and how you think about that leverage?

Drew, I think one-time proceeds, asset sales, proceeds from minerals or our midstream business go toward debt reduction at the parent company. Any return to shareholders whether that's a buyback or the dividend should come from true free cash flow in our opinion. We still want to maintain below two times leverage at the parent company on a consolidated basis, but we also don't want to lever up any of our subs about 2 times either.

Thanks.

Good morning, guys. I noticed you guys had a nice upward provision on the drilling inventory number. It looks like you're pushing almost 30 years now inventory. So, just wondering, do you feel that's a good level for inventory or maybe you guys can look opportunistically to monetize some of that tailwind or just high level thoughts on how the right level of inventory for you guys?

Yes, Jeff. We've been very clear on the grow and prune strategy that the Central Basin Platform is certainly up for sale and that process is ongoing. At this point, with the remaining inventory, certainly we would look to dispose of some inventory at the back end of our 30 years of drilling inventory, but we're not actively working on any of that today given the commodity price environment.

I appreciate that. I'm curious about how you see well costs evolving in 2019 and what that might look like for 2020. Can you discuss how current well costs align with your guidance, and provide insight into the year-end outlook relative to the guidance figures?

Jeff, our current costs are largely reflected in our guidance. Moving forward, the situation will primarily depend on oil price activity. Right now, we are having more productive discussions with stakeholders. We anticipate some softening in the upcoming quarter, but the situation in the latter half of the year will ultimately shape our outlook. For the time being, we expect service and well costs to remain stable. We are actively pursuing synergies and initiatives that are expected to materialize throughout the year. Therefore, we expect a slight reduction in well costs over the year, barring any significant shifts in activity levels.

All right. Really helpful, Mike. And just if I can sneak a housekeeping one, can you guys disclose kind of ballpark what the platform assets are producing today?

7,000 to 8,000 barrels a day.

All right. Great. Thanks guys. Appreciate the time, guys.

Thank you.

Hi. Good morning, everyone. Just had one obviously, a lot on the call already, but just curious on the hedging side. Obviously, the debt is a little bit higher now, but you'll be working on some of that opportunities as the year goes on. Where do you guys get comfortable on the overall hedges? The basis is kind of covered, but just where should we be thinking about the hedge profile as the bigger company now moves forward?

Yes, Jason. I believe our strategy has evolved somewhat as we've grown. Previously, our focus was on protecting the minimum capital needed to maintain our acreage position. Now, it is shifting towards disclosing that we need 14 rigs to sustain production, which requires a total capital investment of approximately $1.5 billion to $1.6 billion. Looking ahead, we intend to hedge that maintenance capital, while any additional capital will be exposed to investors for both growth and oil price fluctuations.

I appreciate that. I'll turn it back. Thank you.

Good morning, Travis, you and your team there.

Hi, Charles.

I wanted you to look at Slide 14 and ask a broader question regarding your inventory compared to your peers. You have lower inventory per foot, but I can see that possibly changing in one of two ways: either your inventory aligns more closely with the industry, or you increase your location count to match the industry levels. I have a thought on which way that is likely to unfold, but I’m interested in hearing your view on it.

Charles, we've always approached reserve management, location count, and production guidance with a conservative mindset. Our industry often faces a variety of challenges, typically resulting in reductions rather than additions. From our experience, particularly regarding inventory, it's generally easier to add locations as advancements in technology and results support their viability, rather than removing them. As you've observed with the reserve numbers released this year, they reflect some negative performance revisions within our industry, primarily due to wells being drilled too closely together, leading reserve auditors to reassess those locations. We're confident in our understanding of our inventory, and earlier in the call, someone even estimated we have enough inventory for the next 30 years. Therefore, we don't see an urgent need to increase our location count just for the sake of representation on a map. We're satisfied with our current position and will consider adding locations as warranted by technological advancements and well performance.

Got it. To elaborate on this, Travis, if the industry as a whole has become too dense and is now moving towards greater spacing like what you do, I believe this would likely result in improved individual well performance and increased productivity in the short term. However, in the mid to long term, it may lead to a reduction in the quality of the inventory compared to what was anticipated six to twelve months ago. Do you share this perspective, or do you see it differently?

That's right. That's the way I think about it Charles, absolutely.

Got it. Got it. And then if I could just sneak in one more, you talked a lot about the grow and prune strategy and that makes sense. I'm curious, you've got some kind of far-flung assets whether it be kind of in Southern Upton or Regan or Lee, are those kind of active interests that you're trying to trade now or is the trade activity more in the middle of the development fairways that you're seeing?

It's a combination, Charles, we probably have eight or nine active trades right now ranging from 160 acres swap to 1,000 plus acres swap. So, all options are on the table, the real prune is the Central Basin Platform, but as we talked about Page 14, as long as we can keep working on that average lateral lengths going up with us drilling, 9,400 average lateral feet per well this year to get that inventory number up, our land and BD teams have successfully executed on our grow and prune strategy.

Got it, thanks for that detail, guys.

Thanks, Charles.

Hi, guys. Wondered if you could give a little bit more color around those four, I guess stellar wells that you guys recently drilled, I guess, and completed there on the Energen acreage. I guess, for those prior wells done by the Energen team with sort of their own drilling and completion methods or whether these were done by FANG with your techniques?

Yes, the wells were drilled by Energen. The great aspect of this combination is that our philosophies aligned closely regarding land selection and drilling locations, resulting in wells placed in similar spots to where we would have chosen. However, the actual completion took place shortly after the merger closed. By that time, we had already begun merging some operational groups, leading to a collaborative effort.

Okay. That's helpful. As I was just trying to get a sense of whether or not you guys are maybe doing things a bit different on the completion side and what Energen was doing; you clearly laid out some material cost reductions versus Energen. Just trying to get a sense of whether or not the actual completion designs or methodologies also might be a little different in leading to some better results?

No. I think the beauty of the trade is that we're so confident in the actual well results we're seeing on the Energen acreage. The benefit that we had is on the cost side, so, two organizations that saw eye-to-eye on design and completion size and landing points. But on a cost perspective, combined that's where the real synergies rest.

Okay. That makes sense. And I guess just looking at your fourth quarter production, it seemed very strong for sure, particularly given the fact that you guys are kind of putting these two companies together in the fourth quarter, certainly seems like it stepped up nice momentum into 2019. I was wondering if you could kind of talk a little bit to kind of production cadence during the year. Is the growth kind of more mid-year weighted or back-half weighted in '19 or is it pretty ratable throughout the year?

Yes, Leo. I'll tackle the Q4 performance because I think there are a few important points there. Our base business full year production of 121.4 MBOE per day was significantly above the guidance we presented in Q3. So the base business outperformed by 8,000 to 10,000 barrels a day in Q4 without giving effect to the Energen trade. So I think that was very important. Looking ahead to 2019, we gave a number that the combined business was doing about 250,000 barrels a day in December, once we combine the two companies together. We expect to grow basically ratably through the year. I think D&C CapEx is going to be pretty consistent through the year with some acceleration toward the back half, but we kind of see 20% or so exit-to-exit as being a very important number for us.

Okay. That's very helpful. And I guess just lastly on cash G&A, I guess your guidance for this year is basically below $1 per BOE, couldn't help but notice your fourth quarter number was around $0.67 per BOE, which I guess is quite a bit below. So, should we be thinking kind of closer to that type of number or is it maybe a little bit upward pressure early in the year if you guys have any severance payments made like that?

All right. I think through the year, you can pick a number between that $0.67 and $1 and be in good shape. We just like to say, under $1 because it's such an industry-leading number.

Okay, thanks guys.

Thank you.

Thanks. Appreciate the time. A lot of mine have been addressed. One thing I guess on the people side of the equation. How are you all situated with people now at this point? Obviously, you had a pretty substantial step-up in activity here as you combine the two companies. Are you all set on new hires? How much of the Energen staff came over and just kind of where you are on that front?

Yes, Michael. The operations team for Energen was based in Midland, so around 250 employees transitioned directly into our workforce. We also have some employees in Birmingham who are in the process of moving. They are still handling some basic functions in Birmingham as we close that office. Additionally, we were lucky to have a few employees relocate from Birmingham to our offices in Oklahoma City and back to Midland. We are actively looking to increase our headcount as mentioned. We have top-tier general and administrative expenses, but we will continue to recruit the best talent available each quarter.

Could you provide more details on the distribution of rigs, specifically in the Midland Basin? I'm interested in understanding the rig count across the various sub-operating areas.

Yes. I'd define the Midland Basin into Northern Midland Basin and then Glasscock County and we're probably going to run about a rig and a half in Glasscock County that gets you to 30 to 35 wells for the year and the rest in Midland Basin rigs, 8.5 or so will be in the Northern Basin area. And Midland Basin will be about 55% of our total wells for the year. The Delaware is 45% of total wells for the year, I'd say, rig count wise, 10 to 11 rigs with four of those in the Reeves County Energen block and the rest split between our ReWard and Pecos positions.

Okay, that's super helpful. If I might, just one last on the grow and prune strategy. Where would you say you have the best opportunity for the growth side of that equation as it relates to these trades and swaps, which of these little sub-areas do you think are the most likely to change over the course of the next year or look more blocky, I guess?

I believe our efforts in Spanish Trail North with a series of trades are progressing well, and we are currently focused on consolidating that area. We still need to enhance our ReWard position, and certainly in the Northern Delaware Basin where the legacy Energen holdings consist of many non-operated properties. We prefer to manage operations in that area due to our cost structure, and we plan to actively consolidate and exchange non-operated positions for operated ones.

All right. Thanks very much, congrats on the solid quarter.

Thanks, Michael.

Hi, good morning, guys.

Good morning.

I couldn't help but notice the big increase in your other locations within the inventory breakdown you gave on Slide 14. Can you give some additional detail on what percent of those locations are operated versus non-operated? What intervals comprise this other category? How the locations are split across those various intervals and will development of the other locations compete for capital relative to locations you break out the Wolfcamp, Spraberry and Bone Spring?

Yes. I'll take that one. Energen kept more Wolfcamp C and Wolfcamp B inventory than Diamondback did in the Midland Basin and had more exposure to it than we did for that. So, that makes up a good amount of the other category. Non-operated is about 400 net non-operated locations as well. And that comprises a good piece. Now on the Delaware side, Energen had some Avalon and Brushy Canyon locations where we don't have that in the Southern Delaware Basin.

And then, in terms of this upcoming monetization of Rattler. You talked about the various considerations being made and deciding what percent of the equity you ultimately show.

No, we can talk about that Eli. It's on file with the SEC and we’re going to look at S1 filing online.

Fair enough. Thanks.

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