Diamondback Energy Inc (FANG) 2019 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to Diamondback Energy's Fourth Quarter 2019 Earnings Conference Call.

(Operator Instructions) As a reminder, this conference is being recorded.

I would now like to introduce your host for today's conference call, Mr. Adam Lawlis, Vice President, Investor Relations.

Sir, you may begin.

Thank you, Kevin.

Good morning, and welcome to Diamondback Energy's Fourth Quarter 2019 Conference Call.

During our call today, we will reference an updated investor presentation, which can be found on Diamondback's website.

Representing Diamondback today are Travis Stice, CEO; and Kaes Van't Hof, CFO.

During this conference call, the participants may make certain forward-looking statements relating to the company's financial condition, results of operations, plans, objectives, future performance and businesses.

We caution you that actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors.

Information concerning these factors can be found in the company's filings with the SEC.

In addition, we will make reference to certain non-GAAP measures.

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, and welcome to Diamondback's fourth quarter earnings call.

Before I start with my remarks, I want to pause and recognize an individual who passed away last week, Clayton Williams, who was truly a larger-than-life West Texan and a man that paved the way for so many in our industry who came after him.

He was a wildcatter, a patriarch, a philanthropist and a Texas Aggie.

Later today, we will lay him to rest and celebrate a life well lived, but I couldn't start without reflecting on what Claytie has meant to so many people.

Ms. Williams and family, our thoughts and prayers are with you today.

Godspeed, Clayton Williams.

You will be missed.

Turning to the fourth quarter.

Diamondback ended 2019 in a position of strength, achieving 5% oil production growth quarter-over-quarter along with our highest oil realizations of the year.

This, combined with our industry-leading cost structure, resulted in 18% quarter-over-quarter EBITDA growth and 31% quarter-over-quarter adjusted EPS growth.

We repurchased 2.4 million shares in the quarter for approximately $199 million, utilizing free cash flow and a $43 million gain from an interest rate swap that was unwound as part of our first investment-grade bond offering in November to repurchase shares at a depressed valuation.

Further, Diamondback did not slow operations in the second half of 2019 and maintained continuous operations with 8 completion crews running consistently through the end of the year, setting us up for continued growth and operational momentum in 2020.

Taking a step back to review the full year, 2019 was a busy year for Diamondback.

We successfully integrated our merger with Energen, doubling the size of our company, while achieving greater cost synergies in a shorter period of time than originally promised at time of deal announcement.

We grew pro forma oil production 26% year-over-year from a $2.9 billion capital budget, increased our dividend by 50% and repurchased 6.4 million shares or about 10% of the shares issued to complete the Energen merger.

On the corporate development front, we sold noncore assets, dropped down mineral interest to Viper and took our midstream business public.

In November, we executed on the final piece of our synergy scorecard and refinanced $3.0 billion of the company's long-term debt following our upgrade to investment grade at an attractive interest rate.

While I'm proud of what we accomplished in 2019, we don't spend any time looking backward at our tracks in the sand, but rather looking ahead and concentrating on the future.

2020 has already bought -- brought its own industry challenges, and we are focused on navigating these challenges by staying disciplined, improving our industry-leading cost structure, growing production, increasing environmental transparency and returning more cash to stockholders.

Our dividend remains our primary method of returning capital to stockholders.

And as evidenced through our announcement today, we are strongly committed to continuing to grow this dividend which sits at a 2% yield at today's stock price.

We will continue to be opportunistic with our share repurchase program and outright debt reduction to maintain balance sheet strength, but our dividend is considered first dollar out when it comes to capital allocation at Diamondback.

Looking to the year ahead of us, Diamondback expects to grow oil production in the first quarter of 2020 on the back of our strong fourth quarter production en route to our 10% to 15% year-over-year expected oil production growth in 2020.

We expect to execute this plan within the same capital budget framework as 2019 while completing 7% more lateral footage with the same amount of capital.

Our oil realizations are expected to improve to nearly 100% of WTI in the first quarter of 2020, which will be a nice tailwind for per share metrics.

Full-service start-up of the EPIC and Gray Oak pipelines in the second quarter will increase our exposure to the export and Gulf Coast markets as well as increase cash flow through our 10% ownership of each pipeline at Rattler.

We will also continue to work to drive down cash operating costs through the year with LOE expected to decline relative to 2019 numbers.

We believe this capital and operating plan reflects the optimal capital efficiency for achieving a peer-leading combination of growth and free cash flow in 2020.

Should commodity prices decline further from current levels, we will be prepared to act responsibly and cut capital further, just like we've done multiple times in the past.

If commodity prices rally, we plan to use excess free cash flow to accelerate our capital return program and reduce debt.

With these comments now complete, operator, please open the line for questions.

(Operator Instructions) Our first question comes from Derrick Whitfield with Stifel.

And congrats on your decision to reinforce your return of capital message with a substantial dividend hike.

Thank you, Derrick.

Perhaps for you, Travis.

As we critically evaluate your inventory additions and the well performance trends by interval, it's clear to us that the Middle Spraberry and the Delaware Second Bone Spring intervals are becoming more valuable intervals within your inventory set.

Focusing on the Bone Spring shale in Pecos, to what degree have you guys delineated the trend across your footprint?

And are there specific or any specific reasons this interval can't account for a larger percentage of your Delaware allocation in future years?

Yes.

Derrick, certainly, we're very encouraged in what we're seeing in the Second Bone Springs across our Delaware position and look for continued results like we posted that we're going to continue to allocate more and more capital to the Bone Springs.

But we're very encouraged about that inventory development and also our existing inventory as we continue to drive down costs and improve returns on all of our Delaware position.

Sure.

And as my follow-up, I'll stay on the Bone Spring shale.

I imagine your operations team could drive meaningful cost improvements in a full field development scenario.

Could you speak to your current completed well costs in comparison to the Wolfcamp A and also comment on potential savings you could see in a full field development scenario?

Yes.

Derrick, I think from a drilling perspective, it's about $40 to $50 a foot cheaper.

So assuming the same completion design as the Wolfcamp A in Pecos, that would be about $0.5 million cheaper on a 10,000-foot lateral.

And I will say one of the benefits is there's been so much infrastructure dollars, so many infrastructure dollars spent in Pecos that you don't have to load up the Bone Spring pads with the same level of infrastructure spend as we did for the Wolfcamp A over the last few years.

So really excited about the results we're seeing there.

It's certainly becoming a competitive zone to the Wolfcamp A, and we'll start to take more of the capital dollars in that field.

Our next question comes from Neal Dingmann with SunTrust.

Travis, my first question is on your investor metrics.

Among the Permian players, we have -- you all generated among the highest combination of oil growth, free cash flow yield and dividend yield at about over 15% already.

Could you speak to your confidence on the sustainability to maintain this or potentially grow these metrics in today's or even a lower oil environment?

Sure, Neal.

I made a comment in my prepared remarks that our Board is committed to continuing to grow our dividend.

The free cash flow yield and volume growth, we feel confident that those numbers are multiyear in duration.

And obviously, we've got an inventory that can support that.

So we're really pretty excited about sustainable oil production growth as well as increasing free cash flow, total free cash flow yield and dividend growth as well.

Very good.

I'd be remiss if I didn't ask a second question on M&A.

Could you all just comment, Travis, for you or Kaes, your view on the need for M&A especially in such a continued volatile energy tape?

Yes.

Look, Neal, our shareholders expect us to know everything that's going on out here in the Permian.

And with boots on the ground out here, we certainly do.

But they also expect us and they know that from our past performance, that anything that we consider needs to be accretive, which means on several metrics: free cash flow, cash flow per share, EPS, inventory quality and operational efficiency.

So any deal that we're interested in has got to be extremely compelling from a price perspective, given our current stock price and the abundance of cheap opportunities out there in the marketplace.

As I just was talking to Derrick, we're very confident with our inventory, and that inventory is going to drive growth for many years in the future.

But we also have responsibility to our shareholders to continue to stay in the game and looking at opportunities that are really attractive.

Our next question comes from Scott Hanold with RBC Capital Markets.

And maybe just a good time to follow up on that last question.

Just in general, as you look at your lateral lengths and as you go to these longer lateral lengths, I mean, look at your average lateral length in your inventory, how do you see that progressing?

I mean is there a lot of opportunities yet to block up?

I know you talked about a Northern Delaware transaction.

But as you look at your footprint, what should we expect that lateral length to look like, say, in the next year or 2 on average?

Yes.

Scott, our asset teams are -- have their own little business development opportunities where they know that drilling longer laterals improve economics and increase our returns to shareholders through increased free cash flow generation.

And that's part of our day in and day out business.

We would like to always drill longer laterals.

I think somewhere in that 10,000-foot length is probably where our inventory is typified by today.

But certainly, we'll look to always to push that.

Okay.

Fair enough.

And as you step back and talked about the proposition you give for investors in that mid-teens growth, a strong free cash flow yield and a good dividend yield, how do you see that growth rate, that production growth rate going forward?

And you got that low to mid-teens number kind of set right now this year.

But as you look into, say, 2021, 2022, do you -- would you like to maintain that rate?

Does that maximize your free cash flow?

Or do you think, over time, it could fall to sort of that -- the 10% to 12%?

Well, certainly, the law of big numbers catches up with you.

And if you're going to maintain flat CapEx on a year in and year out basis, that's going to have an impact on your overall production growth.

So we believe that having that double-digit growth rate, combined with the yield that we have, provides our investors a clear differential investment thesis.

And we've got the inventory that we think we can support that for multiple years to come.

But as we continue to try to grow production on a larger and larger production base, you're going to have to see the CapEx numbers, minus capital efficiencies, continue to increase.

Yes.

Yes.

And I guess the bottom line, I should have been more succinct in saying as you look forward with that free cash flow, how does it get allocated between dividend, buybacks and investing in the business to continue to grow?

Like where does -- how does that allocation change over time?

Yes.

That -- I mean that's an important point, Scott.

Really, free cash flow should be defined as cash flow available above your sustaining CapEx.

And for us, right now, the sustaining CapEx to keep production flat exit to exit is about $1.6 billion.

Now above that, in the mid-$50s oil price environment, we have a couple of billion dollars of cash flow to allocate.

And today in 2020, we're allocating 2/3 of that to growth and 1/3 of that to shareholder returns.

So I think for us, we shouldn't capitulate on growth.

I think Diamondback is still a growth story, and now it's a growth with a free cash flow story.

Our next question comes from Scott Gruber with Citigroup.

Just a question on the Midland Basin development by zone.

You guys are pretty forthright here with the 2020 mix.

Is the mix largely optimized at this point?

As we think about '21 and beyond, is there much additional shifting between zones and change in that percentage of co-development beyond '20?

Yes.

Scott, so I think the big mix -- the shift to co-development happened in 2019 with a little carry on into 2020.

The whole point of the co-development strategy is to get the economic zones that are available today all at the same time.

So I think as you think about development strategy going forward, the Middle Spraberry and the Wolfcamp B will have a bigger piece of the total pie versus past years.

I'm hopeful that it stays about consistent to 2020.

But as we move across various areas where -- in some areas, the Middle Spraberry is better; in some areas, the Wolfcamp B is better.

But overall, this development pace is going to be standard across the company, and we are codeveloping everywhere in the Midland Basin.

Got it.

And just turning back to the dividend, great to see the doubling today.

As we think about the go forward, you mentioned continuing to grow the dividend, how do you think about where you want to place the dividend?

Obviously, the stock price will dictate the yield.

The near term, is there a number that you're targeting over the next, call it, year or 2 to continue to grow that dividend?

And then longer term, how do you think about a proper payout ratio for the business, just given the inherent volatility in the commodity price?

Yes.

Scott, so we've heard a lot of feedback from investors over the last 18 months, particularly around the dividend and growth in exchange for that capital return.

I think the only consistent message we've heard from our large shareholders is that they want the dividend larger sooner.

So for us, we took a big jump this year as we're fully shifting to growth plus free cash flow in 2020, and that was an important step for us.

Now I think in the future, the dividend is still going to be the primary return of capital and going to need to grow.

We don't want to grow it to the point where our implied yield or the payments we need to make on that dividend are a restraint on our business plan.

But today, it's unfortunate that we got to a 2% yield via the stock price, but we were always focused on getting that dividend to a meaningful level, which is near a couple of bucks a share.

Our next question comes from Gail Nicholson with Stephens.

LOE, can you talk about the progression for LOE throughout the year?

And then what specific projects you guys are working on that will drive improvement?

Yes.

So we took a nice step-down in the fourth quarter.

We guided to $4.40 to $4.80 for the year.

I would say the first half of the year is probably going to be on the higher end versus the back half of the year, we start to see some benefit from large projects, particularly on the electrification side of our fields.

Right now, we are renting a lot of power generation in field.

And while that's with these turbines is better than small diesel generators, it's not as efficient as being hooked up to the grid.

So as we progress through the year, we should see a nice trend down in LOE based on getting electrification in Howard County, Pecos County and Northwest Martin County.

Great.

And then on the infrastructure spend in 2020, what percent of that is onetime project versus normal course of business?

And how should we think about that trending in '21 forward?

Yes.

I would say that that's 1/3 onetime projects.

With the integration of Energen, we have learned that some areas are better for gas lift in our field.

So there are some gas lift projects that are onetime in nature.

And then the electrification, as I mentioned, will be some onetime projects.

I think credit to our facilities team, we're going to complete 340 wells this year, and about half of those need $0 from an infrastructure perspective.

So I think that's a pretty impressive feat by the infrastructure team.

Our next question comes from Brian Singer with Goldman Sachs.

When -- I wanted to follow up on one of the earlier questions with regards to that trajectory between CapEx, free cash flow and growth.

When you look at your inventory and your expectations for further efficiencies on the cost side, how long do you see your ability to source double-digit growth at flat CapEx?

And where are you on the trajectory versus growing CapEx in future years relative to seeing your growth rate decelerate to the low end or below the 10% to 15% range?

Brian, it's important what service costs are going to do, right?

I mean if service costs stay flat, our midstream and infrastructure budgets will continue to decrease, and therefore, we're able to get more net wells within the same budget framework.

So I think we'll address '21 and '22 as we get closer and see what service cost and oil price does, but we're not going to give up on sustainable growth but also that growth in the free cash flow on a gross basis year-over-year.

Look, the organizational emphasis has always been to grow and to, as we mentioned earlier, also grow the dividend.

And one of the ways that our guys differentiate themselves is in the way that we become more and more capital efficient as we go forward in time.

And while we know that, that becomes somewhat asymptotic as you go forward in time, that's still part of our core competencies is to pick pennies and nickels up where we used to pick up dimes and quarters.

And so organizationally, Brian, we're going to continue to drive efficiencies well into the future.

Great.

And then can you add any color on how you see the production trajectory and CapEx trajectory through the year and the setup that, that would provide going into 2021?

Yes.

Brian, I think the way we have it set up is to be -- operate fairly consistently throughout the year.

As exhibited by 2019, we did not slow down in the second half of the year, and we have no intention to this year.

We're running 21 big rigs today, 2 saltwater disposal rigs and 8.5 frac crews essentially.

And that pace should be pretty consistent.

I think we do plan to grow off of what was a very good number in Q4.

And then as you think about the rest of the year, we should have fairly consistent growth from Q2 through Q4.

So really like the setup here and also the setup for '21 is we don't plan on slowing down in the back half of the year.

Yes.

Brian, just like I was talking about the organizational culture of efficiency, it didn't make sense to us to go to the operations organization in the back half of last year and say, "Okay, guys, start laying equipment down.

And then we're going to ask you to pick it back up in the first quarter and immediately assume the same level of operational momentum and capital efficiency." So that was the reason we decided to continue with the efficiency, and that's what's led to what we feel like is a good growth in the first quarter as well.

We're not having to catch up or make up ground that we lost from laying down activity in the fourth quarter.

Our next question comes from Jeanine Wai with Barclays.

My first question is on buybacks versus debt reduction, just following up on some of the prior questions.

With the 2% dividend yield now at the current share price, how do you think about buying back stock versus specifically reducing debt?

We know that your debt is trading at a higher yield.

This could increase strategic flexibility in the future.

You've got some nice IP tailwinds going on for you as well.

I'll let Kaes answer those in detail.

But I'll just say in general, the higher the oil price, probably the less you buy back stock in our business.

And likewise, the converse of that's also true.

The lower the oil price, the more you're going to buy back.

Yes.

I would agree with that.

Today, where we are, we still have free cash to buy back stock.

We're not concerned with our leverage ratio or overall leverage.

Certainly, it's important for an oil and gas company to decrease leverage over time.

But unlike other companies, we also have a significant amount of equity in 2 subsidiaries that is monetizable at -- not at a moment's notice, but can be monetized.

So I think for us, on the balance sheet side, we're going to keep taking care of converting our old high-yield notes into IG notes throughout the year and continuing to drive down the overall interest expense at the company.

Okay.

Great.

That's very helpful.

And my second question is on inventory.

How do you think about the cost of adding Tier 1 inventory?

For example, how do the costs compare from moving current tier 1 -- current inventory into Tier 1 via exploration, appraisal or whatever else you might think of versus inorganic additions either via M&A and acreage trades tend to be pretty high RoRs as well?

Yes.

Acreage trades are certainly the highest rate of return possible, and we got about 40 of them done last year with the 2 combined businesses of Energen and Diamondback.

So that was a lot of low-hanging fruit for us to improve.

Now I'll let Travis comment on the other piece, but all I would say is that any inventory additions today in the Permian are significantly cheaper than they have been in any time in our short history.

Yes.

Like I mentioned earlier, we have a set of metrics that we have to be accretive on, and we'll continue to -- we've always done accretive deals, and we'll always look at these accretive metrics.

You mentioned like 3 different ways and one of them was exploration.

And while that's been a very small part of Diamondback's history, we did release results on our 25,000-acre play that we entered in about 3 years ago with really, really low cost on the Xanadu well.

And while for a $20 billion company, one well test is not particularly that significant, but it sure was a good test for the first well that we drilled, the Xanadu well.

I think that IP30 is something over 100 barrels a foot, and now we're turning it over to the execution guys as we move into the appraisal stage and drive costs down.

And as we drive cost down, that's going to push up the returns for that and probably attract a 1- to 2-rig program in our future capital allocation decisions.

So it's really all 3 of those things.

Acreage trades are certainly a day-in and day-out opportunity, looking accretive acquisitions and extremely low valuation that we see today, and then we sprinkled in a little bit of exploration success.

So I think we're executing on all 3 of those strategies.

Our next question comes from Jeff Grampp with Northland Security -- Northland Capital.

Was just curious, we've talked a bit on kind of how you guys are thinking about growing the business going forward.

And I guess related to that, I was wondering, if I'm looking at Slide 10, I think, you guys referenced both the PDP oil decline and BOE decline rates, how should we think about those changing, given that you guys will still be growing the base?

Did -- do those really moderate at all, given that you are still growing?

Or just kind of wondering, high level, like if we were to roll that forward 12 months, how do you guys think that maybe changes, if at all?

Yes.

Jeff, it won't moderate much.

We are -- we will have a big tailwind from 2019 to 2020 on the decline.

2019's decline was north of 40% on the oil side, this year, high 30s on the oil side, given that we're no longer maximizing growth within cash flow and accelerating or adding 5 or 6 rigs this year.

So that should help.

I can't guarantee that they'll keep going down from here, but certainly don't expect it to ramp up significantly, given the steady state development we're heading towards.

Got it.

And for my follow-up, Travis, maybe for you.

You guys, in the prepared remarks, obviously had a substantial checklist of accomplishments that you guys did in 2019.

I was wondering what's on the 2020 checklist in terms of kind of more kind of strategic objectives or goals for the business in 2020, that maybe in 12 months, you'd come back on the 4Q '20 call and tell us about.

Well, certainly, as we sit here today, the level of major corporate development objectives that we had in 2019 won't be repeated in 2020.

That was an incredibly busy year for us.

What we're really focused on this year is growing the business, increasing shareholder returns and really refining our differential story of growth and yield.

And we think we've got the framework exactly suited to be able to do that.

Our next question comes from Asit Sen with Bank of America.

I have one for Kaes and a follow-up for Travis.

Kaes, appreciate the update on sustaining CapEx.

But historically, you've talked about generating a $675 million of free cash flow at $55 oil.

Could you talk about the sensitivity to this free cash flow to changes in oil price?

And how would you think about adapting the activity program to lower oil prices, say, in a $45 scenario?

Yes.

I'll take the second part first.

If we saw a $45 oil for a couple of months, we would do the right decision, make the right decision and cut back on capital spending.

I will say this addition of free cash flow to the story now allows us to not whipsaw around our activity levels based on a weekly or a daily or a monthly move in commodity price.

So this gives us, an operations organization, an ability to continue to operate steadily and drive efficiencies through the year.

On the free cash flow side, certainly above $55, we start to get a lot of the benefit of our 3-leg collars or unhedged production.

So I think at a -- the midpoint of our guidance on oil, $1 in oil price above $55 gives you $65 million or $70 million of free cash.

And I'll just add to that from a general perspective or maybe a higher-level perspective, Diamondback has always demonstrated that when returns to our investors go up, we lean into that.

Now we've moderated that comment a little bit now because we're so focused on free cash flow generation.

But what goes along with that is when returns go down to our shareholders, we slow activity down.

And I think you go back in early 2015, again in 2016 and even again in late 2018, we've got a track record of doing just that.

When the commodity tells us we're not getting paid for it, we moderate our activity accordingly.

Travis, a follow-up for you.

You guys have been a leader in making changes to compensation structure and appreciate ESG component as part of management scorecard.

But could you provide some early examples of some of the metrics that you're going to track?

What's motivating this move?

And perhaps speak to the issue of flaring and how PRRC has positioned Texas and your conversations with them.

Sure.

The one thing just I want to point out is that the transparency that we try to communicate with our investors, we believe, is best-in-class, and we spend a lot of time talking to our large shareholders.

And some of the things that we instituted in this release were as a result of direct communications with those shareholders, things like holding ourselves accountable for ES&G measures.

We've got maybe up to 10% to 15% now of every individual's compensation is going to be tied to ES&G metrics, things like water recycle, spill control, total recordable incident rate, flaring.

Those are not subject to discretion.

Those are quantitative measures that we will incentivize better performance on.

That's one thing that we've proven at Diamondback is what gets rewarded gets done, and we intend to do that in our scorecard.

We've also adjusted -- and again, we've laid it out in a very transparent way, but -- and we'll do so more when we release our proxy here in a month or so.

We've adjusted now our total shareholder return to where we have modifiers for anything below 0% or negative TSR, we've now got a modifier that takes down our long-term incentive.

Now the converse of that's also true.

Anything above a 15% total shareholder return gets an adder.

But again, that's in response to conversations that we've had with our shareholders.

So we really have 2 objectives.

We have the first, which I think is the most important, is that we want to be best-in-class on all of our ES&G measures, full stop.

And secondly, we want to be best-in-class on the disclosure associated with those things.

And we believe that what we released last night is the very important first step in achieving both of those objectives.

And on flaring, Travis?

Yes.

So flaring is a -- flaring in the Permian Basin is an issue that we, as an industry, have to address.

There's flaring that's voluntary flaring.

That should be eliminated as quickly as we can.

I mean companies have to put their balance sheets to work and make sure the gathering system is in place prior to bringing on wells.

Certainly at Diamondback, we follow that to the strictest letter.

There's also collaboration that we have to make with our gatherers.

Even if we're tied into systems, our gatherers have to make sure that they've got contracts in place that allow that gas to be custody transferred at the wellhead and that gas moves to market.

And so it's really -- it's not all on the upstream guys.

It's really a holistic issue that needs to be addressed by everyone to try to eliminate, certainly, routine flaring out here in the Permian as quickly as we can.

Appreciate the color, Travis.

And I'll just add to that, Asit, that the scorecard that we've added in ES&G has flaring in there.

And I can tell you, from a -- we talked about it on our executive meeting.

We have pretty rigorous reports that we review every week, and we talk about creative ways that Diamondback or Rattler could bring their balance sheet to bear to cause flaring to be eliminated quicker than if we just relied on somebody else.

So we're trying to be creative and willing to put our balance sheet to work, if need be, to eliminate the flaring.

Our next question comes from David Deckelbaum with Cowen.

I just wanted to ask a couple of follow-ups on just the Pecos activity.

I think the first half of the year, you guys are running about 6 rigs there right now.

Is the plan -- does that slow in the back half of the year and then going into 2021?

Or should we think about that as kind of a steady state program?

Yes.

David, I mean it's more about completion cadence, right?

So in the first half of the year, we do have more completions in Pecos than the back half.

I think overall, 2019, we completed almost 100 wells in that field.

And I think the goal here as an organization is to get that down to 60 or 70 on a go-forward basis.

So we are allocating capital in the second half of the year to better return areas, one rig going to ReWard and one rig going to the Northern Midland Basin, particularly as the held-by-production issues that we had in Pecos have subsided and we could have a more steady state plan there with 5 rigs or so running full time.

And David, I'll tell you the execution teams, particularly in Pecos County, have done a remarkable job of maintaining results or improving results, some of which we talked about in the Second Bone Springs.

But they've really driven a lot of costs out of the equation.

And so now the returns continue to improve with the same or better EURs per foot but much lower cost per foot.

So it's again a good example of what Diamondback excels at is you work on the numerator and the denominator at the same time, and we're driving rate of return positively for our shareholders.

For sure.

It's encouraging to hear that.

It also sounds that as you get into the back half of '20 and going into '21, absent everything else, some of those HBP obligations obviously subside going into '21?

Correct.

Okay.

And then I just wanted to just ask one more, just framing this conversation around M&A.

You've highlighted a lot of priorities around sustainable free cash, dividends growth.

When you screen now for M&A, do you start with a priority of free cash accretion?

Because you did talk about, obviously, things have to be accretive.

You also talked about acreage being at heavily discounted valuations right now.

Do you still see room for what would otherwise be NAV-accretive of M&A?

Or does everything now have to become free cash accretive?

Well, certainly, that has vaulted to the top of the category list of the things we look at.

But we really focus on several key metrics.

If you're asking probably what we screen on the first, certainly, free cash flow per share is way up there, also cash flow per share, earnings per share and then the more traditional measures of inventory quality and what Diamondback can do with that property in the form of operational efficiency and then, of course, NAV as well, too.

We still fundamentally believe that NAV is an important valuation metric for our business.

But those are what we believe are the right ways to focus on, on anything you're looking at.

And right now, with the stock where it is, we're focused on buying back the stock because it's trading at a deeper, deeper discount to NAV than anything we're seeing in the market.

Yes, agree with that.

Understood.

We don't have to delete our NAV model just yet.

Yes, hold on to that.

Our next question comes from Michael Hall with Heikkinen Energy Advisors.

You just answered my question as it relates to how the stock price looks relative to M&A opportunities.

I guess the second one I had, just to follow up a little bit on the evolution of co-development, you addressed it in the Midland Basin.

But I'm also curious in the Delaware.

I just kind of look on the slides.

The proportion of the Wolfcamp A that's driving the 2020 program on Slide 14, I guess, how does that evolve over time?

Should we expect that to kind of grind lower as a percentage of the total in '21 and beyond?

Or any color on that?

Yes.

Michael, I think that's fair, right?

I think there's a secondary zone in each of our 3 fields that we think competes for capital today.

In Pecos, it's the Second Bone Spring, so that's going to get more attention.

In ReWard, it's the Third Bone Spring.

We're doing a lot more co-development between the A and the Third Bone Spring in that acreage position in 2020 and beyond.

And then up in the Vermejo area, the Third Bone Spring is good but also the Wolfcamp B deserves some attention from a rate of return perspective.

So in each of those -- each of those fields has a different development strategy.

But unlike the Midland Basin, where in the Midland Basin the zones that are being co-developed from a rate of return perspective are in a narrow band, the Wolfcamp A versus the other zones in the Delaware Basin had always said, "Drill the Wolfcamp A and go to the other zones later." But with the Second Bone, particularly in Pecos getting better, that's getting more attention.

Our next question comes from Charles Meade with Johnson Rice.

I want to go into the -- there's a little bit of tension in some of your -- or at least I see some tension in your prepared comments.

You talked about how we've had a lot of volatility in late '19 and even in early '20 with the commodity price.

That's on one hand.

But on the other hand, I get your message that the dividend, your commitment to the dividend is -- you're committed to it, and those are the first dollars out the door.

But I'm wondering if in broad terms, you can give us any insight in your thinking or the Board's thinking.

Is there a limit, maybe a soft limit on the percentage of your cash flow from ops that you wouldn't want to exceed in terms of the dividend payout if commodity prices fell lower?

And conversely -- go ahead.

I'm sorry.

No.

Finish, I'm sorry.

Well, no, I'd say, conversely, is there some minimum level that you're targeting if oil prices hit higher?

Yes.

You can go back and look at some of my previous prepared remarks, where we've talked about the Board wanting to seek a dividend yield that approaches the S&P 500.

And to get prescriptive much beyond that, we don't think is the right way to communicate that message.

Kaes outlines right now that what -- how we look at what to do with free cash flow above our maintenance CapEx.

But I think at the end of the day, Charles, just simply said, when we look at capital allocation, we look at ways to drive not only current shareholder value but also long-term shareholder value.

And certainly, the dividend and the growth of that dividend is very important in that conversation.

What we have seen is some companies that get dividend -- that let the dividend get so high, it actually can become an impediment to doing what oil and gas companies are supposed to do, which is convert resource into cash flow.

So we're ever mindful of that, but it's a discussion that we have at the Board level on an annual basis.

And I can just tell you that we're laser-focused on current shareholder value creation and long-term shareholder value creation.

Yes.

That's helpful color.

And then going back to your Limelight, your Limelight well.

And I appreciate your earlier comments that you guys are much bigger company now certainly than when you guided this play 3 years ago, but that it's still encouraging to get that kind of first well results.

What would you need to see in the combination between well cost from here and productivity from this -- here as well, what would you need to see from this play to make it really compete in the top tier of your overall portfolio for capital?

So we're pretty pleased with the oil profile that came out of it, that we're seeing so far that -- in that first well, and the decline profile looks actually pretty good.

Of course, we're ever mindful that it's a single well in a section.

But I think it's 2 things.

One, you've always got to push greater recoveries, and we have to push a lower development cost, which is something that's right in the wheelhouse of the Diamondback operations teams, both driving EUR and reducing well costs.

So I think there's, Charles, more to come on this story.

We'll probably drill 1 or 2 more appraisal wells this year.

And then we'll talk about it more in 2021 if we're successful in accomplishing those objectives, and it starts attracting more capital in the allocation process.

Our next question comes from Richard Tullis with Capital One Securities.

Travis, real quick on Limelight, just to continue with that theme.

You drilled the Meramec with the Xanadu well.

The upcoming appraisals, do you anticipate going after any other targets there in Limelight area?

Yes.

I'm going to let Dave answer that question.

Dave?

Yes.

For the next 2 wells that we have upcoming for the appraisal project, as we move to the south within the Limelight trend, we're actually going to be targeting the upper portion of the Woodford.

And then we're going to be drilling a well close by to the Xanadu, further driving development efficiencies in the Meramec itself.

Okay.

And lastly for me.

Looking at the Northern Delaware Basin acreage swap referenced in the release, how did that transaction or group of transactions come together?

And how much net acreage remains in New Mexico?

Yes.

Richard, we've worked on probably almost 40 trades throughout the year.

This was certainly the largest.

For us, entering New Mexico as an operator to operate 6 or 7 sections just didn't make sense, given that we can bolt-on to other blocks of acreage that we operate in Texas.

So that certainly -- that trade is one of many that worked out really well.

Today, we have about 2,500 acres left in New Mexico, primarily non-op with one operated well.

Our next question comes from Leo Mariani with KeyBanc.

Just wanted to follow up on one of your earlier comments here, just as a point of clarity.

If I heard it correctly, did you guys kind of say that production growth on a quarterly basis in '20 would be maybe a little slower in the first quarter and then pick up in second quarter of '20 and then kind of be steady for the rest of the year?

Just wanted to make sure I understood that cadence.

Yes.

That's fairly up.

We plan to grow off of what was a very, very good number in Q4.

It exceeded our internal expectations.

But we do expect to grow off that number in Q1 and then have steady growth throughout the year.

Okay.

That's helpful.

And I guess just with respect to well cost.

Wanted to see if you could kind of give us anything little bit sort of leading-edge here in terms of maybe what you've seen in the last couple of months here, just to kind of kick off the year in 2020, maybe versus fourth quarter averages.

Were you guys able to continue to drive efficiencies and maybe benefit from some lower-service cost deals that you might have negotiated in 4Q to kind of start the year here in '20?

Any comments around that?

Yes.

So service cost reductions are not things that we count on as we forecast our capital budget.

Those are not permanent.

We know when commodity price turns back around, those go away.

What we really are focused on is what type of cost improvements can we make that are more permanent in nature.

And that's, again, what I -- the Diamondback operations organization just absolutely excels in.

And we were talking just this week about a 15,000-foot lateral that we got drilled in 11 or 12 days.

And so we continue to see faster and faster well results from our operations organization, and we expect that to continue to happen throughout this year.

And I'm not showing any further questions at this time.

I'd like to turn the call back over to Travis Stice for closing remarks.

Thanks, again, to everyone participating in today's call.

If you've got any questions, please contact us using the contact information provided.

Ladies and gentlemen, this does conclude today's presentation.

You may now disconnect, and have a wonderful day.