Diamondback Energy Inc (FANG) 2018 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Diamondback Energy Third Quarter 2018 Earnings Conference Call.

(Operator Instructions) And 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; 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 Third Quarter 2018 Conference Call.

Diamondback was able to execute on multiple long-term strategic initiative over the last 3 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, and 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 3 years.

Our operating philosophy has not changed: maximize production growth within cash flow; maintain best-in-class operating metrics; low leverage; and 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 and the shareholder meetings are scheduled for November 27, with a deal expected to close shortly thereafter pending shareholder approval.

We are currently operating 14 rigs and 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 companies' asset base.

We will begin delivering on the primary synergies presented in our merger presentation immediately, and 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 3 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.

Also 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 will 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 6 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 Carlyle for the development of the San Pedro area of our Pecos County asset and have started drilling with 1 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 Carlyle developing this acreage block over the coming years.

In true Diamondback fashion, we've had a 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 5 fractories 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 3 of our completion crews and realizing roughly $60 per lateral foot of savings.

We have also begun dual fuel operations on 1 drilling rig and 1 fractor 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 5 drilling rigs and 2 completion crews with these capabilities currently in our fleet.

Moving to well results.

We are excited to announce 2 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 Carlyle 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 achieved in the Midland Basin, roughly 10% of total capital.

With these comments now complete, I'll turn the call over to Tracy.

Thank you, Mike.

Diamondback's third quarter 2018 net income was $1.59 per diluted share, and our net income adjusted for noncash 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 and nonoperated properties and $74 million on infrastructure and midstream.

Year to date, we have spent $934 million on joint operation and nonoperated 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 1.2x.

After adjusting for the closing of the Ajax, ExL and EnergyQuest acquisitions on October 31, 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 26, 2018, to shareholders of record at the close of business on November 19, 2018.

Operator, please open the line for questions.

(Operator Instructions) And our first question coming from the line of Neal Dingmann with SunTrust.

Travis, my first question for you or Kaes and the guys, could you discuss -- it seems like a strategy that's really going 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 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, just I know maybe a bit premature for that, but I'm wondering if you could just give the highlights as far as what you all deem the benefits of a strategy like this versus what, sort of, I guess, 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 2 pipelines that's going to sit within our Rattler Midstream.

And really think that this strategy long-term is going to be seen as a really creative strategy that drives differential value to our shareholders.

Yes, I mean, 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.

And 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, your equity ownership, to move our barrels to the water.

So essentially, we're getting to Corpus Christi almost for free, and then that's where the experts take over.

We're not an exporter, we're not a marketer.

And 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.

So 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 of quarters and then once EPIC comes on in Q2 or Q3 next year, the dips start to ease and we'll start to maximize the benefits of these investments.

Okay, great color.

And then maybe just my second one for Mike.

Mike, looking at that Slide 5 where you -- I'm sorry, Slide 14 actually, where you talk about the take away and sort of more about the landing zones that you're showing in the southern Delaware.

Could you talk about -- I think you mentioned here about the high-graded landing zones, but specifically, if you could talk about the thickness when you look at the Bone Springs versus the Wolfcamp A, B and C, how important is it to have this sort of high-graded landing zone in order to achieve sort of the highest results?

Absolutely, Neal.

3D seismic, we've just got some high-resolution 3D data that's in and we're utilizing that for our targeting.

And it's giving us the ability to stay well within that premium target in both the Wolfcamp A and the Bone Springs.

Again, thickness is important, but where you are within that thickness and the rock quality is very important.

So we continue to refine our model and continue to place these wells where we -- where we're able to test it and get that data so we can adjust as we go forward.

But 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.

And our next question coming from the line of John Nelson with Goldman Sachs.

Travis, our math says the market is only giving Diamondback credit for about $600 million of the more than $2 billion of synergies you all detailed alongside the Energen acquisition announcement.

So, I guess, my question is, one, how, if at all, do you view the execution risk of Energen different from kind of the numerous other acquisitions the team's previously executed on?

And then two, can you maybe walk through a timeline for achieving some of the synergies that you outlined?

Yes.

We, and I think, we had it in our prepared remarks, John.

We anticipate, when we update the market on our 2019 guide that the synergies that we outlined in our acquisition presentation, we're going to be -- that's what to expect organizationally.

That's the challenge that's been placed in front of us.

And look, every time Diamondback has made a pivotal -- made a pivot or done a large acquisition, there's always been in front of us, a hurdle of execution.

And 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.

So 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 they're -- as this merger goes through.

And 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.

And look, we also outlined a couple of billion dollars of secondary synergies as well too in that acquisition presentation.

And I think those are going to become more and more real over time as we get some of these strategic initiatives executed upon.

So 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.

And 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 1Q in early 2019.

Is that still kind of a fair target?

Or as you kind of started to work on in getting further along and evaluating or integrating with the teams, is there any reason to believe that, that will 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 a 24-rig program.

And on the G&A side, we plan our dollar per BOE guidance to be in line with what we've done traditionally, which is less than $1 per barrel.

Perfect.

And then just a second question.

The infrastructure spend is now kind of more than 20% of D&C capital.

And Mike, you kind of hit on it in your prepared remarks, that should kind of migrate to 10% over time.

But just thinking over the next 1 to 2 years, how should we kind of think about that trajectory to kind of get down to that long-term target?

Yes, John, on slide 17, we put a little comparison of the Midland and the Delaware Basins.

We're 5 years into a horizontal program in the Midland Basin, and now, the infrastructure dollar as a percentage of total are a much smaller amount, down to about 8% in total.

The Delaware Basin, when we bought that asset, really it was new country out there in Pecos County and Reeves County and no infrastructure in place.

So we've been spending a lot of money out there over the last 2 years and you see that the Delaware is about 28% of total capital out there this year.

But as our rig counts ramps and the amount of batteries we have out there, the electricity is in place, the oil gathering system is in place, that number will decrease over time.

And hopefully be less than 10%, probably by 2020.

And our next question coming from the line of Derrick Whitfield with Stifel Financial.

Congrats on a strong quarter.

Reading between the lines, you guys are truly excited about the Spanish Trail North asset, 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 2 to 3 rigs.

We'll -- the assets we had there before, we were running between 1, 1.5, than when we added the additional 25,000 acres.

It's reasonable to expect about 1 rig per -- about 10,000 acres, so you have somewhere in the 3 to 4 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 multiwell pads.

I think we've talked previously about 12-well pad, and that's what we intend to do is park a couple of rigs there to develop in these 8 to 12 well pads, one right after another.

And again, that acreage has 3 zones that, at today's prices, has greater than 100% rate of return.

So 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.

So look to us to accelerate and lean in on that one as hard as we can.

Great update.

And then regarding the Second Bone Spring wells that you discuss 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, they're shallower, they're a little bit lower pressure than the Wolfcamp A. So we see somewhere in the $800,000 to $1 million difference.

And again as we continue to use local sand in the area, we'll be able to realize a few -- a little bit more of that savings.

Again, as far as the targeting, we do hit several targets in the Bone Springs, so we'll actually wine rack some in what we call an upper and lower.

But again, as we continue to develop this, we have 3 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 block.

Our next question coming from the line of Drew Venker with Morgan Stanley.

How do you think about setting your capital program and a 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?

Yes, I think we've been pretty clear what our strategy has been.

We're going to allocate -- we are going to continue to allocate capital to higher rate of return projects within cash flow and pay a dividend, and the rig count right now is 14 from Diamondback and 10 from Energen.

So that's going to be the initial allocation of capital, and 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.

But look, I think we're on the cusp really of having created what we feel like is really a special oil and gas company.

Because not only can we generate peer-leading growth, we can also grow our dividend and we can do bolt-on acquisitions, all within cash flow.

And do so with less than a turn of leverage.

And we think that's pretty special, and we think that's the strategy that's going to carry this company forward for multiple years, if not decades, to come.

And we think that's what the generalists have been looking for, that's what the specialists in energy space have been looking for, and I think Diamondback has touched all of those levers to -- as we've matured as a company.

And then 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?

Yes, Drew, we can't talk too much about it, but 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.

So we're going to be waiting patiently, and hope this deal comes to a resolution in some shape or fashion.

And our next question coming from the line of Mike Kelly with Seaport Global.

A specific one for me.

If I look at your updated production guidance for 2018, could you guys give us a sense of how much of that roughly kind of 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.

Yes, Mike, this is Kaes.

I'll take just a further step back.

If you look at when we came into this 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.

And 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 2 months of credit, that would be 2,000 barrels a day of production out of that 7,000 barrels a day we raised.

So 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.

But 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 to 600 barrels a day out of the 2,000 barrel a day increase.

Awesome.

That's -- a lot of detail, I appreciate that.

And Slide (multiple speakers)

So I'd 30% related to acquisitions for the year and 70% of the growth related to organic growth for the year.

Okay, great.

I appreciate that color.

And then another one, could 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.

Would you care -- 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?

Or it could be relative to WTI, kind of incorporate it in everything you laid out to us?

Yes.

I think -- I mean, I think, Q4 will look better than Q3 because of the improvement in the Midland market.

We have 2 deals that priced in the second quarter that were at fixed differentials to MEH over that quarter, and so those deals are in place throughout first quarter next year and then through all of next year.

And then we have some other deals currently pricing that are looking better because the middle market has improved.

So overall, I think Q4 differentials to WTI will look better than our Q3 differential.

But tightening through Q2 of next year, and then 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, Kaes, I mean, do you think that assuming -- incorporating the fees you're going to have to pay to actually to get the crude to the coast, do you have a sense -- can you kind of 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, and 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.

Our next question coming from the line of Asit Sen with Bank of America Merrill Lynch.

So 2 unrelated questions.

In the past, Travis, you've talked about grow-and-prune strategy.

It looks like you've added some nice acreage.

On pruning, what are the areas that are prime for high grading?

And your thoughts or early thoughts on central basin platform near term?

I think, Asit, if you look on any of our presentation, any slide in our presentation, it has those ellipses around the kind of what we're calling our core areas -- core development areas.

Anything outside those circles, or ellipses, are 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 with Energen presentation is that our, first, is to try to swap and core that up, but to the extent we can't swap and core that up, it becomes divestiture candidates.

And look, Central Basin platform, we've essentially called that reserve for sale and we'll start that process as quick as we can after the merger closes.

Great.

And then on the dual fuel opportunity, which switched to natural gas, it looks like you were trying on 1 rig with potential to go up to 5 rigs.

Early thoughts on the 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%, may be 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, but in general, roughly about $100,000 a well or $10 a foot.

On the drilling side, it's, 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.

And our next question coming from the line of Tim Rezvan with Oppenheimer.

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.

Nothing major.

It's just some infrastructure and batteries that came with the acquisition.

Okay.

So those will get folded into, I guess, into Rattler?

Correct.

Yes.

Okay.

And then -- if we just step back a little bit, Travis, you've been pretty clear about this growth then cash-flow approach and you've sort of hinted at dividend growth moving forward and talked about cash capital discipline, at the same time, there's been over $1 billion in acquisitions announced in the last 3 months separate from Energen.

So how do you think about when or how Diamondback might sort of dial down the resource capture?

And 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 tried to be clear that the acquisitions we do, we would do so without putting the balance sheet at risk.

And again, if you go back and look at our history, we've always seen we've maintained a fortress balance sheet for just these type of opportunities.

But look, this -- what we're calling now the Spanish Trail North, that was just too good of an opportunity not to have transacted on.

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 way.

Going forward, Tim, I said during the Energen merger presentation that Diamondback, 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 challenges in front of us and that challenge is very clearly defined as execution.

So throughout, really now both organizations, we understand that the battle lines are drawn for us to execute on those synergies, which is why I've spent so much time detailing the synergies and our plans for the time frame for when we're going to deliver on those.

So look, I think, we've got a lot of things going a very positive direction for Diamondback.

And I think we really like our inventory and where it sits right now.

And 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.

And 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.

And 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.

And that's our mantra of capital discipline, and we expect our investors to expect us to do deals that have -- create full cycle returns and compete for capital right away with our existing inventory.

Yes.

These acquisitions, Tim, are immediately accretive.

And listen, you've covered us for a long time, Tim, and you know that the capital discipline mantra is not something new.

As I've pointed out, we're 15 quarters in a row right now of being capital-disciplined in terms of spending less than we make.

And I think that's a unique commentary in the energy space right now.

15 quarters in a row.

So essentially after the oil price collapsed in 4Q of 2014, this capital discipline has been fundamental to our capital-allocation strategy.

And not one single quarter have we deviated from that our strategy.

So 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 and 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.

So besides the dividend, we should look to kind of you all sort of putting that to work on opportunistic resource capture.

Just 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 and it's visible when you look at 2020 and beyond.

Our next question coming from the line of Jason Wangler with Imperial Capital.

I appreciate the kind of update on the Energen plans in kind of in 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 kind of think of the allocation of those rigs going forward?

Yes, these drilling schedules, while we like to think they're immediately flexible, in fact, they're really about 6 months to 9 months out in front.

So once the merger goes through, we're going to continue operating the 14 Diamondback rigs on the Diamondback properties and the 10 on Energen properties.

And 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.

And then, 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 kind of where they are in the stage of that lifecycle?

Do see a significant amount of spend that you would need for them as you look at 2019 in closing that deal?

Or do you think it will be kind of comparable to what you look to spend on the Diamondback assets next year and going forward?

Yes, 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 3x the SWD capacity that we have today.

So they've been operating in the Delaware for a long time, and they've set up a great infrastructure system.

So 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.

So we had to put electricity, oil, gas, water, SWD all in over the last 24 months, and it's going to benefit us long-term with realizations and LOE and midstream value creation, but it's just a lot of money we're spending as a percentage of total in the Delaware at the moment.

And our next question coming from the line of Richard Tullis with Capital One Securities.

A lot of my questions have been asked already, Travis.

But just going back to the D&C costs for next year.

I believe, it was mentioned that intent 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 are being offset by other efficiencies?

Richard, this is Mike.

The quick answer is yes.

With oil price increasing, we obviously see service cost go along with that, steel tariffs and all of those that are in place today.

So 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 sands, 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.

So the answer is yes.

We're going to take current pricing that we have today in our current structure, apply it as well to the Energen properties.

But going forward, yes, there will be some inflationary pressures coming.

And just one last one.

So 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.

So we've put a lot of water capacity into our systems in the Delaware Basin and we're getting ahead of our growth ramps 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 2 years ahead of major issues.

This oil gathering or oil takeaway issue crept up on us faster than we expected, but 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.

Our next question coming from the line of Charles Meade with Johnson Rice.

I wanted to explore a little bit the -- maybe future -- your future plans in that new Spanish Trail North area you've created.

You've done a great job of assembling that in it seems like pretty quick fashion, but it's striking me that as I look at the map, you've got perhaps the chance to extend that towards the southeast and to connect the dots with that Energen position that's kind of there -- kind of central or northwest Martin County.

So 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?

Well, 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 plus laterals.

And so 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.

But 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.

And we'll be opportunistic to do small tuck-ins and bolt-ons if they're accretive and they make sense for our development scenario.

And 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.

So 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, for my second question, going back to your comments in the prepared remarks about those -- I believe it was the 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.

And so 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.

So again, we're -- it's exciting to see the productivity across the entire acreage block.

Yes, 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.

So our GOs and reservoir engineers and ops team, they're all learning a ton as we start to ramp up there.

We started with 2 rigs, and now, we're running 7 rigs across the Delaware.

So certainly, learning things every well we drill.

And our next question coming from the line of Michael Hall with Heikkinen Energy Advisors.

I'm just kind of curious on the -- as we think about 2019 and the activity profile kind of 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 5 crews.

Is it fair to just kind of scale up that kind of quarterly footage completed with the new equipment profile for 2019?

Or do you think it will kind of take a dip down as you integrate the new assets and then kind of when would it normalize, if that's the case?

Michael, we expect, 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, and that includes all the time throughout the quarter.

And on the Delaware side, we're closer to 900 lateral feet per crew per day.

So we're running 5 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, 5 and 5. So we expect those operational efficiencies to hit right away.

That's helpful.

And 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?

And kind of where does that end, I guess, in the value chain as it relates to Diamondback?

Yes.

Our expertise ends when the pipe ends and then transfers over to the marketers' expertise.

We're still planning to sell the barrel to the marketer at our wellhead in the Permian.

And they -- the marketer will then step into our tariffs and move our barrels to the coast and 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.

(Operator Instructions) Our next question coming from the line of Leo Mariani with NatAlliance Securities.

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 of 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?

Yes, this is Paul Molnar.

We're obtaining -- continuously obtaining 3D in the Southeast Delaware area.

And it's really helping us with our geosteering.

As you can see, there is a lot less vertical well control down there.

And prior operators had difficulty staying in their targeted intervals, and as the 3D is coming in, we're having a lot more success staying in our primary targets.

And Leo, from the other side of the operational piece, of course, we're learning, continuing to optimize every day.

So we change from the landing points to how we stimulate the wells, how we flow the wells back, whether it's cluster spacing in size, fluid volumes, sand content, distribution of the sand size, the intensity with which we frac with, whether we use diversion, and 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 on.

And you've seen that across the industry as a whole.

But 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, what you're seeing with the better well performance.

Okay, that's helpful.

And, I guess, I 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's kind of been coming down a little bit in the last couple of quarters in terms of your oil cut.

I 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.

Yes, 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.

So a 6:1 molecule is getting more 1:1 credit as an NGL.

So really, NGLs have grown -- outgrown our oil cut -- or oil growth.

So that led us to lower the oil cut for the year.

I really think the kind of midpoint of our new range is really our -- for the foreseeable future until something changes on the ethane front.

Okay.

With respect to what you just said there on ethane, I mean do you guys have any expectations that there'll continue to be a lot of ethane pulled out of the stream for the foreseeable future next several quarters?

I mean, how do you see that playing out as we work into 2019?

Yes.

I mean, it's a push-pull with the tightness in both the NGL market and the natural gas takeaway market.

But the ethane pricing right now seems to be that ethane acceptance versus rejection is the norm in the basin.

And 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.

Ladies and gentlemen, thank you for your participation in today's conference.

This concludes the program.

You may now disconnect.

Everyone, have a great day.