Good day, ladies and gentlemen, and welcome to the Diamondback Energy fourth quarter 2018 earnings conference call. At this time, all participants are on a listen-only mode. Later, we will conduct a question and answer session, and instructions will follow at that time. As a reminder, this conference is being recorded. I would now like to introduce your host for today's conference, Adam Lawlis, Director of Investor Relations. Sir, you may begin.
Thank you, Talonda. 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 in 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 3 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 basins, 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 divest as part of our grow and prune strategy. Diamondback grew production 53% year-over-year without giving the 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 proved 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 cash flow for the quarter. This is against our core operating philosophy, and we reacted as quickly as possible after closing the merger by announcing a reduction in activity for 2019, and subsequently dropped 3 operating drilling rigs and 2 completion crews over the course of the last 2 months.
Moving to 2019, we trimmed our capital budget versus previously described expectations in December. 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 Mike will explain in detail later on in this 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 eight through 10, we give an early time 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 best practices on Energen acreage, but also due to some efficiencies the Diamondback team has learned and implemented from legacy Energen best practices.
Also, the benefit of size, scale, and buying power on service calls have 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 per completed lateral foot versus actual Energen well cost, those 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 eight, 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 guidances. Looking ahead, we have line of sight of even more combined capital, operating, midstream, and mineral synergies. 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 properties, 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.
Diamondback's board of directors has declared a cash dividend for the fourth quarter of $0.125 per common share payable on February 28th, 2019 to shareholders of record at the close of business on February 21st, 2019. Operator, please open the line for questions.
Ladies and gentlemen, if you'd like to ask a question at this time, please press star then the one key on your touchtone telephone. That's star one if you'd like to ask a question. If your question has been answered and you wish to remove yourself from the queue, you may do so by pressing the pound key. Our first question comes from the line of Jon Nielsen with Goldman Sachs. Your line is open.
Good morning, congratulations to the team on the velocity of synergy capture. Quite impressive.
Thank you, Jon.
Starting maybe, Travis, with your view on share repurchases in the capital pecking order, in particular, your share count's up about 70%, your stock is down about 20% in the last year. With that in mind, I'm just curious how the company thinks about share repurchases, both with potential monetization proceeds as well as 2020 free cash flow.
Yeah. Certainly, Jon, 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. I think what we've signaled in the past is that shareholder-friendly initiatives such as share repurchases, a 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. As we progress through 2019 and start seeing the focus on 2020 and the significant free cash flow generation that's going to occur then, I think that's a more appropriate time. We've committed to continue to grow the dividend and continue to focus on these shareholder-friendly initiatives.
Fair enough. Then the second question, I think the original guidance targeted something around $50 WTI to be cash flow neutral. We're a bit above that on strip today. I guess philosophically, is 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, Jon, we've got a pretty good long-term strategy laid out at $50 a barrel. I think as commodity price improves, 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. I think the point that we made in our December call, which represented a strategic pivot for Diamondback, specifically addressed the wave of 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. We began that again this year by increasing our dividend as well. 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, Jon.
Our next question comes from the line of Derrick Whitfield with Stifel. Your line is open.
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 billion in aggregate?
We've put a scorecard together. It's what we call our synergy scorecard. It's on slide eight of our investor deck. We're going to continue to lean into delivering all the synergies that we described in the acquisition call there in August. Look, I'm optimistic that we can continue to improve on all of these metrics. I talked about in my prepared comments, that we're working on a drop-down from Diamondback to Viper. The midstream assets are all rolled into our Energen midstream assets are all rolled in. These are all those secondary synergies that we've already got tremendous traction behind delivering on those in 2019. 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.
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. The other synergies mentioned, minerals and midstream, are really more on the financial side. We predicated the deal on the execution and operations side, and that's what we're most focused on today.
Great. 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 were certainly excited about that. The reason we're excited is that's a zone or a couple of zones that we didn't ascribe any value to it during the original Delaware acquisition. We're excited that we're seeing really good positive results and we're going to be cautious, as we further define that zone. I think we probably got a half a dozen or so on the drill schedule this year, and we'll monitor results. Just like we always do, we'll react quickly if we get greater returns on those zones, where we'll allocate more dollars to the highest rate of return stuff. It's good news all the way 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.
All right, great. Thanks for taking my questions and very strong update.
Thank you, Derrick.
Thank you. Our next question comes from the line of Neal Dingmann with SunTrust. Your line is open.
Morning, all. Travis, my first question is around the infrastructure spend. Could you talk a bit just in the sort of guide you have for this year? I know you had a bit of a higher infrastructure spend for end last year and how you see that trending now on the FANG corporate-wide going forward.
Yeah, Neal. I'll take this one. Our infra spend and midstream spend is going to be $400 million-$450 million for 2019. Infrastructure's a bit higher on the battery side because we are doing bigger pads and we're drilling in areas that have no existing wells. That was one of the primary reasons we did the Energen trade was how much completely undeveloped acreage they had, and that 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. Overall, it's probably 60%-65% first half weighted on the total infrastructure and midstream spend, and then 40% in the back half of the year.
Yeah, great details. Travis, just overall question, you mentioned in the press release about obviously refraining from outspending cash flow enough to be one of the first to adjust the plan. I guess when you look at this plan, how do you sort of balance I definitely appreciate that, but how do you balance that with more just sort of a continuity or a stability of your plan versus changing that rate count or that activity more frequent 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 Diamondback is really known for is our really outstanding execution. 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, although we had an aberration in the fourth quarter of last year, it's just not part of how we run the business. 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 completion right on a mid multi-well pad. We take that into account, and you typically don't see that from the outside looking in. We're committed to capital discipline.
This is a mantra that we've been demonstrating since the OPEC announcement in the fall of 2014 and the subsequent price collapse. That's Diamondback. That's what we're known for.
Very good. Thank you both.
Thank you. Our next question comes from the line of Gail Nicholson with Stephens. Your line is open.
Good morning. Just looking at LOE and just kind of your thoughts on how that will trend throughout 2019. 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, kind of in that 2024 aspect?
Yeah, Gail, I'll let Mike answer that question. You've heard me say before, until someone actually pays us 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. I'll let Mike give you the real answer to that, but we always focus on LOE.
Absolutely. Gail, again, we attack it on two fronts. Again, volume increasing helps as well, but a lot of it's on the dollars that we spend. Again, bringing Energen and Diamondback together, we've done a really good job of grabbing synergies and finding ways to do things better. 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. What we hope to see is a lower gross dollar amount spent, as well as a growing production volume. To kind of give you an idea, the Central Basin Platform accounts for about $0.50 of our LOE today. Again, assuming a sale of the Central Basin Platform, that would come off of our guide.
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. I'm 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?
Yeah, Gail, I think it's fair to assume that, with Diamondback owning 59% of Viper, we certainly enjoy owning as much of that business as possible. 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. Certainly, I think Diamondback is looking to increase its ownership in Viper post the drop-down.
Great. 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.
Yeah, we're probably going to test it sometime in the middle of this year.
Great. Thanks, guys.
Thank you.
Our next question comes from the line of Asit Sen with Bank of America Merrill Lynch. Your line is open.
Thanks. Good morning. I have two questions, one on synergy. Mike, I think you mentioned about increased buying power. Just wondering, now that you have more scale, could you talk about specific incremental efforts on the supply chain, rebidding contracts, et cetera? How are you thinking differently about the mix of long-term and short-term contracts? That's for my first question.
Absolutely. Again, when we looked at the two entities apart, we went through, we didn't use all of the same services and vendors as well. We went through and grabbed whichever ones appeared to have the better quality, service, and price. We initially did that day one and swapped out some services on both the Diamondback and Energen side. Again, with the size and scale, we have seen a larger change in price associated with the decrease in commodity price that we've seen. We go back, and actually bidding a larger package, we've seen an increase in that change in what we're getting charged. Again, it's a hard number to tie down, but we've gone back to the vendors and business partners and asked if it were just Diamondback standalone, what is that difference?
It looks like of the change, roughly 20% of that change is what we're seeing for size and scale. Now, as far as how long we plan on tying up services, again, right now, just like we do on any other thing we hedge, we keep a hedge book of what we have long-term contracts with and what we have more of a well-to-well. In general, we're looking at six months to a year on most things.
Okay, thanks. Travis, a big picture question. As the industry moves more towards the manufacturing style, where do you see use of technology, and what are you most excited about? In last quarter, you talked about dual fuel operation, one of the rigs in Delaware. Could you perhaps update us on the economic benefits you're seeing so far and plans going forward?
Yeah, I'll let Mike talk specifically about our dual fuel operations. Listen, technology in our industry, and particularly any manufacturing business, can have a chance to make a huge impact to the efficiency of the operations, we think that that's going to happen inside our industry as more and more advanced technologies come to bear. Those things are, whether it's the way that we transport fluids, the transport media, the actual proppants, the technology at 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.
Asit, the dual fuel, we're currently running two frac fleets on dual fuel. We have, I believe, five rigs currently running dual fuel. 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. 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. 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 it, Kaes. Thanks.
Thanks, Asit.
Thank you. Our next question comes from the line of Ryan Todd with Simmons Energy. Your line is open.
Good, thanks. Maybe, a high-level question. Over the last couple of quarters, you've talked how you've shifted your focus somewhat towards greater free cash flow generation. How do you think about a target for longer-term targets for free cash flow generation at this point? Is it reasonable for you to move towards a free cash flow yield that's competitive with the broader market? How do you think about the timing of how that plays out, whether you make a conscious effort toward it or whether it just happens organically within the portfolio?
It's really both. It's going to happen. We've made a conscious effort to do so, that's why we've pared back activity, to increase our cash flow. It's also going to be happening organically as we continue to look into the future. As I mentioned in some of my earlier comments, 2020 and beyond, we probably will add one to two rigs, but we'll still be in the process of generating significant free cash flow. That's what really has us excited about this new company that we've combined with Energen, is just really that significant free cash flow generation that starts in 2020 and beyond.
Maybe as a follow-up to that, historically you've been a material consolidator in the basin and a very successful consolidator. How would you characterize, I know you just closed the deal, but M&A appetite, and the M&A environment at this point? Previously you had commented how the use of free cash would allow you to potentially use some of that cash to fund more cash-driven deals as opposed to stock-driven deals. Is that still part of the strategy? Is it less a part of the strategy than it was previously? Maybe any comments overall on that would be great.
Yeah. Specifically to Diamondback, what we're focused on right now is we continue to do small bolt-on trades to make sure we can operate these units and drill longer laterals and operate them with greater efficiency. We're continuing to do that. The other really business development focus that we're really digging into right now is continued focus on doing swaps and trades with some of the scattered acreage that we acquired through the Energen asset. That's what our land teams particularly are little business development organizations right now doing that trade.
From a macro sense, we think it's been real quiet on the M&A front, and I think there's a reason for that, and that is that all operators are trying to respond to living within cash flow and the days of buying undeveloped acreage with one or two wells on it, in terms of not being able to be accretive on a cash flow perspective, those days are behind us. Diamondback, we always have an obligation to our shareholders to try to look for deals that can create unreasonable value. The bottom line is right now, we don't see any of those deals out there, and we're focused on doing the small bolt-ons and the trades.
Thanks, Travis. I appreciate that.
Thank you. Our next question comes from the line of Tim Rezvan with Oppenheimer. Your line is open.
Hi. Good morning, folks. First question I had is on realizations. On slide 13 of your deck, it gives 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. Maybe just kind of broadly talk about sort of what assumptions you have that are underlying this guidance.
Tim, the assumptions are the market prices on a forward basis as of last Friday. You can use the strip as of a couple of days ago and use that as your assumption for price. Now, the Midland differential's come in significantly in the past couple of months, and it's projected to stay pretty narrow. A couple of our deals roll off at the end of the first quarter. One of our deals goes down in differential at the end of the first quarter. Once we realized how large Plains Sunrise expansion was and got wind of what Enterprise was looking to do on the NGL side conversion, we stopped signing any fixed differential deals.
Leaving that exposure to the Midland market, we're happy for the majority of our barrels to be exposed to that Midland market as we've kind of gone through the takeaway crisis that was expected in 2018 and 2019.
Okay. That's helpful. I appreciate that. My next question, I guess, is for Travis. If you could put your sort of director hat on now. Diamondback has always had one of the more honest and transparent discretionary comp kind of formulas in the industry. As the company's matured and as you talk now about return on capital employed and free cash flow generation
Can you talk about how, if at all, the board is thinking about appropriate discretionary comp metrics for senior management? Just trying to understand what the priorities are over the medium-term future.
Tim, I appreciate your comment on transparency. We built Diamondback around three core tenets: best-in-class execution, low-cost operations, and transparency, and that's been part of us since the very beginning. I appreciate your transparency comments. Really, I think, Tim, what we did in 2015, I think we were one of the first companies to do so in the comp, and it's not just executive comp because we apply the same metrics to everyone in the organization. We changed the comp focus away from growth in volumes and reserves. In fact, we removed those entirely from our scorecard and instead replaced them with efficiency measures. Those efficiency measures are proxies for returns, return on capital employed or other returns measures. That has continued going forward in the future.
While we've not set the scorecard yet for 2019, I anticipate the board to again, come back to the things that we think are important, which is generating high returns to our investors and keeping our operating metrics pristine and our execution still best in class. That's the way we've gone. I anticipate the board to continue to go in 2019. I think it's served us well over the last several years.
Okay. Just to get a little more clarity, you talked about good returns for investors. Can you talk about what you mean? Is that return on capital employed? Is that cash margin? Is that all of those things?
Well, the efficiency measures that we put in 2015, we used them for proxies as the numerator and the denominator for return on capital employed. We did so so that we could build a track record of being able to see what our return measures look like. I think in most all of our investor presentations for the last several quarters, for sure, if not longer than that, we've included return on capital employed measures. Again, we haven't decided what 2019 is going to look like, but it's certainly going to be returns focused towards our investors.
Okay. Thanks for the comments.
Thank you. Our next question comes from the line of Mike Kelly with Seaport Global. Your line is open.
Hey, guys. Good morning. Travis, I was hoping you could potentially frame or just give a little bit more color on the mineral drop-down opportunity. I guess I'm really just trying to get a sense of how impactful this could be for you guys. Thanks.
Yeah, Mike, there's 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-$80 million or so of cash flow. 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 a near billion-dollar type trade.
Okay. Appreciate that. Following on to Gail's question on this, it sounds like the mechanics of that deal would be more of you'd take Viper shares, more weighted toward Viper shares versus cash. Am I thinking about that correctly, or how should I think about that?
Yeah. We've got to have some board conversations on exactly how we're going to realize that value, but that's probably a good assumption at this point.
Okay, great. Shifting gears to the Northern Delaware, the results there look pretty awesome. 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 online, et cetera.
Yeah. That's one of the things I'm really excited about in this quarter's release, it's probably well results are not the focus, I understand that, in anybody's quarterly release. Those four wells that we delivered in the Romayo area, which is quite honestly now the best stuff in Diamondback's portfolio, and we acquired that from Energen. Those four wells, I think they were over 400 barrels of oil per foot. Those are the best wells we've ever drilled. Obviously that area is going to get as much capital allocation as we can put in there as quickly as we can.
Got it. Maybe just a quick follow-up on that. You comfortable giving a ballpark number of how much acreage you have exposed around there?
I'll just 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 core area.
Great. Thanks, guys.
Thank you. Our next question comes from the line of Drew Venker with Morgan Stanley. Your line is open.
Hi, everyone. I wanted to follow up on some of the free cash flow comments you guys had made. Appreciate maybe it's too early to talk about specifically how you'll be returning cash. 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 into how you think about that leverage.
Yeah, Drew, I think one-time proceeds, asset sales, proceeds from minerals or our midstream business go towards 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. We also don't want to lever up any of our subs above two times either. I understand, thanks.
Thank you. Our next question comes from the line of Jeff Grampp with Northland Capital Markets. Your line is open.
Morning, guys. Noticed you guys had a nice little upward revision on the drilling inventory number. Looks like you're pushing almost 30 years now inventory. Just wondering, do you feel that's a good level for inventory? Or maybe you guys could look opportunistically to monetize some of that tail end, or just high-level thoughts on the right level of inventory for you guys.
Yeah. 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. We're not actively working on any of that today, given the commodity price environment.
All right. Great. Appreciate that. Just on the well cost side, a little bit curious how you guys envision 2019 playing out and looking maybe into an early sneak peek at how that flows through to 2020. Can you guys talk maybe a little bit, how do current well costs compare to the guidance that you guys put out? Maybe, how do things look like at year-end, just relative to what's baked into the guidance numbers that you guys have?
Jeff, the current costs that we're seeing today is pretty well baked into our guidance. Going forward, it's all going to be dependent upon typically what activity and oil price does. What we're seeing right now is we're having much better conversations with folks today. We assume some softening will happen over the next quarter at least. Again, it's going to depend on what happens in the second half of the year. For right now, we're planning for basically service cost and well cost to stay flat. A lot of the synergies and initiatives we're working on today will have some timed-out event. What we talked about is what we have today, but we have some other initiatives that we're working on that should come to fruition throughout the year.
We see well costs coming down very slightly throughout the year, unless there's some other change in activity level.
All right. Really helpful, Mike. Just if I can sneak in a housekeeping one, can you guys disclose, kind of ballpark, what the platform assets are producing today?
78,000 barrels a day.
All right, great. Appreciate the time, guys.
Thank you.
Thank you. Our next question comes from the line of Jason Wangler with Imperial Capital. Your line is open.
Good morning, everyone. Just had one, obviously a lot on the call already, just curious on the hedging side. Obviously, the debt's a little bit higher now, you'll be working some of that off, it seems like, as the year goes on. Where do you guys get comfortable on the overall hedges? The basis is kind of covered, just where should we be thinking about the hedge profile as the bigger company now moves forward?
Yeah, Jason, I think our strategy has changed a bit as we've become a bigger company. In the past it was, let's protect the minimum capital it required to hold our acreage position together, and now it's shifting towards, we did disclose this number of 14 rigs to maintain exit-to-exit production, which is about $1.5 billion or $1.6 billion of total capital. I think on a go-forward basis, we're going to look to hedge probably that maintenance capital, and then everything above that is exposure to the investors for both growth and oil price.
I appreciate that. I'll turn it back. Thank you.
Thank you. Our next question comes from the line of Charles Meade with Johnson Rice. Your line is open.
Good morning, Travis, to you and your team there.
Hey, Charles.
I wanted to look at slide 14 and ask you more of a big picture question, particularly about your inventory versus your peers. You guys have ideally the lower inventory per footprint, but I could imagine that converging one or two ways with the industry down to you, or you increasing your location count up to be more even with the industry. I have a guess which way that's likely to converge, but I'm curious what your guess would be.
Charles, the way that we've always managed reserves, location count, production guidance is that we want to be conservative in the way that we communicate, because a lot of things happen in our industry, and typically, they'll always take things away. In our experience, particularly as it pertains to inventory well, inventory count, it's a lot easier to add locations as well results and technology allow those locations to be there than it is to start taking them away. As you've seen the reserves numbers start coming out this year, I think that's one of the first indications is seeing negative performance revisions in our industry, and most of those negative performance revisions are going to be attributed to wells being drilled too tightly and reserve auditors walking those locations back.
We're very comfortable that we have sort of an at least view of what our inventory looks like. Earlier on the call, someone actually calculated a 30-year work to inventory. We don't feel a compelling need to start adding a bunch of locations just in the form of sticks on a map. We're comfortable where we are right now, and we'll add as technology and well results dictate.
Got it. To push a little further on this, Travis, if the industry in general, this is just generally speaking, not the case for you guys, but did get a little too close and they're backing up and going more like spacing more like yours. It seems to me that that would lead to probably better individual well results and more productivity in the near term, but that in the mid to longer term, it'd mean there's less quality inventory than was thought maybe six or nine or 12 months ago. Do you see it the same way, or is that not something you've-
No, that's the way I think about it, Charles. Absolutely.
Got it. If I could just sneak in one more. You talked a lot about your Grow and Prune Strategy. That makes sense. I'm curious, you've got some kind of far-flung assets, whether that be in Southern Upton or Reagan or Lee. Are those 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-acre swap to 1,000-plus acre swap. All options are on the table. The real prune is the Central Basin Platform. As we talked about page 14, as long as we can keep working on that average lateral length going up, with us drilling 9,400 average lateral feet per well this year, if we get that inventory number up via our land and BD teams, we've successfully executed on our Grow and Prune Strategy.
Got it. Thanks for that detail, guys.
Thank you, Charles.
Our next question comes from the line of Leo Mariani of KeyBanc. Your line is open.
Hey, guys. Wondering 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, were those prior wells done by the Energen team with sort of their own drilling and completion methods, or were these done by FANG with y'all's techniques?
Leo, yes, the wells were already drilled by Energen. Again, the great thing about the combination is that we had very similar philosophies on where we wanted to land and drill the well. They landed in very similar spots to where we would've chose as well, the actual completion happened right at and a little after the close. Again, we had already merged some of the operation groups by that time. No, again, a collaborative effort.
Okay. That's helpful. 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 than 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 were so confident in the actual well results we were seeing on the Energen acreage. The benefit that we add is on the cost side. 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. 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. It certainly seems like it sets up for a nice momentum into 2019. I was wondering if you could talk a little bit to production cadence during the year. Is the growth more midyear weighted or back half weighted in 2019, or is it pretty ratable throughout the year?
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. The base business outperformed by 8,000 or 10,000 barrels a day in Q4 without giving effect to the Energen trade. 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 combined 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 towards the back half. We see 20% or so exit to exit as being a very important number for us.
Okay. That's very helpful. I guess just lastly on cash G&A, I guess you all's guidance for this year is basically below $1 per BOE. Couldn't help but notice that your fourth quarter number was around $0.67 per BOE, which I guess is quite a bit below. Should we be thinking closer to that type of number, or is there maybe a little bit of upward pressure early in the year if you guys have any severance payments or anything like that?
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.
Thank you. Our next question comes from the line of Michael Hall with Heikkinen Energy Advisors. Your line is open.
Thanks. Appreciate the time. A lot of them have been addressed. One thing I guess I haven't hit on is on the people side of the equation. How are you all situated with people now at this point? Obviously, you've 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 where are you at on that front?
Yeah, Michael, the operations organization for Energen sat here in Midland, and so I think there was 200 and-
250.
250 there that just rolled right into our mix. We've got some employees that are in Birmingham that are transition employees, so they're still taking care of some of their base functions in Birmingham as we wind that office close. We were fortunate enough to get some folks to move from Birmingham, both into Oklahoma City offices and back here to Midland as well too. We're continuing to look to increase headcount. As Kaes pointed out, we've got industry-leading G&A, we're going to continue to add the best athletes in the draft that we can find on every quarter.
All right. I'm definitely excited to join the team. The other I had was just on the split of the rigs to the extent you guys can provide any more granularity on, particularly on the Midland Basin side. Just curious how we should think about just where in each of those sub-operating areas, how much in each of those areas you'll have from a rig count perspective.
Yeah. I define the Midland Basin into northern Midland Basin, then Glasscock County. We're probably going to run about a rig and a half in Glasscock County, that gives you 30 to 35 wells for the year, the rest of the Midland Basin rigs, eight and a half or so, will be in the northern Midland Basin area. Midland Basin will be about 55% of our total wells for the year. The Delaware, 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, 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 grow 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 think you look at what we did in Spanish Trail North, with a series of trades, and now we're actively blocking that up. I think we still have some work to do around our Reward position, and certainly in the Vermejo or the northern Delaware Basin Energen position, legacy Energen position. There's a lot of non-operated properties around there that we prefer to operate given our cost structure. I think we're going to be actively working to block that area up and trade non-op position for an operated position.
All right. Thanks very much. Congrats on a solid quarter.
Thanks.
Thanks.
As a reminder, ladies and gentlemen, if you'd like to ask a question, please press star then one on your touch-tone telephone. That's star one if you'd like to ask a question. Our next question comes from the line of Eli Kantor with IFS Securities. Your line is open.
Hey, good morning, guys.
Good morning.
Couldn't help but notice the big increase in your other locations within the inventory breakdown you give on slide 14. Can you give some additional detail on what % of those locations are operated versus non-op? What intervals comprise this other category? How the locations are split across those various intervals? How development of the other locations will compete for capital relative to the locations you break out for the Wolfcamp, Spraberry, and Bone Spring.
Yeah, I'll take that one. Energen kept more Wolfcamp C and Wolfcamp D inventory than Diamondback did in the Midland Basin. They had more exposure to it than we did. That makes up a good amount of the other category. Non-op is about 400 net non-op locations as well. 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.
In terms of this upcoming monetization of Rattler, can you talk about the various considerations being made in deciding what % of the equity you ultimately sell?
Yeah, we can't talk about that, Eli. It's on file with the SEC. You're going to have to look at the S1 filing online.
Fair enough. Thanks.
I'm not showing any further questions at this time. I would now like to turn the call back over to Travis Stice, CEO, for closing remarks.
Thanks again to everyone participating in today's call. If you've got any questions, please contact us using the information provided.
Ladies and gentlemen, that concludes today's conference. Thank you for participating. You may now disconnect.