Diamondback Energy Inc (FANG) 2017 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Diamondback Energy First Quarter 2017 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, Mr. Adam Lawlis, Director of Investor Relations.

Sir, go ahead.

Thank you, Bruce.

Good morning, and welcome to Diamondback Energy's First Quarter 2017 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 on 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 on our earnings release issued yesterday afternoon.

As a reminder, Viper Energy Partners, a subsidiary of Diamondback, will be hosting its conference call at 10:00 a.m.

Central today.

Dial-in details can be found on Viper's 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 first quarter 2017 conference call.

Diamondback has continued the momentum from the second half of 2016 into the first quarter of 2017.

Production continues to rise, up 19% quarter-over-quarter to over 61,000 BOEs a day.

Well results continue to improve across our asset base and we have begun operations in the Southern Delaware Basin after closing 2 transformative acquisitions in the last 3 quarters and more than doubling our acreage footprint of Tier 1 inventory.

We are excited about the well results announced from our first operated wells in the Southern Delaware Basin in this quarter's release, and I'm proud of the organization for the seamless integration of these assets in a short period of time.

We're operating 8 rigs today, 6 in the Midland Basin and 2 in the Southern Delaware Basin, with plans to move to 5 rigs in the Midland Basin and 3 in the Delaware Basin later this month.

Diamondback is currently operating 3 frac spreads, with one of those operating in the Delaware Basin.

We could potentially increase our operated rig count to 9 or 10 rigs in the back half of the year, should commodity prices improve from current levels.

Put simply, if returns to our investors go up, we will increase our activity to take advantage of those returns with a current asset base capable of running up to 20 rigs as operating cash flow allows.

If returns to our investors pull back, we have the operational and financial flexibility to respond accordingly.

Our full year 2017 production guidance remains unchanged with over 65% annual production growth at the midpoint.

Diamondback continues to deliver on its corporate mission of best-in-class execution and low-cost operations with cash operating costs of $9.31 per BOE and well costs essentially flat compared to Q4 2016, due to increased efficiencies and service cost control.

We have hired many more exceptional employees over the last several months, to help us to continue to execute as we increase activity on our larger asset base.

We also continue to be pleased with the strength of our well results across our acreage, which Mike will elaborate upon later.

As shown on Slide 4, we have accumulated a strong inventory with 6 core areas capable of million barrel plus EURs.

In each of these areas, we are focused on long lateral development with more than 85% of our locations having 7,500 foot or longer laterals.

We've now built an organization with an inventory that we expect will, at current strip prices, allow us to grow with best-in-class rates within cash flow for many years to come.

I'll now turn the call over to Mike.

Thank you, Travis.

Diamondback continues to post encouraging results and achieve new company execution milestones.

Turning to Slide 7. We have new data from our first operated completions in the Southern Delaware Basin.

In Ward County, the Coldblood well, a 7,500-foot lateral targeting the Wolfcamp A, completed in early April, has produced 210 BOE per 1,000-foot of lateral for its first 15 days with an 88% oil cut.

Our first operated completions in Pecos County, the 2 McIntyre State wells, produced an average 30 day IP rate of 158 BOE per thousand foot of lateral with an 89% oil cut.

Additionally, on the Pecos Reeves County line, we completed the State McGary well, that achieved a 24-hour IP rate of 243 BOE per 1,000-foot of completed lateral with an 85% oil cut.

We are currently running 2 rigs in the Southern Delaware Basin with one dedicated completion crew and plan to move a third operated rig from the Midland Basin to the Delaware Basin this month.

We continue to optimize our completion design for the Southern Delaware Basin with a focus on maximizing NPV and rate of return.

Slide 8 lays out the recent developments discussed earlier across our Southern Delaware Basin position.

We look forward to developing these assets with wells landed, drilled and completed by Diamondback, throughout 2017.

Slide 9 goes into further detail on our development plans for the Wolfcamp A, in the Southern Delaware Basin.

Our primary landing target is within the upper portion of the Wolfcamp A. As you can see from these well results posted on this page, these wells have a much flatter decline profile than what we have typically seen in the Midland Basin.

Now turning to the Midland Basin, Slide 11, shows our continued strong well results across the basin.

To note, Howard County continues to outperform expectations and each pad has had better well results than the prior pad, again led by the Wolfcamp A.

In Midland County, we highlight the Wolfcamp A well results, which places this zone in a close second to the Lower Spraberry from a returns respective.

On the lower right portion of the page, we show well results from 2 child wells targeting the Lower Spraberry in Andrews County, using our high-density near-wellbore frac design.

The early results show these 2 wells are outperforming their parent wells, a positive indicator for the targeted goal of increasing recoveries from a smaller stimulated-rock volume.

Turning to operations and execution.

Slide 12 showcases our continued track record of execution as D,C&E costs are down 44% from 2014 and down 5% when compared to fourth quarter 2016.

We have forecasted service cost inflation in our 2017 CapEx budget, primarily from completions.

Diamondback is proactively mitigating these costs where appropriate.

For instance, we are looking at debundling services on the completion side of the business and have a large percentage of tubular goods forward-purchased.

Slide 13 demonstrates our ability to effectively convert resource into cash flow.

At $50 oil, the Lower Spraberry in the Midland Basin and the Wolfcamp A in the Southern Delaware Basin have economics that pay back 80% of capital cost in year 1. We have other zones throughout both basins that will compete for capital.

But these 2 zones will be the foundation for our multi-year production growth expectations even in a sub-$50 oil world.

Slide 14 reflects our spacing assumptions relative to our peers, leaving considerable upside from downspacing potential.

Over 85% of our locations have lateral lengths of 7,500 feet or longer.

Diamondback has continued to have success bolting on acreage and trading with other operators to block up our position.

The capital efficiency of longer laterals is well recognized, and we have now completed up to 12,500-foot laterals in the Midland Basin.

Slide 15 shows our operational efficiency over time as well as our current leverage metrics, cash margins and recycle ratio.

We feel the recycle ratio clearly depicts Diamondback as a leader in creating value for its shareholders, given our high cash margins per barrel and industry-leading capital efficiencies.

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

Thank you, Mike.

Diamondback's first quarter 2017 net income was $136 million or $1.46 per diluted share.

Diamondback's first quarter 2017 net income adjusted for noncash derivatives was $97 million or $1.04 per diluted share.

Our adjusted EBITDA for the quarter was $175 million, up 27% from Q4 2016, due to increased production and realized pricing.

Diamondback's average realized price per BOE, including hedges, for the first quarter of '17 was $41.63.

During the quarter, our cash G&A costs were $1.20 per BOE, while noncash G&A was $1.28.

During the quarter, Diamondback spent $100 million on drilling and completion and $16 million on infrastructure and non-op properties.

We continue to expect to spend within our annual CapEx guidance of $800 million to $1 billion as we maintain our April activity levels and begin our infrastructure investments.

As shown on Slide 17, Diamondback ended the first quarter of 2017 with a net debt to Q1 annualized adjusted EBITDA ratio of 1.4x.

Additionally, our lead bank recently recommended increasing our borrowing base to $1.5 billion from $1 billion previously.

We plan to increase our elected commitment to $750 million from $500 million, previously.

Our full year 2017 guidance presented on Slide 18, remains unchanged for the year, with the exception of the introduction of corporate tax rate guidance of 0 to 5% and lower full year interest expense per BOE.

At current strip prices, we expect to deliver annualized production growth of over 65% at or near breakeven cash flow.

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

Thank you, Tracy.

Diamondback was able to deliver another strong quarter because of our commitment to execution and low-cost operations.

Our production was up as a result of continued outstanding well performance.

Our track record of acquiring properties and subsequently executing above acquisition model expectations gives me confidence we have the organization in place to transfer our best-in-class execution and cost control from the Midland Basin to our over 100,000 net acres in the Delaware Basin and to drive growth at or near cash flow for many years to come.

Operator, please open the line for questions.

(Operator Instructions) And our first question comes from Michael Glick from JPMorgan.

Just given the volatility of the oil market, could you talk a little bit about capital flexibility, kind of at what price point would you look to slow down and where would you do it?

Yes.

When you talk directionally, I always hesitate to give a precise oil price.

But directionally, if we're in that $45 to $50 range, I think we're very comfortable, and we have the balance sheet to be able to execute with our current activity levels.

I think if it starts dropping below $40, somewhere between $40 and $45 a barrel, we'll probably take a pause and see exactly what our future plans need to look like.

And then I think on the other end of the spectrum, if it's $50 to $55, something like that, we'll look at potential increase in activity in the back half of the year.

I think, Michael, one of the reasons that we are hesitant in trying to change guidance at this point of the year is I think there's still a lot of uncertainty in the oil markets, and we want to make sure we preserve the optionality to drive the best returns to our investors, and we will do so just like we've done in the past.

Got it.

And then just kind of higher-level on the Pecos County assets.

How is your view on the acreage changed since you announced the acquisition last year?

Any positive surprises?

Well, I think, if you just look at the well results we put in this release, the -- on the ReWard acreage, we knew that acreage is going to be good, particularly in the Wolfcamp A and the 3rd Bone Springs, and we're really pleased with what we've seen in that Coldblood well, at over -- really good 15-day rate.

I think the McGary well, which was a well that's landed in the Upper Wolfcamp A, which is what we underpinned the acquisition at, that's been a nice surprise.

And the McIntyre wells that were landed in the lower Wolfcamp A, those are still at our acquisition type curve.

And so even though it wasn't in necessarily the zone that we think are going to be the dominant development zone, even those wells are at our acquisition type curve.

So we feel pretty confident across the asset base.

And of course, we continue to watch industry activity, not only for well results but also for continued optimization on the completion side.

So we are -- all in all, we're really encouraged with what we've seen at these early times.

Keep in mind, we took over operations March 1, so it's still early in the game, but we're really pleased with what we've seen.

Got it.

And then just maybe one more on Pecos County.

As you ramp up your operated program, could you talk about your latest thinking on landing zones and completion design?

Yes.

So in Pecos County, what we've talked about even at acquisition time was sort of that Gen 3, Gen 4 level, where we're somewhere around 2,000 lbs to 2,500 lbs per foot.

We think, in Pecos County, the Upper Wolfcamp A, which is where the McGary well was landed, it's going to be the dominant zone.

And so far, with good IP 24 and a week's or so of production that really looks good.

So we're monitoring the things that are going on out in the Delaware, just like we always do.

We're fast followers, and we'll continue to experiment with diverters and sand loadings until we find the optimal balance of sand, fluid and rate of return in that present value.

And our next question comes from Neal Dingmann from SunTrust.

Travis, a question around the Delaware acreage or the particularly, the Brigham acreage.

With that, you brought in a fair amount of minerals.

I'm just wondering on what you'll be drilling there in the nearer-term is -- I know you've got some older slide that shows the upside in Viper, to what it does in some of the other Midland acres.

And I'm just wondering when it looks at the Delaware, two questions, one, will a good bit of that be drilled where you have the mineral free acres as well?

And then number two, does that upside, is that proportionally about the same as what it's been for the Viper -- other Viper units?

I'll let Kaes answer the question specifically, but I'll tell you just in a general sense from a Viper said.

Every time we have a drill schedule meeting on 2:00 on Thursdays, and the well gets proposed to the executive team, the first question is do we have minerals underneath that well location.

So we always try to push activity towards our ownership in minerals.

Kaes, do you want to answer...

Yes, I'll also add that with the 2 or 3 rigs that we're going to be operating in that area, primarily we're going to focus on holding leases.

And then outside of that, those rigs will be drilling on Viper minerals.

And getting the cash flow up on those assets for the right time to drop those minerals down.

So had a lot of success buying more minerals in that area, and I think it's a good sign for Viper as well.

Okay.

And then guys, just one last one.

Just we continue to hear talk about OFS inflation.

Just Travis, in general, what some things you all are continuing to do?

Just noticed in some of your wells versus some of the peers, and it tends to be a bit lower for some time the equivalent sort of frac schedule.

I'm just wondering some things that you all are doing, how are you doing that to keep some costs a bit lower than others?

Well, it's -- it's not just 1 or 2 things.

It's really a systematic approach to the whole organization to try and to do things that generate the best returns at the lowest costs.

And it's -- that sounds a little, maybe, esoteric but really, it is about culturally trying to do the best we can with -- and spend the least amount of money in order to be the low-cost operator.

Specifically, the efficiency gains we continue to push on the drilling side.

We've -- as Mike talked about, we began trying to debundle some of the pressure pumping services in order to control some of those things.

We've -- like diesel, for example, we've bought and supply our own diesel for the frac companies and the drilling rigs.

So it's just a series, Neal, of a bunch of things that we try that we're picking pennies up and you pick up enough pennies, well you make a dollar.

And so while we're proud that even while we're trying to digest $3 billion worth of acquisitions, we were able to push cost down quarter-over-quarter.

I think we've said about 5% quarter-over-quarter.

We know that trend won't continue if commodity prices continue to strengthen through the rest of this year.

But we're real comfortable with what our CapEx guidance is, with a 10% overall increase in well cost throughout the full year.

And as we reported, we really didn't see that in the first quarter, so we're -- I'm confident that our business partners are aware what's going on the service side or aware what's going on in the commodity price world.

And I'm confident that the organization has the ability to execute differentially to control costs as well as activity levels pick up.

And our next question comes from Drew Venker from Morgan Stanley.

I was hoping on -- some of you could talk about the plans in Pecos County, something you're focusing on the central acres block.

I'm just curious how much other testing you'd be doing in the other parts of Pecos this year?

Yes, I mean, right now, as Kaes mentioned, I mean, we're primarily focused on near-term leasehold wells, which -- the biggest piece of those is kind of on the eastern block of the acreage where we've seen good well results previously.

But we've got scattered obligations across the acreage and we'll continue to drill those as well.

So you'll see a mix and as we bring in that third rig, we'll also do some other testing as well.

Drew, just to clarify that when Russell mentioned the eastern side of the acreage, we're talking about that central block, not that portion of the acreage that's down in the southeast -- the far southeast.

So it's where we've got a bunch of good wells in that kind of central -- big central block, he's talking about the eastern edge of that.

Okay.

Okay.

Then across the entire Southern Delaware, how much experimentation would you expect with the completion design?

You talked about going to the -- back to the Gen 3 completion, just not sure how much you think that might need to be changed there, how much additional proppant loading you'd be testing this year?

Well, Drew, we've never stopped tweaking and kind of changing our completion recipe since the very beginning.

We believe that in an organization that demonstrates excellence, you've got to always look for continuous improvement and that's what we're trying to do.

So we do so with our own testing with proppant loading as well as following what industry is doing as well.

I'll tell you what -- one thing I think is a little bit different about Diamondback is that most of the testing that we do -- not most, all of the testing we do, we always underpin with what's the corresponding rate of return in that present value impact for that decision.

And so I think right now, we're going to stay in that proppant loading of around 2,000 to 2,500 lbs per foot.

We'll probably continue to experiment with cluster spacing and stage spacing.

But again, we are -- we understand that the Delaware Basin is new not only for Diamondback, but it's still relatively new for the industry.

So we're going to watch what goes on very, very closely with other operators in the Delaware and we'll -- if we feel like we can generate differential returns to our investors, we'll modify the completion or the drilling or any of the things that we think will drive better returns for our investors.

And our next question comes from Gordon Douthat from Wells Fargo.

Just a question on the downspacing, looked like some of the initial data looked promising, I guess, in Andrews County so my question is, to what extent have you tested downspacing elsewhere across your acreage?

And from what I can tell, looks like it's just in the Lower Spraberry here in Andrews, have you done any downspacing in any of the other zones as well?

Yes, we've done a lot of 500-foot spacing wells in -- on our Midland County assets in the Lower Spraberry, this Andrews County, is our first test at 500-foot spacing in the Lower Spraberry there.

For the most part in our other assets on the east side of the basin, we're primarily at 660-foot spacing in the Lower Spraberry, the A and the B. We do have some offset operators in our Midland County [staff] that are testing downspacing, primarily in the Wolfcamp A and so we're watching that data pretty closely as well.

Depending on those, we may do some additional downspacing in the Wolfcamp A.

Okay.

And then understanding that it takes some time to see how the wells produce and to see how the economics ultimately play out, but what is that time frame in your view?

How long does it take to make the decision, we're going to go 500-foot spacing on a go-forward basis?

Yes, I mean, it's going to take a little time just like our Andrews County test.

I mean, that's one 3-well pad.

So I mean, we'll have to drill some additional wells there before we make a wholesale decision to go to tighter spacing across that whole area.

Okay.

And then one last one for me.

The parent-child production slide that you put up there looked pretty promising.

What were those wells spaced on versus -- where were the child wells spaced versus the parent wells?

All the wells were on 660-foot spacing for those 4 wells.

And our next question comes from Gail Nicholson from KLR Group.

When you talk about being an asset capable of running 20 rigs, is that driven by surface acreage or is that driven by drilling inventory?

It's more -- Gail, it's more of a function of surface acreage.

And how efficiently we can coordinate drilling and completion operations.

It's not a function of inventory.

Okay, great.

And then just looking at the Delaware and the first [expectation] on the drilling standpoint, on the ReWard area as well as the Pecos area.

Has anything surprised you on the drilling aspect from an efficiency aspect, have you've been more efficient, quicker or kind of what's your thoughts on improving those spud to TD days in the Delaware?

You bet, Gail.

This is Mike Hollis.

The answer is yes, we've seen a lot more and a lot new, obviously, as we do our research and look at what other folks are doing out there, it's really not until you get in the sandbox that you really get to learn how the rocks are going to act and talk to you.

So we've learned a lot in our last couple of wells, and we will see -- we will draw the same kind of optimization that we have in the Midland Basin side over in the Delaware side.

Again, just for the depth and the pressure regimes, it should end up taking a couple of days longer on the Delaware side than the Midland side, but we'll start -- you'll see us start migrating towards the Midland performance.

Okay.

And then just also from a standpoint of looking at your conservative spacing, in the Delaware, it looks like you're only assuming one zone in the Wolfcamp A, but I'm assuming when you're landing them, are you landing them in the upper zones so you have the ability to go back and do the lower zone at a later date?

Yes, but that is something we'll evaluate over time.

And as we've said, as we bring in the third rig in the Delaware, we'll probably do some pilot testing where we're testing upper and lower A together.

But right now, we don't have enough data to say that we can do that but we're optimistic.

And our next question comes from John Nelson from Goldman Sachs.

Your oil mix, [K Van't] had street estimates for the quarter, and if I take a look at the ops update you are higher than about 90% of oil wells.

Wondering if you could just speak at a high-level how should we expect that oil mix to trend over the next couple of quarters?

I think it's -- it will stay about flat.

There will be variation quarter-to-quarter as we've always seen as you noted, on the Delaware side we're in a really high oil cut area.

But on the Midland side, eastern side of the Midland Basin where we've seen really good overall results and we'll continue with activity there, those are a little bit gassier.

So I think, overall, probably for the remainder of the year, we should probably stay close to that 75% oil cut level.

That's helpful.

And then some of your peers have noted inflationary pressures in the Delaware Basin, are running a bit hotter versus the Midland Basin.

Can you just comment if that's something you all are seeing as well?

Or any kind of quantification would just be helpful.

You bet, John.

We see about the same inflationary pressure from both basins.

Most of the inflation that we've seen has been on the pressure pumping side.

And again, pressure pumping in from the sand side.

So when you go to the Delaware, where a lot of folks are still experimenting with really high sand loadings and large jobs, they're getting a disproportionate size of inflation on that they're seeing from the Delaware side.

But in general, we're seeing about the same from both basins.

And then just one true up, if you did add the ninth and 10th rigs in the back half of the year, is that something that was already contemplated in the 2017 capital guidance of $800 million to $1 billion or would that be something that will either require efficiency gains or you're free to kind of raise that budget?

John, our original budget was from 6 to 10 rigs and that had us from that $800 million to $1 billion price range.

So they were baked into the initial guidance that we've given.

So the high end of that range, okay, perfect.

And our next question comes from Dan McSpirit from BMO Capital Markets.

Can you share your view on basis differentials, asking in light of the basis swaps you've added in 2018, at less than $1 per barrel.

Dan, this is Kaes.

We're pretty happy with the basis hedges we have on, at this point.

We are also very encouraged by the announcements that have happened in the last quarter on greenfield expansion, as well as the brownfield projects that are being expanded over this summer.

So we're happy with where we are today, and I think you'll see that the midstream guys are looking to fund these greenfield projects given the growth they're seeing coming out of the basin.

So I think we're pretty happy with where our hedge positions sits and where the takeaway capacity is heading out of the basin.

And as a follow-up, just a question on portfolio management, if you will.

If you look out 9, 12 months from now, after the company has had time to, I guess, fully digest the acquisition, what basin or operation, Midland or Delaware, yields the highest return in your view?

And is there anything in the portfolio that can't compete or won't compete for capital and could be a candidate for divestiture?

Yes, I think the first part of that question is -- we addressed in one of the slides, I can't remember which slide it is.

But we actually say that what we see in the Upper Wolfcamp A, even at the higher cost because you have a higher EUR per foot, is competitive with the Lower Spraberry, in the Northern Midland Basin.

So if that premise holds true in the next 12 months, well then you should have equal allocation of capital on both sides of the basin.

And the second question was are there portions of the portfolio which don't make sense to allocate capital to initially?

And I think, talk to any company, when you look at some of the inventory that's out on the very tail end, it's going to have a hard time competing for capital.

So would we divest?

I don't know, we've got a lot to say grace over right now, so we're going to -- we're focusing on trying to execute and some of the late portfolio development assets, we'll address that sometime through the course of this year.

And our next question comes from Richard Tullis from Capital One Securities.

Travis, what was the drilling completion cost for the initial FANG-operated Delaware Basin wells?

Have you already achieved the completions cost referenced in the investor presentation at $550 per foot level?

Yes, Richard, I'm going to let Mike address the question specifically, but I will tell you that early on in the Delaware Basin, we've done some science that -- science means more expense in the first couple of wells, but I'll let Mike talk about it, specifically.

So Richard, on the completion specifically, with your $550 question, the answer is yes.

The completions have all come in at or right near our cost for the $550.

Total drill complete and what we've had to do from the equip side up to this point -- of course these wells are naturally flowing right now, so the equip piece is a little smaller than normal.

But we have, as Travis said, have done some science.

So ex science, we are right in our guidance range for the wells.

And then what percentage do you expect in, say, the second half of the year if the Delaware Basin wells will be drilled on 2 well pads?

So Richard, after the first 4 or 5 wells in each one of our big blocks, the Brigham piece as well as the Luxe piece, we'll go to pad development after that point.

And when we bring that third rig over, that will obviously make it a lot easier to drill pad wells and still meet the few obligations that we have throughout the year.

And Travis, how is the infrastructure build-out proceeding in the Delaware Basin and what do you expect infrastructure spending could be over, say, the next 1 or 2 years and just your current view on maybe infrastructure being a more meaningful asset within the FANG portfolio going forward?

Yes, Richard, I'm going to let Kaes answer that question, he's got his finger on that pulse pretty closely.

Yes, Richard, the large projects are proceeding as planned.

We didn't spend that much money in Q1, just because we closed Brigham at the end of February.

So through the rest of this year, we still have $150 million to $175 million budgeted for infrastructure, and I would say that, that spend is going to be fairly even over the last 3 quarters of the year.

And on the Brigham stuff, we did acquire gathering system on the gas side that was in place and some significant water assets that were in place.

So that's allowed us to seamlessly transition into that asset.

In the long term, we are focused on maximizing our net backs at Diamondback and that's why we're building these systems over the next 9 to 12 months.

Okay.

And then just lastly, so 1Q, obviously a very strong quarter for cost controls.

How much more opportunity do you see at FANG for driving OpEx cost even lower or at least keeping it flattish, given you're coming out of acquiring a sizable asset there.

So perhaps that presents some opportunities to keep the momentum going.

Yes, Richard, you've heard me say before that we'll never quit pushing on the LOE reduction side until we can produce these wells for free.

So I'm not ready to say we're going to go the other way -- we're going to go the other way at any time but the reality is that we've got a lot of new assets we're bringing in and it takes all of our field organization every day leaning into the brace, trying to make sure we'd produce these wells as efficiently and as cost-effectively as we can.

And like I said, we didn't make a bullet point out of it on our earnings release, but even in the process of dialing in 100,000 new acres, our field organization lowered LOE quarter-over-quarter, which I was real proud of them for being able to do that and especially against the backdrop of acquiring new assets.

(Operator Instructions) And our next question comes from John Aschenbeck from Seaport Global.

A lot of the good ones have already been addressed.

But I did have a question here on timing of tests of additional zones in Pecos County.

And I understand most of the activity this year is going to focus on the A. But if I recall, I believe you had several Bone Spring completions scheduled for this year.

So I just curious to get an update on the timing of those tests and when we should expect results.

Yes, we've got a couple of DUCs at Brigham drill that we'll be completing, that are in the Bone Springs.

And as we mentioned at acquisition time, they had some previous Bone Springs tests that had some nice results.

Right now, we don't have any specific additional Bone Springs tests scheduled on the Brigham acreage this year, but we'll just complete those DUCs and see how those results stack up with the Wolfcamp A, before making a decision on a go-forward basis.

Okay, got it.

And I guess, just you're looking for those results in the back half of the year then?

Correct.

And at this time, I'm showing no further questions.

I'd now like to turn the call back over to Travis Stice, for any 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, and this does conclude the program.

You may all disconnect.

Everyone, have a great day.