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Diamondback Energy, Inc. (NASDAQ:FANG)

Q1 2013 Earnings Call

May 8, 2013 10:00 AM ET

Executives

Adam Lawlis – IR

Travis Stice – President and CEO

Teresa Dick – SVP and CFO

Analysts

Ryan Oatman – SunTrust

Gordon Douthat – Wells Fargo

Jason Wangler – Wunderlich Securities

Jeb Bachmann – Howard Weil

John Freidman – Raymond James

Ipsit Mohanty – Canaccord

Jeffrey Connolly – Brean Capital

Matt Portillo – Tudor Pickering

Operator

Good day, ladies and gentlemen, and welcome to the Diamondback Energy First Quarter Earnings Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will be given at that time. (Operator Instructions). As a reminder, today’s program is being recorded.

I would now like to introduce your host for today’s program, Adam Lawlis, Investor Relations. Please go ahead, sir.

Adam Lawlis

Thank you. Good morning and welcome to Diamondback Energy’s first quarter conference call. Again, my name is Adam Lawlis, and I manage Investor Relations at Diamondback. Representing Diamondback today are Travis Stice, CEO; Tracy Dick, CFO; and Russell Pantermuehl, Vice President of Reservoir Engineering.

During this conference call, the participants may make certain forward-looking statements relating to the company’s financial conditions, results of operations, plans, objectives, future performances, 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 we found in the company’s filings with the SEC.

During our call today, we will reference certain non-GAAP financial measures, which we believe provide useful information for investors. We include reconciliation of those measures to GAAP in our earnings release.

I will now turn the call over to Travis Stice.

Travis Stice

Thanks, Adam. Welcome everyone and thank all of you for listening into Diamondback’s first quarter 2013 conference call. When discussing quarter-over-quarter comparisons, I’ll be referring to the pro forma numbers for 2012, which give effect to our acquisitions as if they had occurred at the beginning of 2012.

Over the past few months, Diamondback has continued to make significant progress in expanding on our horizontal drilling with 15 horizontal Wolfcamp B wells in various stages of development with what we feel are very exciting results. Our acreage lines right in heart of this emerging play in the Midland Basin. And we feel like we are leading the way in delivering horizontal well reserves to our stockholders.

We’ve achieved an average 24 hour IP rate from eight horizontal wells of 860 boes per day, of which 87% is oil from lateral links that average just slightly less than 5,000 feet with two marquee wells testing at rates exceeding 1,000 barrels a day equivalent. The average 30 day rate for the same set of wells was over 600 boes per day. We are currently running two horizontal rigs, one in Upton and one in Midland County.

Operationally we’ve been active on several fronts including ramping production and increase in efficiencies and an effort to achieve best in basin margins. Now looking at our results, we are pleased with our production for the first quarter of 2013 which averaged 48,000 boes per day. The production ramp we expected from horizontal wells was evident as we exited the quarter at 55,000 boes per day.

This is almost 1,000 barrel a day increase when compared to 2012 exceed rate of 45,000 boes a day. Now looking just at the oil compound at the production stream, which accounts for 87% of our revenue. Our first quarter exit rate for oil was 38% compared to the fourth quarter reflecting the high percentage of oil we’ve seen from these horizontal wells.

Although the production ramp we developed last year for 2013 started roughly a month later than planned to do this some production delays associated with our choice together data in a micro seismic fashion and an operational delay on our first horizontal well. Both vertical and horizontal wells are meeting or exceeding our expectations.

Although the numbers are not finalized for April yet, our production is around for the month 6,000 boes per day. And then I’m looking at the first few days of May, we’re over 6,500 boes per day. This production ramp gives us confidence in delivering on our growth profile for 2013.

Our operations team continues to improve performance to a level we believe is among the best in the Midland Basin. We had 7,500 foot lateral in Upton County and reached TD in 16.5 days and the 4,500 foot well also in Upton County that reached TD in 13.5 days.

Our first quarter well cost for short laterals was $6 million, which is 22% improvement over the fourth quarter of last year and our longer laterals of 7,500 feet averaged $7.8 million for this quarter, which is again at 10% improvement over the fourth quarter of last year.

We expect our well cost to migrate to the low end of our guidance between $7.5 million to $8.5 million for these 7,500 foot lateral wells with further upside possible as we continue to optimize our completions. We also saw improvements again this quarter on our vertical programs with spud to TD times decreased in the 18% to average nine days. Three of these wells reached TD in less than eight days.

We planned to begin testing the horizontal potential of our Andrews County lease hold during the third quarter of 2013 with wells planned both in the Wolfcamp B and in the Clearfork shale intervals.

Acreage values continue to increase as seen in the recent results of the university lands auction with offset acreage selling over $6,500 per acre, likely driven, we feel about horizontal perceptivity. This acreage pricing reflects positively for our 18,000 net acres in Andrews County.

Now, as I said earlier, we’ve got over – we’ve got 15 horizontal wells in various stages of development. Referring to our earnings release from yesterday, you can see all the details associated with each of these horizontal wells. The two best wells are from the Midland County, ST 2501H that peaked 1,054 boes per day. And the Upton County Neal 8-2H that peaked at 1,134 boes per day.

The Spanish drilled 2501H result is particularly encouraging since that’s the short lateral volume about 4,451 feet. Now we’re currently falling back our first 7,500 foot lateral well in the Midland County and it’s just starting to produce oil.

When we evaluate our performance using the early time data for these horizontal wells, we are at or above our type curve projections. We’re also encouraged by the strong results recently delivered by the Pioneer operated horizontal Wolfcamp B hut well, which is located within 18 miles of our acreage in Midland County.

We believe our activity combined with industry results has essentially de-risked our lease hold in Midland and Upton counties in the Wolfcamp B target zone. Our first quarter LOE per boe has decreased 20% to $12.61 per boe when compared to the fourth quarter of 2012. This is being driven lower as we place more water in the pipelines and less in truck carriers.

While we’re just beginning to benefit from infrastructure expenditures, we believe we’re well on our way of our goal to reduce our total LOE to between $11 and $13 by the end of this year. This effort to reduce cost will continue and expect me to report on our efforts. We also expect to further improve our oil price realizations through our connection to the Magellan

Longhorn pipeline. Although our production is currently prorated in May, we expect to move an estimated 1,422 gross barrels of oil per day into the pipeline and we anticipate monthly increases in deliveries until at full pipeline capacity in late 3Q. At that point, we expect to be delivering 8,000 gross barrels per day through the remainder of the five-year term. If this pipeline has been operational during the first quarter of 2013, we would have increased our oil price realizations by $21 a barrel.

Now while we’ve seen this spread contract recently between LLS and WTI, we feel of having 8,000 barrels a day of non-interruptible transportation out of the Permian is a big advantage for our shareholders. Not only in a physical movement of all, but also improved price realizations, if the basis differential wide again like we saw during the first quarter.

And lastly, we’ve added – we’ve continued to add liquidity to balance sheet as our borrowing base has increased 33% to $180 million.

With these comments complete, allow me to turn the call over to Tracy.

Teresa Dick

Thanks, Travis. Our net income for the quarter was $5.4 million or $0.15 per share. Net income for the period included an unrealized gain on commodity derivatives of $1.5 million. Excluding the unrealized gain and the related income tax affect, adjusted net income was $4.4 million or $0.12 per diluted share.

Revenues for the first quarter totaled $28.9 million, as compared to fourth quarter of 2012, up $27 million. Our sequential quarter-over-quarter $2 million increase is supported by higher price realization and increased production volume. The net dollar effect of the increases in both price and production was $0.9 million and $1.1 million respectively.

Our average realized price, before the effective hedges, was $67.09 per boe compared to $63.96 per boe for the prior quarter. Our average realized price, including the effective hedges, was $63.51 per boe compared to $61.43 per boe for the prior quarter. EBITDA for the quarter was $20.3 million.

Our LOE was $12.61 per boe as compared to $15.68 per boe in the fourth quarter of 2012. Our LOE per boe is in line with our LOE guidance of between $11 and $13. Our general and administrative costs came in at $5.73 per boe. We expect unit cost to decline with higher volumes and trend toward our guidance of $3 to $5 per BOE in the second quarter. Our production tax and the DD&A are both in-line with guidance.

At quarter’s end, we have $36.5 million in debt leaving a $104 million of liquidity in the form of cash on hand and additional borrowing capacity. With our borrowing base redetermination recently completed an increase to $180 million, our liquidity has increased by an additional $45 million.

Our current debt outstanding today is $44 million. Our debt-to-capitalization ratio was 7% at the end of the quarter. In the first three months of 2013, we generated $17 million of cash flow or $0.46 a share. We spent $74.1 million. This includes approximately $15 million for drilling and completion, $18.6 million to Gulfport for the final settlement of a post closing cash adjustment in connection with the acquisition of their properties, and the remainder on infrastructure, facilities and acquisitions.

I’ll now the turn the call back over to Travis for his closing remarks.

Travis Stice

Thanks Tracy. To summarize and like I said in my opening comments, we’re pleased with our performance during the first quarter of this year as we migrated the company to increase our horizontal development and we’re well on our way to delivering our volume growth projections.

We’ve ramped our production through these results, above these horizontal wells, our expenses were down. We’re executing at or near the top in our anticipated drilling results, development costs in both horizontal and vertical wells are trending down. And we’ve added liquidity with our increased borrowing base. We feel like we have the right assets and the right people to deliver on very exciting 2013.

Before I open the call to questions, please note that we filed an S-1 Registration Statement with the SEC on April 11th in conjunction with the proposed follow-on equity offering to raise additional equity to accelerate horizontal activity.

We’re still on the filing process with the SEC and maybe precluded from answering some of your questions. On behalf of the board and employees of Diamondback Energy, I’d like to thank you for your participation today.

This concludes our prepared comments. Operator, please open the call to questions.

Question-and-Answer Session

Operator

Certainly. (Operator Instructions). Our first question comes from the line of Ryan Oatman from SunTrust. Your question please.

Ryan Oatman – SunTrust

Hi, good morning, Travis.

Travis Stice

Hi, good morning, Ryan.

Ryan Oatman – SunTrust

You mentioned, you feel that Midland and Upton County acreage is substantially de-risk. Can you just remind us how much acreage you have in those two counties?

Travis Stice

Yeah, Ryan, good question. In Midland, we’ve got about 10,000 acres and in Upton County, we also have about 10,000 acres, and those are net acres.

Ryan Oatman – SunTrust

Okay, great. And then shifting to Andrews County, what makes the Clearfork, the attractive target there versus say that the Wolfcamp B.

Travis Stice

Well, if you noticed when I said Andrews County, we’re testing both. We’re testing Wolfcamp B sort of on the eastern edge of Andrews County where we think the shale thickness and offset activity has really given us some excitement to test that zone and as we move a little further west in Andrews County where we’ve got a large acreage block, the Clearfork Shale looks really exciting.

We’ve done a lot of signs on the Clearfork there including a vertical well test in the Clearfork Shale alone and which tested at about 50 barrels a day and we’ve also done some sidewall core analysis and some advanced to shale logging all of which indicate that this is a really perspective shale zone for us.

And we were also watching offset operator activity as well as they test the Clearfork Shale. And as you move kind of off the shale’s edge into where our acreage is that Clearfork get’s deeper and thicker which we think both are accretive to our acreage position.

Ryan Oatman – SunTrust

Great. Thank you for that color there. And then, Travis, what you can tell us on this Kintner well, which is currently flowing back. Did you have any issues there or do you feel like you had an effective stimulation stating zone et cetera, et cetera?

Travis Stice

Yes. That well was effectively stimulated as a standard. It was our standard completion technique with about roughly 300,000 pounds of sand per stage. It’s a sort of a long lateral, you see the lateral length in our earnings release and it was drilled and completed without incident and we’ve had it on now for about a week and a half, it’s about 15% load recovery and its increasing oil every day. I think last night, it made about 520 barrels of oil and it’s still flowing at Casings.

Ryan Oatman – SunTrust

Okay. Great. That 520, how does that compare to, you say what you saw earlier in the Neal A or Neal B wells.

Travis Stice

It’s right in well on Ryan. It’s just attracting almost exactly.

Ryan Oatman – SunTrust

Okay. Very good. I appreciate all that. I’ll hop back in the queue.

Travis Stice

Great. Thanks, Ryan.

Ryan Oatman – SunTrust

Thanks.

Operator

Thank you. Our next question comes from the line of Gordon Douthat from Wells Fargo. Your question, please.

Gordon Douthat – Wells Fargo

Morning, guys.

Teresa Dick

Hey, Gordon.

Gordon Douthat – Wells Fargo

Travis, you mentioned you’re having success getting well cost down and you’re tracking towards the low end of your targets or you hope to be there by year end. Can you talk about some of the things that you’re seeing on both the drilling and completion side that’s allowing you to realize these reductions?

Travis Stice

Yes. Specifically on the drilling side, what the drilling organization is doing is with the extreme focus on just almost every connection on the drill pipe, they’ve improved deficiency. So, I can tell you how many minutes it takes to make a connection. And so what that really translates to is behavior that actually cuts days out of the total execution. So when I talk about 16.5 day well, that’s out there to 7,500 feet. It’s through a lot of hard work and diligence on the drilling side of the organization.

And then on the completion side, what these guys are doing is continue to optimize the completion methodology without sacrificing EUR or initial production range.

Specifically what we’re doing is, is we’ve tested with kind of cutting out stages, but still pumping the same amount of propane and fluid and what that really does, it cuts time out of the completion and when you cut time out of the completion, you also cut dollars. So when you combine all that together with the extreme focus on cost that we have on our execution, you start seeing the results that we’re seeing right now with quarter-over-quarter improvements.

Gordon Douthat – Wells Fargo

Okay. That’s good color. And can you get into maybe more specific about kind of your standard completion. I know you mentioned 300 pounds of propane per stage, but as you complete these wells both on the long and the short laterals. How do you look to space the frac stages and what type of completion recipe are you fracking these wells with?

Travis Stice

Sure. Our currently recipes like I said about 300,000 pounds per stage in the kind of the inter stage distances about 250 feet and we’re using slick water transport fluid and 40/70 sand, white sand.

Gordon Douthat – Wells Fargo

Okay. And then just last question from me. You mentioned the B bench looked to be de-risk, when do you think you will outside the you’ll – outside of Andrews, but actually I should say in Midland and Upton, when do you think you will test other bench of the A or maybe the other benches?

Travis Stice

Well, we ask ourselves that question almost every day and what’s hard for us to try to justify is when you’re bringing on wells, we’re making a 1,000 barrels a day to go test other benches. And really what I think we are doing right now is there is a lot of industry activity that’s been announced out there where other benchers are being tested.

And so I’m going to continue to try to keep my drill bid in the Wolfcamp B and I follow very closely what the industry reports in these other benches and we’ll be able to respond very quickly if somebody has comes up with the zone, that’s better than a Wolfcamp B, but right now, I’m going to try to keep my drill bid in the Wolfcamp B there and Midland County.

Gordon Douthat – Wells Fargo

All right, it makes sense. Thank you.

Operator

Thank you. Our next question comes from the line of Jason Wangler from Wunderlich Securities. Your question please.

Jason Wangler – Wunderlich Securities

Morning. Just one quick one on the CapEx side. The $18.6 million to Gulfport, assuming obviously that’s the final settlement there. Is there any other payments like that that are expected or I assume that’s it. And then, is that baked into the current CapEx guidance, just want to make sure that assumptions are right?

Travis Stice

Sure. No further payments and yes, it’s baked into our CapEx guidance.

Jason Wangler – Wunderlich Securities

Perfect. That’s all I had. Thank you.

Operator

Thank you. Our next question comes from the line of Jeb Bachmann from Howard Weil. Your question, please.

Jeb Bachmann – Howard Weil

Going back to – Travis going back to the – your completion methods. Can you tell us or talk us about the differences that you’re seeing between the submersible pumps and the gas lifts on these horizontal Wolfcamp wells?

Travis Stice

Sure. We originally started with the gas lift. We did that one to sort of minimize operational risk. And two, we’re looking at to save an extra rig up on one of these top wells typically runs around $25,000 to $30,000 and we avoided that by going to gas lift, because we’re drilling that with stick pipe.

That’s our standard method right now and the reason we’re drilling that with stick pipe is because as we test these longer 10,000 foot laterals, we know we can’t use coil to clean up that whole lateral.

So, we’re building our game up to drill out these well with the stick pipe, which is what we’re doing. So, what we do when we already have a rig on there, since we’re using stick pipe, we’ll just run in there with tube and with gas lift valves and lift the well – start producing the well up to tubing. If I just lift the well flow, I have to wait for it to flow and then deplete on flow back and then rig up again where that incremental cost comes in and put us a pump on there.

Now, having said all of that, what we really did was, we set up two test wells where we could kind of measure them side by side. The 25-1H, which is on sub-pump and the 25-2H which is on the gas lift and what we’re looking at is, we’re looking at the total tube production into the first 90-day period and kind of get a gauge on whether or not the sub-pumps are kind of differential better than the gas lift.

But I can tell you what we’re seeing right now, these early rates just appears at the sub-pumps are capable of moving more fluid early on, and I said early on probably in the first 30 days then the gas lift wells are. So, our operations program is migrating towards more sub-pumps.

Jeb Bachmann – Howard Weil

Great. Thanks. And then one other clarification for me, Travis, on – you mentioned the 38% exit rate for oil increase over 1Q 2013 over 4Q 2012. Was that a 4Q 2012 exit rate or the 4Q 2012 average?

Travis Stice

That was 4Q 2012 exit rate.

Jeb Bachmann – Howard Weil

Okay. Great. Thanks guys.

Operator

Thank you. Our next question comes from the line of John Freidman from Raymond James. Your question please.

John Freidman – Raymond James

Good morning, guys. On the – your vertical – the plans for the 35 to 40 gross vertical wells that’s currently guided to, what spud to TD time does that assume?

Travis Stice

I think for your planning purposes kind of two wells per month on these vertical wells. We’re averaging, like I said in the first quarter, spud to TD of about nine days, it gives us a day or so to run case in a couple of days to move the rig. So, just from a planning purpose I think you can go about two vertical wells per month.

John Freidman – Raymond James

Okay. Yeah. I mean that’s currently what I was getting at. It looks like you’re doing a little bit better on the days and what you originally budgeted for and just was curious if we might see maybe next quarter that that vertical well count guidance maybe go up a little bit just because of the run rate.

Travis Stice

Yeah. That’s a fair question. But right now for your planning purposes, I just stay with two per month.

John Freidman – Raymond James

Okay. And then back on the completion side on these horizontals, just to make sure I’m understanding this correctly. As you all have been testing the longer laterals so far at least you’ve stayed with a consistent sort of 300,000 pounds of sand per stage. You haven’t sort of adjusted to see if as you go longer maybe to increase that.

Travis Stice

Well, so far, only – when we said we go longer, we’ve gone from a one-mile lateral or the 5,000 foot laterals to the 7,500 foot. And no, we’ve not really changed the recipe there. The next well we’ve got on our drilling schedule is a 10,000 foot are down in Upton County. And we’re working to design that right now. So, there maybe a – there may be a slight change in the 10,000 foot design.

John Freidman – Raymond James

Okay. Great. Thanks guys.

Operator

Thank you. Our next question comes from the line of Ipsit Mohanty from Canaccord. Your question please.

Ipsit Mohanty – Canaccord

Good morning, guys.

Travis Stice

Hi, good morning Ipsit.

Ipsit Mohanty – Canaccord

Let me start off with the Texas, with the Magellan Longhorn pipeline. If you could provide some more color on the timeline, like – is this current quarter be the first one to realized pricing or are we going to see a lag?

Travis Stice

Yes. The pipeline started filling in April. And the producers that have committed the firm transportation to the line were notified late April and we nominated barrels starting in May. So, in May, it’ll be the first time we realize the uptick in LLS versus WTI.

And what Magellan is telling us is that there is a kind of milestone production points that they’re going to reach. The first is 75,000 barrels a day, which they hope to reach end of this month, early next month and then they’ll go to 135,000 barrels, which is kind of in the July timeframe. And then they anticipate be in at 225,000 barrels kind of in late October.

And what they’ll do at each one of those milestones is they’ll come back to the producers and they’ll increase the allotment up until and for down back up until we’re at our 8,000 barrels a day of firm transportation, when they’re at 225,000 barrels a day of full capacity.

Ipsit Mohanty – Canaccord

But Travis on pricing, is that a spot pricing that you fixed with them or is it a fixed pricing – if you could talk about that a little bit.

Travis Stice

Yeah. It’s simply, it’s a deduct. So, we receive LLS pricing less about $7 a barrel.

Ipsit Mohanty – Canaccord

Got you. Great. And then a follow-up on the horizontal Wolfcamp wells in Midland and Upton. If you could talk – do you plan to drill any laterals longer than the 7,500 and just approximately how many of them to kind of test out the ultra long laterals?

Travis Stice

Yeah. What we’ve seen, Ipsit, is that there is a cost efficiency as you increase the lateral lengths. And we’ve seen that when we went from 5,000 foot laterals to 7,500 foot laterals. And as I just mentioned, we’re getting ready to test our first 10,000 foot lateral in Upton County.

And we anticipate seeing that same cost efficiency as we add another 2,500 feet of lateral length. Now, granted every time you add lateral lengths, you increase risk a little bit. So that’s kind of the offset there. But in a general sense, we let our lateral lengths be dictated by our lease geometry.

So, our sort of preferred lateral length is in that 7,500 to 8,000 foot range, because most of our – most of our leaseholds are kind of three miles stand-up sections and we can develop three miles with two 7,500 foot laterals where we can now is rather than drill too short laterals. We’re going to try to drill just one long 10,000 foot lateral. And we think there is a material cost improvement on our cost efficiency improvement there.

But we’ve got to get one on the board first. And so, when I look ahead for this year, I think we’ve got, Russell, we’ve got five – roughly five 10,000 foot laterals on the Board for the rest of this year. But the first one in Upton County is the one that we’re really – we’re really – we’re going to test.

Ipsit Mohanty – Canaccord

And Travis, you might have talked about this, but I assume your additional rig in the Wolfcamp will be in the Midland County?

Travis Stice

That’s a fair assumption.

Ipsit Mohanty – Canaccord

All right. And given what you’ve just seen with putting submersible pumps on these wells. Are you going to do that across the board on all wells, is it a case-by-case basis?

Travis Stice

Right now, my operations organization is saying, they’re locking what they see and that’s probably going to be in all future wells we’ll go with the sub pump.

Ipsit Mohanty – Canaccord

Wonderful. Thank you, Travis.

Operator

Thank you. Our next question comes from the line of Jeffrey Connolly from Brean Capital. Your question please.

Jeffrey Connolly – Brean Capital

Hey. Good morning, guys. One quick follow-up on CapEx. The third horizontal rig that’s backed into the guidance here right?

Travis Stice

That’s correct.

Jeffrey Connolly – Brean Capital

And then around the announcement of the S1, you guys mentioned potentially raising CapEx to accelerate the horizontal drilling. Can you give us some idea what an accelerated horizontal program would look like?

Travis Stice

That’s one of those things that I mentioned earlier. In this quite period with the SEC, I can’t comment on any of that until we actually get effective and then get on the road with our story.

Jeffrey Connolly – Brean Capital

Okay. That’s fine. Well, thank you very much. That’s it for me.

Travis Stice

You bet. Thanks.

Operator

Thank you. Our final question comes from the line of Matt Portillo from Tudor Pickering. Your question please.

Matt Portillo – Tudor Pickering

Good morning, guys.

Travis Stice

Hi. Good morning, Matt.

Matt Portillo – Tudor Pickering

Just a few quick questions from me. One of the interesting comments you just made was potentially drilling a longer 10,000 foot lateral versus two shorter 4,500 foot laterals. I was curious if you guys have a rough kind of ASC estimate of what you’ll be looking for on the 10,000 foot lateral. Just trying to a sense of kind of the potential improvement on capital efficiency?

Travis Stice

We’re putting the final touches on the ASC right now. But it’s kind of like in that $9 million range. And as I reported, our current first quarter performance on the shorter laterals are $6 million. So, if you kind of just look at those two endpoints, our $9 million 10,000 footer versus a $12 million for two 5,000 foot laterals. So, I mean, that’s where you start seeing the economies of scale there, which makes the risk profile worth probably taken.

Matt Portillo – Tudor Pickering

Perfect. And then just on the Wolfberry. I was wondering if you can just give us an update on kind of where your AFE costs are coming in there and do you guys continue to see some cost efficiency if you can wring out on kind of the Wolfberry wells.

Teresa Dick

Yeah. We’re running about $2 million to $2.1 million running there on actuals. And we’re picking up pennies right now in the vertical program. So, I won’t say that we’ll never be happy with cost performance. In a general sense, we always try to reduce cost, but we’re really pretty close to the edge right now.

Matt Portillo – Tudor Pickering

Great. And then I know you guys are focusing obviously on the Wolfcamp horizontals and that’s been covered in detail here. I was just curious on the Wolfberry as we think about kind of the 20-acre down spacing opportunity.

I know that kind of at the time in the IPO that was something you may have been looking at late this year or early in 2014. I was wondering if that was still kind of in the plans and if you’ve seen any other offset operators testing some of the additional 20-acre down spacing that would give you confidence in limited interference on the wells.

Teresa Dick

Yeah. In our plants right now for this year, we don’t anticipate doing any 20-acre infill wells. In fact most of the vertical program we’ll have in front of us is just simply to hold acreage. But we are actively involved in conversations with some private operators around town that are active in down spacing. And so, we’re in conversations with those guys.

And in a general sense, the jury is still out on there, but I think as we think about it, somewhere around an 80% reduction from the 40-acre well is reasonable. So, you’ll just have to do the economics on costs and recoveries to see if that’s an economic in nature, but it’s not a decision that we’re faced with right now. It’s still future economic inventory for our shareholders going forward. Right now, we’re drilling the highest rate return investments we can and right now those are the Wolfcamp B horizontal wells.

Matt Portillo – Tudor Pickering

Perfect. And then just my last question, we’ve seen some softness in the A and D market as of late with some sale private opportunities. And I assume that may provide you guys some opportunity to take up additional leasehold acreage, although we are clearly operating, it is a still pretty hot market.

Just wondered if you could give us any commentary on kind of how you see the A and D market at the moment, and really the opportunity that you see for picking up incremental acreage within Midland or maybe some of the other basins within the Permian.

Travis Stice

Well you’re right in your comment about it. The acreage have been pretty tightly held, but I think it’s fair for our shareholders to expect Diamondback is involved in our every negotiation, our every conversation about acquisitions here in the Midland Basin.

In terms of picking up acreage, I think I announced last quarter that we picked up about 2,500 acres, and I think we have added about 150 acres to 200 acres just this quarter as well to. So it’s – we are picking up parcels in bolt-on acreage, and we are active in the game of in the A and D arena as well.

Matt Portillo – Tudor Pickering

Thank you very much.

Operator

Thank you, this does conclude the question and answer session of today’s program. I’d like to hand the program back to Travis Stice for any concluding remarks.

Travis Stice

Great, I know this is a busy time and a busy day for a lot of the equity analysts out there. So I appreciate the attention this morning that Diamondback got. And I also appreciate everybody else those on the call expressing your interest in Diamondback Energy.

If you got any questions, we’re in the office this all week. We got Adam Wallace now and his contact information is on our website. So if you got any further questions, I encourage you to reach out there. But just really thanks guys for the interest in Diamondback Energy. And we look forward to having some more conversations with you guys in the future.

Operator

Thank you ladies and gentlemen for your participation in today’s conference. This does conclude the program. You may now disconnect. Good day.

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