Diamondback Energy Inc (FANG) 2018 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Diamondback Energy Fourth Quarter 2018 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, Adam Lawlis, Director of Investor Relations.

Sir, you may begin.

Thank you, Towanda.

Good morning, and welcome to Diamondback Energy's Fourth Quarter 2018 Conference Call.

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

Representing Diamondback today are Travis Stice, CEO; Mike Hollis, President and COO; and Tracy Dick, CFO.

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

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

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

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

The reconciliations with the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon.

I'll now turn the call over to Travis Stice.

Thank you, Adam.

Welcome, everyone, and thank you for listening to Diamondback's Fourth Quarter 2018 Conference Call.

2018 was another transformational year for Diamondback.

We successfully closed 3 large acquisitions in the fourth quarter, including our acquisition of Energen, which, combined, nearly doubled our core acreage position.

Diamondback now has over 364,000 net acres in the core of the Midland and Delaware Basins, along with another 96,000 net acres of Permian assets, the majority of which are on the Central Basin Platform, which we are working to divest as part of our grow-and-prune strategy.

Diamondback grew production 53% year-over-year without giving the effect to the Energen merger, and exited the year producing over 250,000 BOEs per day in December after closing the merger.

Our reserves are up almost 200% year-over-year to just shy of 1 billion barrels of oil equivalent, and our organic reserve replacement ratio for 2019 was over 450%.

Drill bit F&D was essentially flat year-over-year at $7.28 a barrel and proved developed F&D was $10.44, highlighting the combination of our acreage quality and capital-efficient cost structure.

Commodity prices declined dramatically in the fourth quarter, and as a result of this volatility, Diamondback outspent cash flow for the quarter.

This is against our core operating philosophy, and we reacted as quickly as possible after closing the merger by announcing a reduction in activity for 2019, and subsequently dropped 3 operating drilling rigs and 2 completion crews over the course of the last 2 months.

Moving to 2019.

We trimmed our capital budget versus previously described expectations in December, and we still expect to grow production 27% year-over-year while also paying a 50% larger dividend than we did in 2018, all within operating cash flow.

As Mike will explain in detail later on, on this call, we are realizing more synergies faster than expected after closing the Energen merger, all of which are reflected in our capital budget and projected operating costs in 2019.

Lastly, we are actively working on dropping down the remaining mineral and royalty assets held at the Diamondback level to Viper and expect to do so at some point in 2019.

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

Thank you, Travis.

Turning to Slide 8 through 10.

We give an early-time update on both the primary and secondary synergies presented when we announced our merger with Energen last August.

The highest-value primary synergy presented during the merger announcement was a reduction to Midland Basin well cost.

Based on the midpoint of our 2019 cost per completed lateral foot guidance for the Midland Basin of $785, Diamondback expects to save $215 per foot versus Energen's second quarter 2018 actual cost or over 95% of what we expected to achieve per foot by early 2020 in the merger presentation.

This savings is not only attributed to the immediate implementation of Diamondback best practices on Energen acreage, but also due to some efficiencies the Diamondback team has learned and implemented from legacy Energen best practices.

Also, the benefit of size, scale and buying power on service costs have been greater than originally anticipated.

Running these savings through 40% of our Midland Basin well count for the year results in almost $150 million in capital savings.

In the Delaware Basin, we are seeing enough improvements to move what was originally a secondary synergy into the primary synergy bucket.

In 2019, we expect to save between $55 and $60 per completed lateral foot versus actual Energen well cost, most primarily due to multiwell pads, longer laterals, completion and casing designs as well as the cost benefit realized associated with larger scale.

Overall, we expect Delaware Basin well costs to decrease by almost 7% versus 2018, again due to improved efficiencies, completion design and service cost concessions.

As also seen on Page 8, Diamondback has realized all of the expected $30 million to $40 million of G&A synergies earlier than anticipated, which are fully reflected in our 2019 guidance.

Looking ahead, we have line of sight of even more combined capital, operating, midstream and mineral synergies, and we look forward to updating the synergy scorecard with these initiatives in progress.

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

Thank you, Mike.

Diamondback's fourth quarter 2018 net income was $2.50 per diluted share, and our net income adjusted for noncash derivatives and other items was $1.21 per diluted share.

Our consolidated adjusted EBITDA for the quarter was $468 million, and our cash operating costs were $8.10 per BOE, including LOE of $4.51 and cash G&A of $0.67 per BOE.

During the quarter, Diamondback spent $424 million on drilling, completion and non-operated properties and $101 million on infrastructure and midstream.

For the year ended 2018, we spent $1.4 billion on drilling, completion and non-operated properties and $306 million on infrastructure and midstream.

Diamondback ended the fourth quarter of 2018 with $192 million in standalone cash and approximately $1.5 billion of outstanding borrowings under its revolving credit facility, resulting in $700 million of liquidity.

Finally, Diamondback's Board of Directors have declared a cash dividend for the fourth quarter of $0.0125 per common share payable on February 28, 2019, to shareholders of record at the close of business on February 21, 2019.

Operator, please open the line for questions.

(Operator Instructions) Our first question comes from the line of John Nelson with Goldman Sachs.

Congratulations to the team on the velocity of the synergy capture.

Quite impressive.

Thank you, John.

Starting, maybe, Travis, with your view on share repurchases in the capital pecking order.

And in particular, your share count's up about 70%.

Your stock is down about 20% in the last year.

So with that in mind, I'm just curious how the company thinks about share repurchases, both with potential monetization proceeds as well as 2020 free cash flow.

Yes, certainly, John.

It's key to get to that point first before we have meaningful conversations with Wall Street exactly on what we're going to do.

But I think what we've signaled in the past is that shareholder-friendly initiatives such as share repurchases, a continued focus on increasing the dividend, all of those things are within our bandwidth of what we can do in the form of returning cash to our investors.

And as we progress through 2019 and start seeing the focus on 2020 and the significant free cash flow generation that's going to occur then, I think that's a more appropriate time.

But I'm -- we've committed to continue to grow the dividend and continue to focus on the shareholder-friendly initiatives.

Fair enough.

And then my second question, I think the original guidance targeted something around $50 WTI to be kind of cash flow neutral.

We're a bit above that on kind of strip today.

I guess, philosophically, is the company going to continue to target a $50-type commodity price?

Or would you all add rigs potentially if oil prices remain a bit stronger?

No, I think at this point, John, we've got a pretty good long-term strategy laid out at $50 a barrel.

And I think as commodity price improves back half of year, maybe into 2020, you could look at us to perhaps add 1 to 2 rigs in 2020 and beyond with this significant free cash flow I was talking about.

But I think the point that we made in our December call, which represented a strategic pivot for Diamondback, specifically addressed the wave of free cash flow that's coming, that the pivot is that we're not going to redeploy that all back into the ground.

We're going to start returning that to our shareholders.

We began that again this year by increasing our dividend as well.

So that's the pivot that we've made, and we're committed to continue to look at that even as commodity prices improve.

Our next question comes from the line of Derrick Whitfield with Stifel.

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

We put a scorecard together, and it's what we call our synergy scorecard.

It's on Slide 8 of our investor deck.

And we're going to continue to lean in to delivering all the synergies that we described in the acquisition call in August.

And look, I'm optimistic that we can continue to improve on all of these metrics.

We've -- I talked about in my prepared comments that we're working on a drop-down from Diamondback to Viper, and the midstream assets are all rolled in to our -- the Energen midstream assets are all rolled in.

So these are all those secondary synergies that we've already got tremendous traction behind delivering on those in 2019.

But we're going to continue to update the market on this synergy scorecard.

And as these things materialize, we'll look forward to telling a really good story around these additional synergies above and beyond what we talked about in August.

Yes, I think what's important, Derrick, is that we based the trade on -- or the merger with Energen on the cost synergies and the execution side of the business.

And the other synergies mentioned, minerals and midstream, are really more on the financial side.

So we predicated the deal on the execution and the operation side, and that's what we're most focused on today.

Great.

And then shifting over to the Delaware.

Regarding the Bone Spring shale well that you guys announced in Pecos, that's a particularly strong well given the decline attributes of that interval.

How does that result change your view on capital allocation to the area, if at all?

Well, we were certainly excited about that, and the reason we're excited is that that's a zone or a couple of zones that we didn't ascribe any value to during the original Delaware acquisition.

So we're excited that we're seeing really good positive results.

And we're going to be cautious, I mean, as we further define that zone.

But I think we probably got half a dozen or so on the drill schedule this year, and we'll monitor results.

And just like we always do, we'll react quickly.

If we get greater returns on those zones, we'll allocate more dollars to the highest-grade return stuff.

So it's good news all the way around.

It's good news because it's unrecognized upside that we're now bringing to the table, and it's good news for our inventory count in Pecos County.

Our next question comes from the line of Neal Dingmann with of SunTrust.

Travis, I mean, my first question is around the infrastructure spend.

Could you talk a bit just in the sort of guide you have for this year?

I know you had a bit of, like, what for -- end of last year, a bit of a higher infrastructure spend.

And how do you see that trending now on the FANG, corporate-wide, going forward?

Yes, Neal, I'll take this one.

Our infra spend and midstream spend is going to be $400 million to $450 million for 2019.

Infrastructure is a bit higher on the battery side because we are doing bigger pads and we're drilling in areas that have no existing wells.

I mean, that was one of the primary reasons we did the Energen trade, was how much completely undeveloped acreage they had.

And that results in us needing to build a lot more batteries than expected.

The midstream budget should decline over time, and hopefully, that's in a separate business going forward.

But overall, probably 60%, 65% first half weighted on the total infrastructure and midstream spend, and then 40% in the back half of the year.

Yes, great details.

And then, Travis, just overall question.

You mentioned in the press release about obviously refraining from outspending cash flow enough to be one of the first to adjust the plan.

I guess, when you look at this plan, I mean, how do sort of balance -- I definitely appreciate that, but how do you balance that with more of just sort of a continuity or a stability of your plan versus changing that rig count or that activity more frequent to keep balancing that?

Well, we've got to make sure we don't interrupt the efficiency of the Diamondback machine.

That's one thing that Diamondback is really known for, is our really outstanding execution.

And so we can't disrupt the machine.

But by that same token, Neal, we can't outspend cash flow either.

We've not done that for 4 years, and we're -- and although we had an aberration in the fourth quarter last year, we're -- it's just not part of how we run the business.

And we would have actually dropped activity quicker in the fourth quarter last year, but we were on multiwell pads.

And that makes no sense at all to stop completion on the mid -- right on the mid multiwell pads.

So we take that into account.

And you typically don't see that from the outside looking in, but we're committed to capital discipline.

This is a mantra that we've been demonstrating since the OPEC announcement in the fall of 2014 and the subsequent price collapse.

That's Diamondback.

That's what we are known for.

Our next question comes from the line of Gail Nicholson with Stephens.

Just looking at LOE and kind of your thoughts on how that will trend throughout '19.

And then outside of the potential of sale of the Central Basin Platform, are there other things that you are working on to further improve LOE in the future, kind of in that '20 forward aspect?

Yes, Gail, I'll let Mike answer that question.

But you've heard me say before, until someone actually pays us to produce these barrels, we're going to always lean into our LOE and try to make that lower tomorrow versus what it is today.

So I'll let Mike give you the real answer to that.

But we always focus on LOE.

Absolutely.

Gail, again, we attack it on 2 fronts.

Again, volume increasing helps as well, but a lot of it's on the dollars that we spend.

So again, bringing Energen and Diamondback together, we've done a really good job of grabbing synergies and finding ways to do things better.

So there's areas and things that we've learned from the Energen folks that we're implementing today as well as the other way around.

So what we hope to see is a lower gross dollar amount spent as well as a growing production volume.

So to kind of give you an idea, the Central Basin Platform accounts for about $0.50 of our LOE today.

So again, assuming a sale of the Central Basin Platform, that would come off of our guide.

But on a go-forward basis, again, it's going to be a nice, slow drop in LOE, assuming we can implement all of the initiatives that we're working on today.

Great.

And then I'm just looking at the potential drop-down into Viper.

When you look at Diamondback's ownership in Viper, is there an appropriate level that you guys want to maintain on a go-forward basis?

Yes, Gail.

I think it's fair to assume that with Diamondback owning 59% of Viper, we certainly enjoy owning as much of that business as possible.

And if the parent company is generating cash flow, I don't see a need for the parent company to take back cash in any transaction there.

So certainly, I think Diamondback is looking to increase its ownership in Viper, post the drop-down.

Great.

And just one last one.

Several quarters ago, you guys brought up the Limelight Prospect and doing some appraisal activity in '19.

I'm just kind of curious how that fits into the portfolio today.

Yes, we're probably going test it sometime in the middle of this year.

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

So I have 2 questions.

One, on synergy.

Mike, I think you mentioned about increased buying power.

And just wondering, now that you're more scaled, could you talk about specific incremental efforts on the supply chain, rebidding contracts, et cetera, and then how you're thinking differently about the mix of long-term and short-term contracts?

That's my first question.

Absolutely.

So again, when we looked at the 2 entities apart, we went through and we didn't use all of the same services and vendors as well.

So we went through and grabbed whichever ones appeared to have the better quality, service and price.

And we initially did that day 1 and swapped out some services on both the Diamondback and Energen side.

Again, with the size and scale, we have seen a larger change in price associated with the decrease in commodity price that we've seen.

So we -- going back and actually bidding a larger package, we've seen an increase in that -- that change in what we're getting charged.

Again, it's a hard number to tie down.

But we've gone back to the vendors and business partners and asked, "If we were just Diamondback standalone, what is that difference?" And it looks like it's roughly -- of the change, roughly 20% of that change is what we're seeing for size and scale.

Now as far as how long we plan on tying up services, again, right now we keep -- just like we do on any other thing we hedge, we keep a hedge book of what we have long-term contracts with and what we have more of a well-to-well.

But in general, we're looking at 6 months to 1 year on most things.

Okay.

And Travis, a big-picture question.

As the industry moves more towards a manufacturing style, where do you see use of technology and what are you most excited about?

And last quarter, you talked about dual-fuel operation in one of the rigs in Delaware.

Could you perhaps update us on the economic benefits you're seeing so far and plans going forward?

Yes, I'll let Mike talk specifically about our dual-fuel operations.

But listen, technology in our industry, and particularly, any manufacturing business, can have a chance to make a huge impact to the efficiency of the operations.

And we think that that's going to happen inside our industry as more and more advanced technologies come to bear.

And those things are -- whether it's the way that we transport fluids, the transport media, the actual proppants, the technology at which we steer these wells in zone, the real-time feedback and all the way up to artificial intelligence, these are all things that we believe are going to make a large change in the efficiency of the manufacturing process called producing and drilling for our barrels out here in the Permian.

I'll let Mike answer the dual-fuel question.

So Asit, the dual fuel, we're currently running in 2 fracked fleets on dual fuel.

We have, I believe, 5 rigs currently running dual fuel.

So again, where it makes sense, where we have the availability and the equipment already converted, we're making those moves anywhere it makes sense to do it today.

On the implementation of new technology, of course, we use real-time data and analytics on the drilling side, the completion side.

Basically, all of the things Travis mentioned a second ago, the answer is yes on all of those, from how we're doing our processing of our seismic data to how we steer, complete and land these wells.

So the answer is yes, we're seeing a faster change of progress today than we've had in the last decade or 2, which is what you would expect, but we see greater things coming.

We're not going to guide to any of those changes because we don't have them here today.

But we're very hopeful for what's coming.

Our next question comes from the line of Ryan Todd with Simmons Energy.

Two things.

Maybe a high-level question.

I mean, you've, over the last couple of quarters, you've got -- you've shifted your focus so much towards greater free cash flow generation.

How do you think about a target for -- longer-term targets for free cash flow generation at this point?

Is it reasonable for you to move towards a free cash flow yield that's competitive with the broader market?

And how do you think about the timing of how that plays out, whether you make a conscious effort towards it or whether it just happens organically within the portfolio?

It's really both.

I mean, it's going to happen -- we've made a conscious effort to do so, and that's why we pared back activity to increase our cash flow.

But it's also going to be happening organically as we continue to look into the future.

I mean, as I mentioned in some of my earlier comments, 2020 and beyond, we probably will add 1 to 2 rigs, but we'll still be in the process of generating significant free cash flow.

And that's what really has us excited about this new company that we've combined with Energen, is just really that significant free cash flow generation that starts in 2020 and beyond.

And maybe as a follow-up to that, I mean, historically, you've been a material consolidator in the basin and a very successful consolidator.

I mean, how would you characterize -- and I know you just closed the deal, but M&A appetite and the M&A environment at this point?

And previously, you had commented how the use of free cash would allow you to potentially use some of that cash to fund more cash-driven deals as opposed to stock-driven deals.

Is that still part of the strategy?

Is it less part of the strategy than it was previously?

Any comments overall on that would be great.

Yes, so specifically to Diamondback, what we're focused on right now is we continue to do small bolt-on trades to make sure we can operate these units and drill longer laterals and operate them with greater efficiency.

And so we're continuing to do that.

The other, really, business development focus that we're really digging into right now is a continued focus on doing swaps and trades with some of the scattered acreage that we acquired through the Energen asset.

And so that's what our land teams, particularly, our little business development organization is right now doing that trade.

From a macro sense, it's obviously been real -- we think it's been real quiet on the M&A front.

And I think there's a reason for that.

And that is that the -- all operators are trying to respond to living within cash flow.

And the days of buying undeveloped acreage with 1 or 2 wells on it, in terms of not being able to be accretive on a cash flow perspective, those days are behind us.

So Diamondback, we always have an obligation to our shareholders to try to look for deals that can create unreasonable value.

But the bottom line is, right now, we don't see a lot of those -- any of those deals out there, and we're focused on doing the small bolt-ons and the trades.

Our next question come from the line of Tim Rezvan with Oppenheimer.

First question I had is on the realizations.

On Slide 13 of your deck, you gave us some kind of guidance quarter-by-quarter through 2019.

And I was wondering if you could talk about the assumptions, I guess, in that first and second quarter of '19 because you appear to have more Midland exposure in the second quarter of '19, but you're guiding to tighter differentials.

So maybe just kind of broadly talk about sort of what assumptions you have that are underlying this guidance.

Yes.

Yes, Tim.

So the assumptions are the market prices on a core basis as of last Friday.

So you can use the strip as of a couple of days ago and use that as your assumption for price.

Now the Midland differential has come in significantly in the past couple of months and it's projected to stay pretty narrow.

So a couple of our deals roll off at the end of the first quarter.

One of our deals goes down in differential at the end of the first quarter.

So once we realized how large Plains' Sunrise expansion was and got wind of what the enterprise is looking to do on the NGL side conversion, we stopped signing any fixed differential deals.

So leaving that exposure to the Midland market, we're happy for the majority of our barrels to be exposed to that Midland market as we've kind of gone through the takeaway crisis that was expected in 2018 and 2019.

Okay.

Okay, that's helpful.

I appreciate that.

My next question, I guess, is for Travis, if you could put your sort of director hat on now.

Diamondback has always had one of the more honest and transparent discretionary comp kind of formulas in the industry.

As the company has matured and as you talk now about return on capital employed and free cash flow generation, could you talk about how kind of, if at all, the board is thinking about appropriate discretionary comp metrics for senior management?

Just trying to understand kind of where -- what the priorities are over the medium-term future.

Tim, I appreciate your comment on transparency.

We built Diamondback around 3 kind of core tenets: best-in-class execution, low-cost operations and transparency.

And that's been part of us since the very beginning.

So I appreciate your transparency comments.

Really, I think, Tim, what we did in 2015, I think we're one of the first companies to do so in the comp.

And it's not just executive comp because we apply the same metrics to everyone in the organization.

But we changed the comp focus away from growth in volumes and reserves.

In fact, we removed those entirely from our scorecard and instead replaced them with efficiency measures.

And those efficiency measures are proxies for returns, return on capital employed and other returns measures.

So that has continued going forward in the future.

And while we've not set the focus for -- we've not set the scorecard yet for 2019, I anticipate the board to again come back to the things that we think are important, which is generating high returns to our investors and keeping our operating metrics pristine and our execution still best-in-class.

And so that's the way we're going -- I anticipate the board to continue to go in 2019.

It's -- I think it served us well over the last several years.

Okay.

And just to get a little more clarity.

You talked about higher -- good returns for investors.

Can you talk about what you mean?

Is that return on capital employed?

Is that cash margin?

Is that all of those things?

Well, the efficiency measures that we put in 2015 were -- we used them for proxies as the numerator and the denominator for return on capital employed.

And we did so, so that we could build a track record of being able to see what our return measures look like.

I think in most all of our investor presentations for the last several quarters, for sure, if not longer than that, we've included return on capital employed measures.

So again, we haven't decided what 2019 is going to look like.

But it's certainly going to be returns focused for -- towards our investors.

Our next question comes from the line of Mike Kelly with Seaport Global.

Travis, I was hoping you could potentially frame and just give a little bit more color on the mineral drop-down opportunity.

I guess, I'm really just trying to get a sense of how impactful this could be for you guys.

Yes, Mike.

I mean, there's a significant amount of minerals still held at the Diamondback level prior to the Energen deal.

It's probably about 2,000 net acres that Diamondback just owns, still, at the parent level.

The Energen deal adds another $60 million to $80 million or so of cash flow.

So we're trying to rightsize that deal.

I think it can be a very sizable trade, meaningful both for Viper and Diamondback, and a near billion-dollar type trade.

Okay, appreciate that.

And kind of following on to Gail's question on this.

It sounds like you would -- the mechanics of that deal would be more of, you'd take Viper shares -- more weighted towards Viper shares versus cash?

Is it -- am I thinking about that correctly, or how should I think about that?

Yes, we really -- those -- we've got to have some board conversations on exactly how we're going to realize that value, but that's probably a good assumption at this point.

Okay, great.

And then shifting gears to the Northern Delaware.

The results there look pretty awesome.

And just curious what the game plan looks like for the Northern Delaware in 2019, maybe we could just talk about expected activity levels, wells put online, et cetera.

Yes.

That's one of the things that we're really excited about in this quarter's release.

And it's probably -- well results are not the focus.

I understand that in anybody's quarterly release.

But those 4 wells that we delivered in the Vermejo area, which is, quite honestly now, the best stuff in Diamondback's portfolio and we acquired that from Energen, those 4 wells, I think they were over 400 barrels of oil per foot, those are the best wells we've ever drilled.

So obviously, those -- that area is going to get as much capital allocation as we can put in there as quickly as we can.

Got it.

And maybe just a quick follow-up on that.

Are you comfortable giving me kind of a ballpark number of how much acreage you have exposed around there?

It's -- kind of talk rig count, we're going to run probably 4 or 5 rigs in that area.

It's probably 50,000 or 60,000 total acres in the core area.

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

I wanted to follow up on some of the free cash flow comments you guys have made.

And I appreciate maybe it's too early to talk about specifically how you'll be returning cash, but maybe you can talk about your targets for leverage and if you're still hoping to strengthen the balance sheet further and how your Viper stake plays into how you think about that leverage.

Yes, Drew, I think one-time proceeds, asset sales, proceeds from minerals or our midstream business go towards debt reduction at the parent company.

Any return to shareholders, whether that's a buyback or the dividend, should come from true free cash flow, in our opinion.

We still want to maintain below 2x leverage at the parent company on a consolidated basis, but we also don't want to lever up any of our subs above 2x either.

Our next question comes from the line of Jeff Grampp with Northland Capital Markets.

[Remember that] you guys set up a nice little upward revision on the drilling inventory number.

It looks like you're pushing almost 30 years now of inventory.

So I was just wondering, do you feel that's a good level for inventory?

Or maybe you guys can look opportunistically to monetize some of that tail end or -- just high-level thoughts on kind of the right level of inventory for you guys.

Yes, Jeff.

We've been very clear on the grow-and-prune strategy, that the Central Basin Platform is certainly up for sale and that process is ongoing.

At this point, with the remaining inventory, certainly, we would look to dispose of some inventory at the back end of our 30 years of drilling inventory.

But we're not actively working on any of that today given the commodity price environment.

All right, great.

Great.

Appreciate that.

And then just on the well cost side, a little bit curious how you guys kind of envision '19 playing out and kind of looking maybe into some -- an early sneak peek of what '20 -- how that flows through to '20.

So can you guys talk maybe a little bit, how do current well costs compare to the guidance that you guys put out?

And maybe, how do things look like at year-end just relative to what's kind of baked into the guidance numbers that you guys have?

Jeff, the current costs that we're seeing today is pretty well baked into our guidance.

Now going forward, it's all going to be dependent upon, typically, what activity and oil price does, but what we're seeing right now is we're having much better conversations with folks today.

So we assume some softening will happen over the next couple -- or the next quarter, at least.

Again, it's going to depend on what happens on the second half of the year.

But for right now, we're planning for basically service costs and well costs to stay flat.

A lot of the synergies and initiatives we're working on today will have some timed-out events.

What we talked about is what we have today, but we have some other initiatives that we're working on that should come to fruition throughout the year.

So we see well costs coming down very slightly throughout the year unless there's some other change in activity level.

All right.

Really helpful, Mike.

And just if I can sneak a housekeeping one.

Can you guys disclose kind of ballpark what the platform assets are producing today?

About 7,000 to 8,000 barrels a day.

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

I just had one -- obviously, a lot on the call already, but just curious on the hedging side.

Obviously, the debt's a little bit higher now but you'll be working some of that off, it seems like, as the year goes on.

Where do you guys get comfortable on the overall hedges?

The basis is kind of covered, but just where should we be thinking about the hedge profile as the bigger company now moves forward?

Yes, Jason.

I think our strategy has changed a bit as we've become a bigger company.

In the past it was, "Let's protect the minimum capital required to hold our acreage position together." And now it's kind of shifting towards -- we did disclose this number of 14 rigs to maintain exit-to-exit production, which is about $1.5 billion or $1.6 billion of total capital.

I think on a go-forward basis, we're going to look to hedge probably that maintenance capital, and then everything above that is exposure to the investors for both growth and oil price.

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

I wanted to look at Slide 14 and ask you kind of more of a bigger-picture question, particularly, about your inventory versus your peers.

And so you guys have ID-ed a lower inventory per footprint, but I could imagine that converging one or two ways: with the industry down to you or you increasing your location count up to be more even with the industry.

I have a guess which way that's likely to converge, but I'm curious what your guess would be.

Charles, the way that we've always managed reserves, location count, production guidance is that we want to be conservative in the way that we communicate because a lot of things happen in our industry, and typically, they always take things away.

So in our experience, particularly as it pertains to inventory well -- inventory count, it's a lot easier to add locations, as well results and technology allow those locations to be there, than it is to start taking them away.

And as you've seen the reserves numbers start coming out this year, I think that's one of the first indications, is seeing negative performance revisions in our industry.

And most of those negative performance revisions are going to be attributed to wells being drilled too tightly and reserve auditors taking -- walking those locations back.

So we're very comfortable that we have sort of an at-least view of what our inventory looks like.

And earlier on the call, someone actually calculated it at 30 years' worth of inventory.

So we don't feel a compelling need to start adding a bunch of locations just in the form of sticks on a map.

So we're comfortable where we are right now and we'll add as technology and well results dictate.

Got it.

And then to push a little further on this, Travis.

If the industry, in general, just generally speaking, not the case for you guys, but did get a little too close and they're backing up and going more to like spacing more like yours, it seems to me that, that would lead to probably better individual well results and more productivity in the near term.

But that, in the mid- to longer-term, would mean there's less quality inventory that -- than was thought maybe 6 or 9 or 12 months ago.

Does that -- do you see it the same way?

Or is that not something you...

Yes.

No, that's right.

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

Absolutely.

Got it, got it.

And then if I could just sneak in one more.

You talked a lot about your grow-and-prune strategy, and that makes sense.

I'm curious, you've got some kind of far-flung assets, whether that be kind of in Southern Upton or Reagan or in Lea.

Are those kind of active interests that you're trying to trade now?

Or is the trade activity more in the middle of the development fairways that you're seeing?

It's a combination, Charles.

We probably have 8 or 9 active trades right now, ranging from 150-acre swap to 1,000-plus acre swap.

So all options are on the table.

The real prune is the Central Basin Platform.

But as we talked about Page 14, as long as we could keep working on that average lateral length going up, with us drilling 9,400 average lateral feet per well this year, if we get that inventory number up, our land and BD teams, we have successfully executed on our grow-and-prune strategy.

Our next question comes from the line of Leo Mariani of KeyBanc.

I wonder if you could give a little bit more color around those 4, I guess, stellar wells that you guys recently drilled, I guess, and completed there on the Energen acreage.

I guess, were those prior wells done by the Energen team with sort of their own drilling and completion methods?

Or were these done by FANG with your own techniques?

Leo, yes, the wells were already drilled by Energen.

So -- and again, the great thing about the combination is that we had very similar philosophies on where we open the land and drill the wells, so they landed in very similar spots to where we would have chose as well.

But the actual completion happened right at and a little after the close.

So again, we had already merged some of the operation groups by that time.

But no, again, a collaborative effort.

Okay, that's helpful.

I'm just trying to get a sense of whether or not you guys are maybe doing things a bit different on the completion side than what Energen was doing.

You clearly laid out some material cost reductions versus Energen.

Just trying to get a sense of whether or not the actual completion designs or methodologies also might be a little different and leading to some better results.

No.

I think the beauty of the trade is that we're so confident in the actual well results we were seeing on the Energen acreage.

The benefit that we had is on the cost side.

So 2 organizations that saw eye to eye on design and completion size and landing points, but on a cost perspective, combined, that's where the real synergies rest.

Okay, that makes sense.

And I guess, just looking at your fourth quarter projection.

It seemed very strong, for sure, particularly given the fact that you guys were kind of putting these 2 companies together in the fourth quarter.

It certainly seems like it sets up a nice momentum into 2019.

I was wondering if you could kind of talk a little bit to kind of production cadence during the year.

Is the growth kind of more midyear-weighted or back half-weighted in '19 or is it pretty ratable throughout the year?

Yes, Leo, I'll tackle the Q4 performance because I think there are a few important points there.

Our base business full year production of 121.4 MBOE per day was significantly above the guidance we presented in Q3.

So the base business outperformed by 8,000 or 10,000 barrels a day in Q4 without giving effect to the Energen trade.

So I think that was very important.

Looking ahead to 2019, we gave a number that the combined business would gain about 250,000 barrels a day in December once we combined the 2 companies together.

We expect to grow basically ratably through the year.

I think D&C CapEx is going to be pretty consistent through the year, with some acceleration towards the back half.

But we kind of see 20% or so, exit-to-exit, as being a very important number for us.

Okay, that's very helpful.

And I guess, just lastly, on cash G&A.

I guess your guidance for this year is basically below $1 per BOE.

I couldn't help but notice that your fourth quarter number was around $0.67 per BOE, which, I guess, is quite a bit below.

So should we be thinking kind of closer to that type of number?

Or is there maybe a little bit of upward pressure early in the year if you guys have any severance payments or anything like that?

I think through the year, you can pick a number between that $0.67 and $1 and be in a good shape.

We just like to say under $1 because it's such an industry-leading number.

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

A lot of mine have been addressed.

One thing, I guess, we haven't hit on is just on the kind of the people side of the equation.

How are you all situated with people now at this point?

Obviously, you had a pretty substantial step-up in activity here as you combined the 2 companies.

Are you all set on new hires?

How much of the Energen staff came over and just kind of where are you at on that front?

Yes, Michael, the operations organization for Energen is set here in Midland.

And so I think there's 200...

250.

250 there that just rolled right into our mix.

And then we've got some employees that are in Birmingham that are transition employees.

So they're still taking care of some of the base functions in Birmingham as we wanted that office closed.

And then we're fortunate enough to get some folks to move from Birmingham both into our Oklahoma City offices and back here to Midland as well, too.

So we're continuing to look to increase headcount.

As Kaes pointed out, we've got industry-leading G&A, but we're going to continue to add the best athletes in the draft that we can find on -- every quarter.

All right.

They're probably excited to join the team.

The other I have is just on kind of the split of the rigs, to the extent you guys can provide any more granularity, particularly on the Midland Basin side.

I'm just curious, like, how we should think about -- yes, just kind of where in each of those kind of sub-operating areas -- how much in each of those areas you'll have from a rig count perspective.

Yes, I'd define the Midland Basin into Northern Midland Basin and then Glasscock County.

And we're probably going to run about 1.5 rigs in Glasscock County, that gets you 30 to 35 wells for the year; and the rest of Midland Basin rigs, 8.5 or so will be in the Northern Midland Basin area.

And Midland Basin will be about 55% of our total wells for the year.

The Delaware, 45% of total wells for the year.

I'd say, rig count-wise, 10 to 11 rigs, with 4 of those in the Reeves County Energen block and the rest split between our ReWard and Pecos positions.

Okay.

That's super helpful.

If I might, just one last on the grow-and-prune strategy.

Where would you say you have the best opportunity for the grow side of that equation as it relates to these trades and swaps?

Like, which of these little sub-areas you think are the most likely to change over the course of the next year or look more blocky, I guess?

Yes, I mean, I think -- you look at what we did in Spanish Trail North.

It was series of trades and now we're actively blocking that up.

I think we still have some work to do around our ReWard position.

And certainly, in the Vermejo and the Northern Delaware Basin Energen position -- legacy Energen position, there's a lot of non-operated properties around there that we prefer to operate given our cost structure.

And I think we're going to be actively working to block that area up and trade non-op position for an operated position.

(Operator Instructions) Our next question comes from the line of Eli Kantor with IFS Securities.

I couldn't help but notice the big increase in your other locations within the inventory breakdown you gave on Slide 14.

Can you give us some additional detail on what percent of those locations are operated versus non-op, what intervals comprise this other category, how the locations are split across those various intervals and how development of the other locations will compete for capital relative to the locations you break out for the Wolfcamp, Spraberry and Bone Spring?

Yes, I'll take that one.

Energen kept more Wolfcamp C and Wolfcamp B inventory than Diamondback did in the Midland Basin and had more exposure to it than we did.

So that makes up a good amount of the other category.

And then non-op is about 400 net non-op locations as well, and that comprises a good piece.

Now on the Delaware side, Energen has some Avalon and Brushy Canyon locations, where we don't have that in the Southern Delaware Basin.

And then in terms of this upcoming monetization of Rattler, can you talk about the various considerations being made in deciding what percent of the equity you'll ultimately sell?

Yes, we can't talk about that, Eli.

It's on file with the SEC and you're going to have to look at the S-1 filing online.

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

I would now like to turn the call back over to Travis Stice, CEO, for closing remarks.

Thanks again to everyone participating in today's call.

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

Ladies and gentlemen, that concludes today's conference.

Thank you for participating.

You may now disconnect.

Everyone, have a wonderful day.