Good day, ladies and gentlemen, and welcome to the Diamondback Energy third 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. If you should require any assistance during the call, please press star then zero for operator assistance. As a reminder, this conference is being recorded. I would now like to introduce your host for today's conference, Mr. Adam Lawlis, Director of Investor Relations. Sir, you may begin.
Thank you, Olivia. Good morning, and welcome to Diamondback Energy's third quarter 2018 conference call. During our call today, we will reference an updated investor presentation which can be found on our website. Representing Diamondback today are Travis Stice, CEO; Michael Hollis, President and COO; and Teresa 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. 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, thank you for listening to Diamondback's third quarter 2018 conference call. Diamondback was able to execute on multiple long-term strategic initiative over the last three months, all while maintaining our focus on near-term execution with best-in-class operating efficiencies and margins. We grew production 9% quarter-over-quarter to 123,000 BOEs a day while decreasing cash costs over the same time period. Our production is now up 45% year-over-year, all from organic growth within cash flow, our updated 2018 production guidance implies 50% year-over-year growth within cash flow. In a world where capital discipline is now the primary theme across North American energy and companies are discussing what they plan to do, look no further than what Diamondback has done over the past three years. Our operating philosophy has not changed.
Maximize production growth within cash flow, maintain best-in-class operating metrics, low leverage, execute on acquisitions accretive to our current acreage position and per share metrics. All of which we continued to do in the third quarter. During the third quarter, we announced our transformational combination with Energen. As an update, we have received regulatory approval for the merger, the shareholder meetings are scheduled for November 27th, with the deal expected to close shortly thereafter, pending shareholder approval. We are currently operating 14 rigs, Energen is currently operating 10 rigs, both split evenly between the Midland and Delaware basins. We see this rig count as the baseline for our 2019 operating plan as we integrate the merger and work to instill best practices across the pro forma company's asset base.
We will begin delivering on the primary synergies presented in our merger presentation immediately. Our 2019 capital and production guidance will reflect this pro forma cost structure, which we will look to present in the coming months after the merger closes. We were also able to close multiple significant acquisitions in the northern Midland Basin, including the previously announced Ajax acquisition and the recently announced ExL acquisition. These acquisitions add 25,000 Tier 1 acres to our existing inventory and have three zones with greater than 100% IRRs at current commodity prices. The blocky complementary nature of these assets gives us significant running room for capital efficient, long lateral development. Because there are minimal drilling obligations across the block, we can run multiple rigs, drilling large multi-well pads and efficiently develop the reservoir.
Diamondback will continue to look for assets complementary to our existing asset base that compete for capital right away within our existing portfolio at acquisition prices that allow us to generate full cycle returns well in excess of our cost of capital. With the size and scale of our pro forma business, we will look to continue to grow production differentially within cash flow, add inventory and acreage without compromising our balance sheet, and grow our return of capital program through our dividend. With these comments now complete, I'll now turn the call over to Mike to discuss our operational highlights for the quarter.
Thank you, Travis. In the third quarter, Diamondback continued to execute on both our near-term and long-term crude marketing strategies. In the near term, we have over 100,000 barrels per day of gross production locked in firm transportation agreements with multiple third parties. These deals have been signed over the last six months and have various fixed differentials to Gulf Coast pricing, including deals linked to Brent and MEH. In general, pricing is expected to be the weakest in the fourth quarter this year and the first quarter of next year, with pricing improving throughout the remainder of 2019. When the EPIC Pipeline project completes its early in-service construction, Diamondback will benefit from space on that pipeline and overall lower differentials through the back half of 2019.
With respect to our long-term oil marketing strategy, we now have over 200,000 barrels per day of space between the Gray Oak and EPIC Pipeline projects, with 50% of this space take or pay. We also have a 10% equity interest or equity option in both projects held at our subsidiary, Rattler Midstream. This incentivizes Diamondback to efficiently utilize our long-haul space on both projects. We expect the Gray Oak project will move all of our anticipated production from Diamondback's current Delaware Basin position to the Gulf Coast, and that the EPIC project will move most of our anticipated production from our current Midland Basin position. We have proactively worked with our marketers to secure a true wellhead-to-water solution with reserved tankage and export capacity needed on the Gulf Coast. These deals remove the Midland market risk from our future while building our midstream business via strong strategic partnerships.
In the third quarter, we also executed a joint development agreement with Carlisle for the development of the San Pedro area of our Pecos County asset and have started drilling with one rig. This strategic partnership will allow us to bring value forward from an area that does not currently compete for capital, while also benefiting our midstream and minerals businesses. We look forward to a long, successful partnership with Carlisle developing this acreage block over the coming years. In true Diamondback fashion, we've had an extremely busy and successful third quarter. I'd like to take this time to thank all of the Diamondback staff for leaning in together to make this happen. With everything we've accomplished this quarter, the teams never missed a beat on execution. Diamondback completed over 414,000 lateral feet this quarter across 43 wells with an average lateral length of over 9,600 feet.
We operated 13 rigs and five frac crews throughout the quarter. We began testing the use of 100% local sand in the Delaware Basin and will continue to monitor both our results and offset activity. In the Midland Basin, we are using local sand for all three of our completion crews and realizing roughly $60 per lateral foot of savings. We have also begun dual-fuel operations on one drilling rig and one frac crew in the Delaware Basin, supplementing higher cost diesel with cheap natural gas. If the use of dual fuel continues to make economic sense, we have five drilling rigs and two completion crews with these capabilities currently in our fleet.
Moving to well results, we are excited to announce two successful tests of the Second Bone Spring in Pecos County and look forward to continuing to prove up this zone as a secondary target to the Wolfcamp A. We also announced a Wolfcamp A result on the eastern third of our Pecos County acreage that early time is as good as any well we have completed across the acreage block. Regarding our capital budget for the year, we are increasing our overall budget by 6% at the midpoint of our range due to an increase in our infrastructure and midstream budget for the year. This is primarily due to the continued build-out of our midstream infrastructure in the Delaware Basin, the added infrastructure from the execution of our joint development agreement with Carlisle, as well as our overall increased rig count exiting the year.
Please note all of this investment has been done within cash flow. Over time, the infrastructure spend as a percentage of total capital in the Delaware Basin will begin to move from current levels to a rate that more closely represents what we achieve in the Midland Basin, roughly 10% of total capital. With these comments now complete, I'll turn the call over to Teresa.
Thank you, Mike. Diamondback's third quarter 2018 net income was $1.59 per diluted share, and our net income, adjusted for non-cash derivatives and other items, was $1.67 per diluted share. Our adjusted EBITDA for the quarter was $372 million, and our cash operating costs were $8.70 per BOE, including LOE of $4.34 per BOE and cash G&A of $0.78 per BOE. During the quarter, Diamondback spent $321 million on drilling completion in non-operated properties and $74 million on infrastructure and midstream. Year to date, we have spent $934 million on drilling completion and non-operated properties and $205 million on infrastructure and midstream, while generating free cash flow of $12 million excluding acquisitions. Diamondback ended the third quarter of 2018 with a net debt to Q3 annualized adjusted EBITDA ratio of 1.2 times.
After adjusting for the closing of the Ajax, ExL, and EnergyQuest acquisitions on October 31st and our increased credit facility of $2 billion, we ended the quarter with roughly $1.3 billion of liquidity. Finally, Diamondback's board of directors has declared a cash dividend for the third quarter of $0.125 per common share, payable on November 26th, 2018, to shareholders of record at the close of business on November 19th, 2018. Operator, please open the line for questions.
Thank you. Ladies and gentlemen, at this time, if you have a question, please press the star then the number 1 key on your touchtone telephone. If your question has been answered or you wish to remove yourself from the queue, please press the pound key. To prevent any background noise, we ask that you please place your line on mute once your question has been stated. One moment for our first question.
Our first question coming from the line of Neal Dingmann with SunTrust. Your line is open.
Good morning, all. Travis, my first question for you occasionally, guys. Can you discuss, it seems like a strategy that's really going to pay off longer term. I want to dig a little bit more into your Wellhead to Water Strategy. Specifically, could you talk about I know there's a lot of factors involved as far as the storage and everything at the ship channel, all the way to making sure you have the proper storage on the ship and everything itself. Again, I know it may be a bit premature for that, I'm just wondering if you could just give the highlights as far as what you all deem the benefits of a strategy like this versus what options some others are taking at this point.
Sure. Well, the strategy that we've outlined a couple of times on our Wellhead to Water Strategy is not one that sacrifices anything near term, for long-term gains. I think we've really advantaged our investors with the way that we've set this structure up that allows us to ensure we've got firm transportation. We now have equity ownership in two pipelines that's going to sit within our Rattler Midstream, really think that this strategy long term is going to be seen as a really creative strategy that drives differential value to our shareholders.
Yeah. I think long term, Neal, the upside for us is not one of our barrels on our current position will touch the Midland market for the foreseeable future. If you think about the systems that we're going to be on and the long-haul systems we're going to be on, we're going to be paying ourselves via our equity ownership to move our barrels to the water. Essentially, we're getting to Corpus Christi almost for free. Then, that's where the experts take over. We're not an exporter. We're not a marketer. We have some strategic partnerships with exporters to handle those barrels from then on. In the near term, we used that scale and our commitments to those pipes to secure firm transportation in the near term in what is a pretty tight market in the Permian this year.
Now we have over 100,000 barrels a day of gross production protected at fixed discounts to Brent and MEH to get us through the next couple quarters. Once EPIC comes on in Q2 or Q3 next year, the diffs start to ease and we'll start to maximize the benefits of these investments.
Okay. Great call. Then maybe just my second one for Mike. Mike, looking at that slide five where I'm sorry, slide 14 actually, where you talk about the takeaway and more about the landing zones that you're showing in the Southern Delaware. Could you talk about, I think you mentioned in here about the high-graded landing zones, but specifically if you could talk about the thickness when you look at the Bone Spring versus the Wolfcamp A, B, and C, how important is it to have this high-graded landing zone in order to achieve the highest results?
Absolutely, Neal. 3D seismic, we've just got some high-resolution 3D data that's in, we're utilizing that for our targeting. It's giving us the ability to stay well within that premium target in both the Wolfcamp A and the Bone Spring. Again, thickness is important, but where you are within that thickness and the rock quality is very important. We continue to refine our model and continue to place these wells where we're able to test it and get that data so we can adjust as we go forward. From the well results that we've been able to publish and show you guys, the work that we're doing down in Pecos County is really paying off.
Great. Thanks so much, guys.
Thank you. Our next question coming from the line of John Nelson with Goldman Sachs. Your line is now open.
Good morning, congratulations on the update.
Thanks, John.
Travis, our math says the market's only giving Diamondback credit for about $600 million of the more than $2 billion of synergies you all detailed alongside the Energen acquisition announcement. I guess my question is, one, how, if at all, do you view the execution risk of Energen different from the numerous other acquisitions the team's previously executed on? Two, can you maybe walk through a timeline for achieving some of the synergies that you outlined?
Yeah. I think we had it in our prepared remarks, John. We anticipate when we update to market on our 2019 guide that the synergies that we outlined in our acquisition presentation, that's what to expect. Organizationally, that's the challenge that's been placed in front of us. Look, every time Diamondback has made a pivot or done a large acquisition, there's always been in front of us a hurdle of execution. Our track record has always been to address that challenge, and we've overcome it every time while we've had flawless execution. This is a larger acquisition, yes, but we're a larger company as now as well, too. I feel really confident about the synergies that we outlined. It's $220 a foot on the Midland Basin wells. Obviously, the acquisition hasn't closed yet, but we're seeing things.
I would say that the Energen organization exited really hot as this merger goes through. I couldn't be more excited about how the integration is going, the opportunities in front of the pro forma company to deliver on those primary synergies. Look, we also outlined $2 billion of secondary synergies as well too, in that acquisition presentation. I think those are going to become more and more real over time as we get some of these strategic initiatives executed upon. I'm just really excited about what this pro forma company is going to be able to do in the upcoming quarters.
That's great. Just to push a little bit, I think the timing on beginning to see the Midland Basin D&C and some of the G&A was Q1 in early 2019. Is that still kind of a fair target? As you started to work on and getting further along and evaluating or integrating with the teams, is there any reason to believe that that'll be a little bit later to be achieved?
No, John, we plan our 2019 guide, cost per lateral foot to be what we're doing today with 14 rigs across the 24-rig program. On the G&A side, we plan our $ per BOE guidance to be in line with what we've done traditionally, which is less than a $ per barrel.
Perfect. Just the second question. The infrastructure spend is now more than 20% at D&C capital. Mike, you hit on it in your prepared remarks, that should migrate to 10% over time. Just thinking over the next 1 to 2 years, how should we think about that trajectory to get down to that long-term target?
Yeah, John, on slide 17, we put out a little comparison of the Midland and the Delaware Basin. We're five years into a horizontal program in the Midland Basin. Now the infrastructure dollars as a percentage of total are a much smaller amount, down to about 8% of total. The Delaware Basin, when we bought that asset, really it was a new country out there in Pecos County and Reeves County. No infrastructure in place. We've been spending a lot of money out there over the last two years. You see that the Delaware is about 28% of total capital out there this year. As our rig count ramps and the amount of batteries we have out there, the electricity is in place, the oil gathering system's in place, that number will decrease over time and hopefully be less than 10%, probably by 2020.
Perfect. I'll let somebody else hop on. Congrats again.
Thanks, John.
Our next question coming from the line of Derrick Whitfield with Stifel Financial. Your line's now open.
Good morning, all, congrats on a strong quarter.
Thanks, Derrick.
Reading between the lines, you guys are clearly excited about the Spanish Trail North asset and the potential of the Middle Spraberry there. What level of activity should we assume for this area broadly as we look out to 2019 and 2020?
Derrick, we'll be looking at two to three rigs. The assets we had there before, we were running between one and a half. When we added the additional 25,000 acres, it's reasonable to expect about one rig per about 10,000 acres. You'd have somewhere in the three to four rigs running in the area going forward.
I think the other thing, Derrick, that we tried to highlight in the prepared remarks was the fact that the lease obligations here are minimal, and so we can actually take a rig and park a rig there and develop multi-well pads. I think we've talked previously about a 12-well pad, and that's what we intend to do is park a couple of rigs there developing these 8-12 well pads one right after another. Again, that acreage has three zones that at today's prices has greater than 100% rate of return. From a capital allocation perspective, those projects are going to compete in the top quartile, if maybe not even the top 15%, top 10% of Diamondback's overall portfolio. Look to us to accelerate and lean in on that one as hard as we can.
Great. Great update. Regarding the Second Bone Spring wells that you discussed in your press release, could you comment on the targeted zone within the Bone Spring formation and your AFEs on those wells?
Derrick, yes. The AFEs are, again, when we drill these wells, are shallower. They're a little bit lower pressure than the Wolfcamp A. We see somewhere in the $800-$1 million difference. Again, as we continue to use local sand in the area, we'll be able to realize a little bit more of that savings. As far as the targeting, we do hit several targets in the Bone Spring, so we'll actually wine rack some in what we call an upward and lower. Again, as we continue to develop this, we have three wells in the area right now, so we don't have a whole lot of development to be able to talk about, but we wanted to delineate some acreage across the acreage plot.
Great. Thanks. Very helpful, guys.
Our next question coming from the line of Drew Poffel with Morgan Stanley. Your line's now open.
Good morning, everyone. How do you think about setting your capital program and the balance between growth and return of cash and thinking also about just the free cash flow profile? Should we think about that as increasing over time and then a corresponding slowing of the pace of rig additions?
Yeah, I think we've been pretty clear what our strategy has been. We're going to continue to allocate capital to high rate of return projects within cash flow and pay a dividend. The rig count right now is 14 from Diamondback and 10 from Energen. That's going to be the initial allocation of capital. We'll look depending on commodity price and free cash flow, we'll look to if we need to increase that in the back half of 2019. Look, I think we're on the cusp really of having created what we feel like is a really special oil and gas company because not only can we generate peer-leading growth, we can also grow our dividend, and we can do both on our acquisitions all within cash flow, and do so with less than a turn of leverage.
We think that's pretty special, and we think that's a strategy that's going to carry this company forward for multiple years, if not decades to come. We think that's what the generalists have been looking for. That's what the specialists in energy space have been looking for. I think Diamondback has touched all of those levers as we've matured as a company.
Thanks for that, Travis. In terms of the Howard County lawsuit with Energen, is there anything you can really share there as far as timing, and then how you guys would proceed with either acquiring the acreage in full or some other structure to move ahead with development there?
Yeah, Drew, we can't talk too much about it. Energen did put out an 8-K about 10 days ago that the Court of Appeals had ruled in favor of Energen in that lawsuit. I think the counterparty has the opportunity to appeal that sometime over the next 30 days. We're going to be waiting patiently and hope this deal comes to a resolution in some shape or fashion.
Thanks.
Our next question coming from the line of Mike Kelly with Seaport Global Securities. Your line's now open.
Hey, guys. Good morning.
Good morning, Mike.
A specific one for me. Just if I look at your updated production guidance for 2018, could you guys give us a sense of how much of that roughly 2,000 barrel a day increase is attributable to these acquisitions you're folding in here, Ajax and ExL? I was a little unclear on that. Thanks.
Yeah, Mike, this Kaes, I'll take this a further step back. If you look at when we came into the year, we guided midpoint of 112,000 barrels a day of production. The new midpoint of our guidance is 119,000 barrels a day of production. Even if you take all the Ajax and ExL production together, let's just say it's about 12,000 barrels a day today for two months of credit, that would be 2,000 barrels a day of production out of that 7,000 barrels a day we raised. More specifically for the year, we're organically raising our production guidance by 5%. Going into the year, we were going to grow 40% within cash flow. We're now going to grow 50% within cash flow, all due to the outperformance of well results.
More specifically to Q4, we raised our guidance last quarter for the Ajax acquisition by about 4% at the midpoint. We raised it again this quarter by 2%. I'd say 25% of that 2% is attributable to ExL, which is about 500 barrels a day-600 barrels a day out of the 2,000 barrel a day increase.
Awesome. All right. That's a lot of detail. Appreciate that.
I'd say 30% related to acquisitions for the year and 70% of the growth related to organic growth for the year.
Okay, great. Appreciate that color. Another one to be fairly granular here. On the differentials, you guys were a little more than $13 off WTI in Q3 on the oil front. I think Mike mentioned that Q4, Q1 still have the Midland exposure. Not going to be that pretty, but things start to change in 2Q with all these fixed-term contracts and once you get oil on pipe. Could you maybe just frame it for us a little bit, how you expect to ultimately see those oil realizations trend, maybe the end of 2Q and the second half of the year, where you could be relative to WTI, incorporating everything you laid out to us? Thanks.
Yeah. I think Q4 will look better than Q3 because of the improvement in the Midland market. We have two deals that priced in the second quarter that were at fixed differentials to MEH over that quarter. Those deals are in place throughout first quarter next year and through all of next year. We have some other deals currently pricing that are looking better because the Midland market has improved. Overall, I think Q4 differentials to WTI will look better than our Q3 differential, but tightening through Q2 of next year. When the EPIC pipe comes on early, we'll have space on that, and that kind of clears the basin until the other large pipes, Cactus and Gray Oak, come on.
When that all is said and done, K, do you think that incorporating the fees you're going to have to pay to actually get the crude to the coast, do you have a sense, can you frame it in terms of what you'd expect to be priced at relative to WTI, incorporating transportation?
I think I'll take it a different way in that we'll be at a Gulf Coast price less about $3 or $4 to get to Corpus Christi. Of that $3 or $4, we're going to pay ourselves probably 65% of that with our equity interest in the pipes and our ownership of in-basin gathering with Rattler.
Got it. Perfect. Thanks a lot, guys.
Thanks, Mike.
Our next question coming from the line of Asad Syed with Bank of America Merrill Lynch. Your line's now open.
Thanks. Good morning, guys. A 200 related question. In the past, Travis, you've talked about grow and prune strategy. Looks like you've added some nice acreage. On pruning, what are the areas that are primed for high grading and your thoughts or early thoughts on Central Basin Platform near-term?
I think also that if you look on any of our presentation, any slide in our presentation that has those ellipses around the, what we're calling our core areas, core development areas. Anything outside those circles or ellipses are what we're considering as assets that are available for pruning. Now, the first thing we're going to do, and we were clear with this during the acquisition or with the Energen presentation, is that our first is to try to swap and core that out. To the extent we can't swap and core that out, it becomes divestiture candidates. Look, Central Basin Platform, we've essentially called that reserve for sale, and we'll start that process as quickly as we can after the merger closes.
Great, thanks. On the dual fuel opportunity, which switched to natural gas, looks like you're trying on one rig, potential to go up to five rigs. Early thoughts on reliability issues and potential savings that you expect?
Absolutely. Reliability, the diesel engines, they have no issue running natural gas as part of the fuel stream. We can run upwards to 60%, maybe as high as 70% of the fuel stream as natural gas as opposed to diesel. Savings wise on completion crews, again, it depends on the size of the job and whether it's Midland or Delaware. In general, roughly about $100,000 a well or $10 a foot. On the drilling side, of course, we use a lot less diesel on the drilling side, so it's somewhere in the $15,000 to $20,000 a well range there.
Very helpful. Thanks, Mike.
You bet.
Thank you. Our next question coming from the line of Tim Rezvan with Oppenheimer. Your line's now open.
Good morning, folks. I'm trying to get some context on the ExL tack on you announced last night. You highlighted acreage and production. You also mentioned related assets. Can you talk about what those related assets are? Is it infrastructure or kind of minerals? Just trying to understand that value in relation to the total price.
Yeah. Nothing major, it's just some infrastructure and batteries that came with the acquisition.
Okay. Those will get folded into, I guess, into Rattler.
Correct. Yes.
Okay. If we just step back a little bit, Travis, you've been pretty clear about this growth within cash flow approach, and you've sort of hinted at dividend growth moving forward and talked about capital discipline. At the same time, there've been over $1 billion in acquisitions announced in the last 3 months, separate from Energen. How do you think about when or how Diamondback Energy might sort of dial down the resource capture? I guess, do you think that this acquisition appetite kind of muddies the picture for investors who are looking for clarity on capital discipline?
Well, I was proud to be clear that the acquisitions we do, we would do so without putting the balance sheet at risk. Again, if you go back and look at our history, you've always seen we've maintained a fortress balance sheet for just these type of opportunities. Look, this, what we're calling now the Spanish Trail North, that was just too good of an opportunity not to have transacted on it. We felt like we had differential knowledge in the area because of our legacy activity. We felt like we had willing sellers that weren't marketing the process broadly, and we felt like we could bring our expertise in to wells that could immediately compete for capital right away.
Going forward, Tim, I said during the Energen merger presentation that Diamondback Energy, in a large sense, is going to be on the sidelines on the acquisition front, and that's essentially where we are right now. We understand what our challenge is in front of us, and that challenge is very clearly defined as execution. Throughout, really now both organizations, we understand that the battle lines are drawn for us to execute on those synergies, which is why I spent so much time detailing the synergies and our plans for the timeframe for when we're going to deliver on those. Look, I think we've got a lot of things going very positive direction for Diamondback Energy, and I think we really like our inventory and where it sits right now.
Like I said, we're more or less on the sidelines until we get this merger integrated and start delivering materially on the synergies that we talked about.
I'll add that tuck-in acquisitions like the ExL acquisition that make a lot of sense are just going to be part of our core operating philosophy. Capital discipline probably has a couple definitions in the market. To us, capital discipline is not outspending our cash flow. DC&E CapEx plus infrastructure plus our dividend, which is small but continuing to grow, equals our operating cash flow. That's our mantra of capital discipline. We expect our investors to expect us to do deals that have great full-cycle returns and compete for capital right away with our existing inventory.
Yeah, these acquisitions, Tim, are immediately accretive. Listen, you've covered us for a long time, Tim, and you know that the capital discipline mantra is not something new. As I pointed out, we're 15 quarters in a row right now of being capital disciplined, in terms of spending less than we make. I think that's a unique commentary in the energy space right now, 15 quarters in a row. Essentially, after the oil price collapse in 4Q of 2014, this capital discipline has been fundamental to our capital allocation strategy. In not one single quarter have we deviated from that strategy. I think any of our investors that have known Diamondback understand that capital discipline is believed because of not what we say, but because of what we have done.
Okay. I appreciate that context. Just sort of to close the loop, I guess if you're running models through 2020 and you have a decent commodity price, you can see pretty healthy free cash flow. Besides a dividend, we should look to you all sort of putting that to work on opportunistic resource capture. Is that kind of how you're thinking about that free cash flow?
That's one of the levers that we can crank on. Look, the return of capital to our investors is a real strategy that we at the board have discussed, that return of capital can take many forms, but it's real within Diamondback, it's visible when you look at 2020 and beyond.
Okay. Appreciate all the context, folks. Thank you.
Our next question coming from the line of Jason Wangler with Imperial Capital. Your line's now open.
Hey, good morning, everyone. Appreciate the update on the Energen plans and kind of on 2019. As you look at that 24 combined rigs, do you expect to keep 14 on your properties and 10 on Energen to start, or how do you think of the allocation of those rigs going forward?
Yeah. These drilling schedules, while we like to think they're immediately flexible, in fact, they're really about six months to nine months out in front. Once the merger goes through, we're going to continue operating the 14 Diamondback rigs on the Diamondback properties and the 10 on the Energen properties. It probably won't be until late 2Q or the back half of the year before we're able to start modifying the drill schedule substantially.
Okay, that's helpful. Obviously, you talked a bunch about the infrastructure spend on your end and as you grab the Energen assets as well. Can you talk about where they are in the stage of that life cycle? Do you see a significant amount of spend that you'd need for them as you look at 2019 and closing that deal, or do you think it'd be comparable to what you look to spend on the Diamondback assets next year and going forward?
Actually, what's been exciting to us is to see how much they have in place. They've been really smart about how they've built their infrastructure, especially in the Delaware Basin, where they have probably twice or three times the SWD capacity that we have today. They've been operating in the Delaware for a long time, and they've set up a great infrastructure system. I'd expect their percentage of total capital to be closer to our Midland Basin percentage of total capital. The thing with us in the Delaware Basin, 100,000 acres with really nothing on it. We had to put electricity, oil, gas, water, SWD all in over the last 24 months. It's going to benefit us long term with realizations and LOE and midstream value creation.
It's just a lot of money we're spending as a percentage of total in the Delaware at the moment.
I appreciate it. Thank you.
Our next question coming from the line of Phillips Johnston with Capital One Securities. Your line's now open.
Thank you. Good morning. A lot of my questions have been asked already, Travis. Just going back to the D&C costs for next year, I believe it was mentioned that intend to basically use current Diamondback D&C costs for the entire program next year. Are you seeing any meaningful cost pressures anywhere on the D&C side, even if they're being offset by other efficiencies?
Richard, this is Mike. The quick answer is yes. With oil price increasing, we obviously see service costs go along with that, steel tariffs and all of those that are in place today. Going forward, absolutely, in our budget, we are taking into account some of the inflationary pressures. However, we also take into account the cost savings from local sand, some of the pressure pumping deals that we have in place today, as well as some of the operational efficiencies that we have our eyes set on today, as well as when we get to working on those. The answer is yes. We're going to take current pricing that we have today and our current structure, apply it as well to the Energen properties. Going forward, yes, there will be some inflationary pressures coming.
Thanks, Mike. Just one last one. It looks like the industry takeaway bottlenecks are on track to be relieved in the second half of next year. Looking longer term, seeing any other potential issues that could slow the strong industry growth projections over the next couple of years, whether it's on the water side, et cetera?
Richard, we're doing everything we can to be ahead of all these issues. There's always going to be a new issue in the Permian. I think NGLs are getting solved. Crude is getting solved, which for us is the most important, and gas is getting solved by the end of 2019. We've put a lot of water capacity into our systems in the Delaware Basin, and we're getting ahead of our growth ramp so that any issues that do present themselves, we're looking to be ahead of. I think we have a rule of thumb that we try to stay two years ahead of major issues.
This oil gathering or oil takeaway issue crept up on us faster than we expected. We've now solved it, and I think all of our barrels and growth barrels projected are going to have a nice home on the water for a long time.
All right, Kaes, thank you. That's all from me.
Thanks, Richard.
Our next question coming from the line of Charles Meade with Johnson Rice. Your line is now open.
Good morning, Travis, to you and your team there. I wanted to explore a little bit maybe your future plans in that new Spanish Trail North area you've created. You've done a great job assembling that in what seems like pretty quick fashion. It strikes me as I look at the map, you've got perhaps a chance to extend that towards the southeast, and to connect the dots with that energy position that's there, central or northwest Martin County. Can you help us calibrate our expectations on not just maybe your appetite to do that, but also the possibility of, are there sellers in that spot?
We think we've been pretty opportunistic in putting this position together, and we've now got over 25,000 Tier 1 locations that all are set up for 10,000 oil plus laterals. As Kaes highlighted earlier, we'll continue to be opportunistic to do bolt-on deals and for a plus $20 billion market cap company on a pro forma basis. These tack-on deals can be relatively large from historical perspectives. We couldn't be more excited about that Spanish Trail North area, and we're very pleased with what our position looks like right now. We'll be opportunistic to do small tuck-ins and bolt-ons if they're accretive, and they make sense for our development scenario.
Charles, as far as connecting the dots, whether it's with the acreage in between or whether we can do it with our infrastructure, we'll take advantage of that anytime it makes sense. We'll tie in things like oil gathering, SWD capacity, and take care of that so we can increase our ability to move fluids from one place to another. We do that across all of our other acreage, and I think it would be reasonable to expect here that we'll do the same thing.
Right. It's one of those advantages of scale you guys have been talking about. If I could ask on my second question, going back to your comments in the prepared remarks about those, I believe it was Neal Lethco wells in Pecos County on the eastern third of your acreage. Can you talk about whether those wells have in any way changed your view of the surrounding area, either by de-risking some inventory or perhaps alternatively high-grading some of that inventory over there?
Charles, it confirmed our initial assessment of the area. No, it really hasn't changed any of our plans. Again, it's very productive in that area. It's to the eastern side. It also makes us excited about what may happen down in what we call our San Pedro area, even further to the east and south of there. Again, it's exciting to see the productivity across the entire acreage block.
Yeah, I think it's important to remember that we're very early in the Delaware Basin, probably 80 wells into a 3,000-well program. Our geos and reservoir engineers and ops team, they're all learning a ton as we start to ramp up there. We started with two rigs, and now we're running seven rigs across the Delaware. Certainly learning things every well we drill.
That's helpful color. Thank you.
Our next question coming from the line of Michael Hall with Heikkinen Energy Advisors. Your line is open.
Thanks. Good morning. Excuse me. Just kind of curious as we think about 2019 and the activity profile, relative to the efficiencies we've seen of late. I think in the third quarter, you completed something a little over 400,000 lateral feet with the 13 rigs and five crews. Is it fair to just scale up that kind of quarterly footage completed with the new equipment profile for 2019? Or do you think it will take a dip down as you integrate the new assets? Then when would it normalize if that's the case?
Well, Michael, we think about it on a completed lateral feet per crew per day. On the Midland Basin side, our crews right now average about 1,400 lateral feet per day. That includes all move time throughout the quarter. On the Delaware side, we're closer to 900 lateral feet per crew per day. We're running five crews right now. Post-acquisition or merger completion, we'll probably run 10 crews, and those crews will be about evenly split between Midland and Delaware, five and five. We expect those operational efficiencies to hit right away.
That's helpful. Then I guess, on the wellhead-to-water strategy, what, if any, additional details can you provide on the water side of that equation? What exactly have you secured? What sort of contracts have you taken on? Where does that end, I guess, in the value chain as it relates to Diamondback?
Yeah. Our expertise ends when the pipe ends, then transfers over to the marketer's expertise. We are still planning to sell the barrel to the marketer at our wellhead in the Permian. The marketer will then step into our tariffs and move our barrels to the coast. Via our commitments to these pipes, they know what our minimum volume is going to be on these pipes, and that allows them to secure the tankage and the export capacity that they need, in this particular case, in Corpus Christi.
Okay. No, that is helpful. I think that is all I have for now. I appreciate the time. Congrats, guys.
Thanks, Michael.
As a reminder, ladies and gentlemen, at this time, if you have a question, please press the star and the number 1 key on your touchtone telephone. Our next question coming from the line of Leo Mariani with NatAlliance Securities. Your line is now open.
Hey, guys. Just a quick question for you here on well performance. It certainly seems like your wells got stronger this quarter from what you guys demonstrated. You guys did talk about having some better 3D laid out there in the field. Could you maybe just provide a little bit more color on what you're seeing in terms of some of the improved well performance and some of the reasons behind that?
Yeah, this is Paul Molnar. We're continuing to obtaining 3D in the Southeast Delaware area, and it's really helping us with our geo-steering. As you can see, there's a lot less vertical well control down there, prior operators had difficulty staying in their targeted intervals. As the 3D's coming in, we're having a lot more success staying in our primary targets.
Leo, from the other side of the operational piece, of course, we're learning, continuing to optimize every day. We change from the landing points to how we stimulate the wells, how we flow the wells back, whether it's cluster spacing and size, fluid volume, sand content, distribution of the sand size, the intensity with which we frack with, whether we use diversion. The answer is we use all of those, and we continue to change that recipe over time, and we'll continue to get better as we go. You've seen that across the industry as a whole. All of those with being able to put the wells in the right spot in the rock and spaced properly is, I think, what's given in all of those things together and what you're seeing with the better well performance.
Okay, that's helpful. I guess, certainly noticed that just looking at your guidance for oil cut for 2018, I guess you guys reduced it a little bit here with this update, and I guess it had kind of been coming down a little bit in the last couple of quarters in terms of your oil cut. Just wanted to get a sense of what was sort of driving that. I don't know if you guys were shifting activity to different areas, but maybe just a little color behind that.
Yeah, Leo, it's been interesting to see, not only ourselves but also across the Permian, with natural gas takeaway getting tighter and economics prevailing, ethane has been moving out of the residue stream and into the NGL stream, and therefore increasing our NGLs as a percentage of total. A six-to-one molecule is getting more one-to-one credit as an NGL. Really, NGLs have outgrown our oil growth. That led us to lower the oil cut for the year. I really think the midpoint of our new range is where we are for the foreseeable future until something changes on the ethane front.
Okay, just with respect to what you just said there on ethane, do you guys have expectations that there'll continue to be a lot of ethane pulled out of the stream for the foreseeable future, next several quarters? How do you see that playing out as we work into 2019?
Yeah, it's a push-pull with the tightness in both the NGL market and the natural gas takeaway market. The ethane pricing right now seems to be that ethane acceptance versus rejection is the norm in the basin.
Thanks, guys.
Thank you.
Thank you. At this time, I'm showing no further questions. I would like to turn the call back over to Mr. Travis Stice, our CEO, for closing remarks.
Thanks again to everyone participating in today's call. If you have any questions, please contact us using the contact information provided.