Diamondback Energy Inc (FANG) — Q1 2015 Earnings Call Transcript

Thank you, Sarah. Good morning, and welcome to Diamondback Energy and Viper Energy Partners Joint First Quarter 2015 Conference Call. During our call today, we will reference an updated investor presentation which can be found on Diamondback's website. Representing Diamondback today are Travis Stice, CEO; and Tracy Dick, CFO; as well as other members of our executive team. 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. I will now turn the call over to Travis Stice.

Thank you, Adam. Welcome, everyone, and thank you all for listening to Diamondback's and Viper Energy Partners First Quarter 2015 Conference Call. It was another great quarter for Diamondback as we had production that exceeded expectations and we raised production guidance as a result of well performance, increasing completion activity, and accretive acquisitions. We plan to add a second completion crew in June to go to work down the inventory of drilled but completed wells because cooperation with service providers has lowered our well costs by 20% to 30% since the service cost peak in the third quarter of 2014. Additionally, we plan to add 2 horizontal rigs later this year. As a result of service cost concessions and efficiency gains, we are keeping CapEx unchanged despite increasing activity. The accretive acquisitions are located in the core of the northern Midland Basin primarily in northwest Howard County where economics and productivity rival those of Spanish Trail in the Midland County. I will talk more about the details of those acquisitions later in the call. I will now turn to our updated slide deck that can be found on our website. The Lower Spraberry shale continues to exceed our expectations. As shown in Slides 6 and 7, Lower Spraberry completions in Midland County continue to exceed our million-barrel type curve while those in Martin and Andrews County are tracking well above the 800,000-barrel type curve. As a reminder, about 2/3 of our completions this year will target the Lower Spraberry formation. Now turning to costs. AFEs are trending towards the low end of the $6.2 million to $6.7 million guided well cost range per 7,500-foot lateral. Several of our upcoming 7,500-foot lateral wells are on track to cost less than $6 million. We've also seen approximately 15% of cost concessions associated with LOE. Specific cost reductions are broken out on Slide 10. Since we're still completing wells drilled before we received cost concessions, we continue to expect to be within this guided well cost range of $6.2 million to $6.7 million for the year. We're projecting that at $60 a barrel for WTI, our cost savings and efficiency gains will allow us to generate project rates of returns comparable to those generated when WTI was at $75 a barrel. With the improvement in service costs and oil prices, we will resume our former pace of completion activity by adding a second dedicated frac crew next month to work down our backlog of drilled but uncompleted wells. We plan to increase our rig count from 3 to 5 rigs in the third and fourth quarter of this year and could potentially add another 2 or 3 rigs in 2016 to continue this growth trajectory. With the inclusion of our announced acquisitions, we now have an acreage footprint that can accommodate up to 10 horizontal rigs. We are reiterating our guidance for total capital spend of $400 million to $450 million despite expecting to drill and complete more wells. Including the effect of the acquisitions, increased completion activity, and strong productivity, we are also increasing our production guidance by 11% at the midpoint to a range of 29,000 to 31,000 BOEs per day. More than half of the increase is due to increased completion activity and productivity with the remainder of the increase coming from pending acquisitions that we expect to close by the end of June. Diamondback increased production by 19% quarter-over-quarter to 30,600 BOEs per day, which exceeded expectations. The increase in production is primarily associated with the strong productivity of wells that came online during the quarter. Diamondback's track record for peer-leading efficiency and execution continues, resulting in cheaper wells and higher rates of return. Slide 12 shows that during the first quarter, we drilled 2 well pads with an average lateral length of 10,000 feet per well in 31 days from the spud of the first well to TD of the second. In Martin County, we drilled a well with an approximate lateral length of 8,200 feet in 12 days, our best drilling performance to date on this acreage block. With these service cost reductions and continued efficiency improvements, rates of return are now more than 85% per Spanish Trail Lower Spraberry well and nearly 200% where Viper owns the underlying minerals, as shown on Slide 13. Last night, Diamondback announced that we have acquired or entered into definitive agreements to acquire approximately 12,000 net acres from private parties for $438 million, including 2,500 barrels a day of production on a 3-stream basis from 117 gross vertical wells and 3 gross horizontal wells. These transactions demonstrate both of our acquisition strategies: the bolt-on acquisitions in and around our core areas and adding new development areas. These assets, located primarily in northwest Howard County, provide us with approximately 232 net horizontal locations primarily in the Lower Spraberry, Wolfcamp A, and Wolfcamp B formations on blocky acreage that is ideal for drilling longer laterals. Recent horizontal wells in the area of northwest Howard County confirm our geochemical data that indicates our 3 primary targets are well into the mature oil window. We expect EURs for these locations to range from 600,000 to 900,000 BOEs, which provides a low acquisition cost of approximately $2 a barrel. We expect roughly 40% of these locations to be drilled at 10,000-foot laterals, with the remaining locations being predominantly 7,500-foot laterals. Longer laterals support low refining costs, higher capital efficiency, and stronger rates of returns. Additional upside may exist in the Middle Spraberry. There are over half a dozen Middle Spraberry wells drilled in and around the Spanish Trail acreage in Midland County with encouraging results, and the target looks very similar in Howard County. With over 25 wells completed in the immediate vicinity of the northwest Howard County, we consider this to be a proven area and the most de-risked acquisition in Diamondback's history. As shown on Slide 16, offset EURs range from 600,000 to 900,000 BOEs, which make the asset in the top quartile of our inventory with economics that are competitive with Spanish Trail. Slide 17 includes a cross-section showing that the horizontal target shale formations in northwest Howard County are comparable to Spanish Trail in Midland County. Included in this acquisition is a 1.5% overriding royalty interest that we've offered to Viper Energy Partners for $34 million, which would leave Diamondback Energy with approximately 75% NRI. We expect to begin developing this acreage in 2016 or sooner depending on the timing of infrastructure needed to support a 2-rig program. You have heard me talk about all Tier 1, which is a type of acreage that generates the highest cash margins and rates of returns for our investors. As I have said many times before, Diamondback is committed to delivering best-in-class operations and the highest cash margins in the Permian Basin. With these comments now complete, I will turn the call over to Tracy.

Thank you, Travis. Diamondback's net income for the quarter was $5.8 million or $0.10 per diluted share after adjusting earnings for our non-cash market-to-market derivative losses of $25 million. Netting out the related income tax effect, our adjusted net income was $22 million or $0.38 per diluted share. Diamondback's adjusted EBITDA for the quarter was $110 million, roughly flat quarter-over-quarter due to increased production despite lower commodity prices. Our average realized price per BOE for the first quarter was $36.78 and due to the positive impact of our hedge position, our average realized price per BOE, including the effect of hedges, was $52.57. We are currently looking at opportunities to layer on hedges for 2016. We laid out the detail of our current hedge position in last night's earnings release and on Slide 22 of the presentation. Turning to cost. Our LOE was $8.14 per BOE for the quarter, a 17% reduction from the fourth quarter of 2014. We continue to see cost concessions and to implement best practices on the acreage acquired in 2014. Learning from our experience of last year when we acquired nearly 300 gross vertical wells, we're making a minor adjustment to our LOE guidance as a result of acquiring 117 gross vertical wells in the announced acquisition. We think this new guidance of $7 to $8 per BOE is manageable given that we decreased LOE 17% quarter-over-quarter due to reductions in well servicing units, route about water, trucking, chemicals, and other components. Our cash G&A cost came in at $1.20 per BOE while noncash G&A was $1.79 per BOE for the quarter, both within full-year guidance ranges. We believe that our total G&A of $2.99 per BOE is among the lowest in the Permian Basin on a per-BOE basis. In the first quarter of 2015, Diamondback generated $99 million of operating cash flow and $109 million of discretionary cash flow for $1.69 and $1.86 per diluted share, respectively. During the first quarter of 2015, we spent approximately $149 million for drilling, completion, and infrastructure. The majority of first quarter 2015 capital spend was associated with 2014 projects. We continue to expect our total capital spend to be in the range of $400 million to $450 million for 2015, unchanged from previous guidance due to cost savings and efficiency improvements. We anticipate our CapEx will trend down due to reduced rig count in the first half of 2015 and lower well costs. As of March 31, 2015, we had $162 million drawn on our secured revolving credit facility. Diamondback's agent lender under its revolving credit facility recently recommended a borrowing base of $725 million. However, the company intends to continue to limit the lender's aggregate commitment to $500 million. We believe our current volume availability provides us with plenty of liquidity. We estimate our 2015 year-end debt-to-EBITDA will be less than 2x. At current commodity prices and with the current drilling program, we expect that we will turn cash flow positive in the second half of this year. I'll now turn briefly to Viper Energy Partners, which recently announced a cash distribution of $0.19 per unit for the first quarter. This exceeded expectations. During the quarter, cash available for distributions was $15 million and production increased 16% quarter-over-quarter to 4,844 BOE per day. Viper has no debt and an undrawn revolver of $110 million as of March 31, 2015. Viper's agent lender under its revolving credit facility has recently recommended a borrowing base increase of 60% to $175 million subject to the approval of the other lenders. Turning to Viper's guidance, we expect 2015 volumes in the range of 4,600 to 5,000 BOE per day, up 10% from prior guidance. As a reminder, Viper does not incur lease operating expenses or capital expenditures. With that, I'll now turn the call back over to Travis for his closing remarks.

Thank you, Tracy. To summarize, this quarter, we've increased production guidance, resumed our completion activity, and announced several Tier 1 acreage acquisitions. Service cost concessions and continued operational efficiencies have improved rates of returns equivalent to when WTI was $75 a barrel. As a result, we plan to pick up additional rigs later this year. Our intense focus on execution and generating differential cash margins has never wavered even as we go through this down cycle in commodity prices. I'm proud of all that our employees have accomplished so far this year and look forward to updating you on our progress. On behalf of the board and employees of Diamondback and Viper, I would like to thank you for your participation today. Operator, please open the call to questions.

I think the first thing I'd ask is on your decision here to go back to work. And you mentioned in the release that you could see the rig count going from 3 all the way up to 8 rigs at some point in 2016. And I was just hoping Travis, you could detail kind of what the criteria is to get there? And how fast you might be able to ramp to 8 rigs.

Sure, Mike. It's really a function of a couple of things. We've got to maintain discipline on costs from the service community and commodity prices continue to need to improve. But in a general sense, as I outlined in our call, we believe we're generating rates of return when commodity prices were equivalent to $75 for WTI. So right now, we'll look at that. We've got a rig coming in the third quarter, one in the fourth quarter. And certainly, as commodity prices continue to improve, we'll be able to add additional rigs in late fourth quarter, early first quarter, primarily to go to work in our newly acquired acreage in Howard County.

As a follow-up on that, regarding the balance sheet, you mentioned in the release that you might finance the acquisition and the upcoming ramp in activity through a combination of debt and equity. When we analyzed your figures last night, we found that even after covering this deal and increasing to 8 rigs throughout next year, the debt-to-EBITDA ratio remains below 2.5 times. I’m curious about how you view an appropriate leverage target and the potential need for equity in the future.

Yes, our stance on leverage really hasn't changed since before we took the company public. We always state that we like to keep a leverage ratio below 2. And I think that's logical to assume going forward as well. What's really unique about Diamondback is the different forms of financing that we have available to us. We have the opportunity to issue equity like we've done historically for acquisitions. We also have the high-yield market that's open to us. We have unused capacity on our revolver. And we also have an ownership in Viper Energy Partners. So we really have multiple ways to fund this acquisition going forward.

Travis, you mentioned the infrastructure as kind of something that you need to get on the acquisition before you start to go to work there. Can you talk about what specifically you're looking for? And then what kind of time frame you're looking at to get that put in place? And is that something that Diamondback's going to do themselves? Or is that a third-party deal?

Sure. David, well, we set aside roughly $20 million in the acquisition to put the necessary infrastructure in place to support a 2-rig horizontal program. And what that really entails is primarily the accumulation of stimulation fluid. So it's stim fluid accumulation ponds, pipes, and facilities able to accommodate high volumes. This property was developed with vertical wells, and while we're pleased with the condition of the facilities associated with the vertical well development, most of those are going to need to be upgraded to accommodate significantly higher fluid handling capacity. So as soon as we close this deal, we'll go out at Diamondback, not a third party, and will begin that infrastructure. One thing I'm pleased with and we outlined in the acquisition is that we also acquired a saltwater disposal system for about $5 million. So we’ve got quite a bit. But we can't start work until we close the acquisition, which is in the middle of June. That being said, we've got our plans firmly underway, at least on paper, to make a rapid transition to horizontally develop this acreage.

Got it. And then looking at your Slide 17, I mean, it looks like the Wolfcamp B on the acquisition is actually considerably thicker than it is at Spanish Trail. Do you actually expect to be a more attractive target at the acquisition? How should we think about that going forward?

Really, when we look at these 3 primary zones here, if you look at Slide 16 and you look at the offset results, we put quite a few of them here nearest wells to this acreage block. The Lower Spraberry and the Wolfcamp A are the 2 best performing zones. The Wolfcamp B is not quite as good as those other 2, but if you look at the location of the Wolfcamp B wells, they're east of the acreage block. And the Wolfcamp B does thicken as you go to the west. So we think we've got a good chance of the Wolfcamp B being better on this acreage than it is on the wells to the east. So overall, we think we've got 3 really nice targets here.

Great. And one last question if I may. As you accelerate and consider the cyclical cost reductions you've experienced so far, how do you plan to secure those reductions? Is there a risk that service companies may come back and try to reclaim some of that reduction? How do you manage the cost aspect to ensure it remains at a level that you're comfortable with as you move forward?

Well, we'll always try to hold the line on costs. Service companies are not willing to lock-in long-term contracts at what appears to be close to the bottom of the cost cycle. So it's, again, working very collaboratively with business partners because if costs continue to go up faster than commodity prices go up, Diamondback, using our same mantra of capital discipline, will tap the brakes again. So I'd like to say yes, we've locked-in these low-cost forever. But the reality is, you just can't do that right now. But again, the natural governor is increased activity versus laying rigs down, and that's certainly what drove the behaviors that got us to going back to work right now. And we still have that lever going forward as well.

Many of your peers have noted that the asset sales in the past six months have mostly involved lower-quality or more peripheral assets. Could you comment on why you believe these assets are of high quality despite the attractive acquisition price? Also, what internal rate of returns do you anticipate on that 600,000 to 900,000 MBOE type curve at $60? Additionally, are you witnessing a shift in the M&A pipeline towards higher quality assets?

Yes, John, several good questions there. I'll try to take them in the order you asked them. As I outlined in my prepared remarks, this acquisition in northwest Howard County marks the most de-risked acquisition in Diamondback's history. And I don't make that statement casually. We've got over 60 wells where we had open-hole logs where we were able to do our geochemical and petrophysical work supported by hole-core analysis that really highlighted the oil in place and the significance of these shale horizons. And also, while I think we've only put about 1 dozen or maybe 13 wells that have public data available in our slide deck, we really had over 25 slides in and around this area that had IP-30s and established production that allowed us to go in and put reserve forecasts on those wells. And so we've never had that many data points, both from a geoscience perspective and/or from a well performance perspective, that gave us confidence in this research block. And I know there's a lot of question on what other quality deals are out in the M&A market, and my history has been that we don't really talk about acquisitions that are underway. I can tell you, though, that my shareholders should expect that Diamondback is actively involved in the M&A arena. And we intend to continue to be so in the future.

And if I could just...

John, I apologize. You had another question regarding the rates of return for the 600,000 and 900,000 type wells. They will fall within the 40% to 70% range at current prices and service costs. I previously mentioned that these wells are in the top quartile of Diamondback's Energy's portfolio, and this is substantiated by the rates of return we see.

That's very helpful. And I was just hoping to just get one clarification on your earlier comment. Would the addition of rigs 6 to 8 then be contingent on further improvement in commodity price? Or are you just saying that we need to sort of stay the course with this?

Yes, it's more of the latter.

One, congrats on a great acquisition. And obviously another stellar quarter, weather clearly didn't impact you guys, as others commented on. One of the things that I'm curious about is you ramped the rig count up, and in the past, you've talked about this. And as you continue to acquire, do you feel like you have the appropriate staff in place to run an 8-rig or even a larger rig program? If you could just refresh us in terms of what kind of capacity you think your staff has at this juncture.

Yes. As an executive team, we have always aimed to develop a capacity that can support 10 horizontal rigs. When I mentioned that we now have an acreage footprint suitable for a 10-rig program, I feel we are close to having that capacity in place. We might need to add one or two more key contributors to fully support this. Our organization is designed around this 10-rig cadence. It's worth noting that while we're aiming for a 10-rig program, the speed at which we drill these wells makes it feel more like a 15- or 20-rig program. For instance, we were able to drill two 10,000-foot laterals in about a month. We are closely monitoring our organization and continue to structure it around that 10-rig cadence.

I appreciate that color. And then kind of following up on that, obviously, with the speed at which you're drilling, the inventory of wells that are producing right now, have you looked at building up? Or do you already have in place a kind of field or well control team to ensure uptime of the existing production? Obviously, as the footprint gets wider, that becomes harder to control. And just curious how you're thinking about that.

Yes. We have a production well improvement program that analyzes the performance of all our wells on a weekly and monthly basis. This program also conducts detailed assessments of any wells that have experienced issues to proactively identify failures. It's crucial to identify failures and implement effective pumping practices to reduce them. Most of the vertical wells we've acquired in the past year have a failure rate of over 1.5. For the 300 wells acquired last year, our first quarter report shows we've managed to reduce the failure rate from 1.5 to approximately 0.7. This significant reduction positively impacts our well maintenance costs. We are nearing 1,000 total wellbores, which presents a substantial challenge for our field organization to optimize. Additionally, our operations span across Upton County, Howard County, and Martin County, covering about nine counties, which can complicate management and efficiency. However, our Vice President of Operations, Jeff White, and his team are fully committed to maintaining top-notch operations from our field organization’s perspective.

One last one. Just relative to the ability to ramp up but also the ability to ramp down as you highlighted. The rigs that you'd be picking up, the completion crew that you're picking up, what kind of terms are you looking at on those? Are we talking well to well? Are we talking more contractual over several months to a year? Any kind of color on that would be helpful.

Yes, the rigs we have coming online are all under different contract periods. For rigs 6, 7, and 8, we'll be acquiring them on a well-to-well basis. One of the slides references the rig cost, and you can see that our rig cost has only decreased by 3%, which is due to most of these being under pre-existing contracts. As we add more rigs, a significant source of cost savings will be the day rate for the drilling rigs. We have committed to our completion crew that we have over a dozen wells to work from in our inventory. As long as commodity prices remain stable, we will continue our operations, but they are not under any long-term contract.

As you look to ramp your rig activity, it looks as if there's a potential for 2 to go in Howard County. Just wondering beyond that, how you look to spread your rigs across your acreage.

We plan to keep as many rigs as possible in Spanish Trail, aiming for a maximum of 2 to 3 rigs operated there. This includes the acquisition from the fourth quarter of last year in the Gridiron area and some adjacent acreage. In addition, we will likely maintain 2 rigs in the North, shifting between Northeast Andrews County and Northwest Howard County, where we can drill profitable wells in the Lower Spraberry. We'll also deploy one rig in the Glasscock County area, which is a new acquisition from last year, and maintain 2 rigs in Howard County. Moreover, we expect to have one more rig in Southwest Martin County. Overall, this strategy should allow us to operate with 8 to 10 rigs, depending on commodity prices and service costs.

Okay, that's helpful. And then just wanted to get your thoughts on hedging. I know Tracy, you mentioned that you're looking to add some for 2016. And just wanted to get your thoughts on what you're looking for in order to get more aggressive with the hedging position next year.

We've identified an internal target for crude oil prices at around $65 per barrel for WTI. This week, we observed that the hedges and forward prices have reached approximately $65 to $65.50. While I haven't checked today, we're nearing the point where we intend to begin building our hedge portfolio. I discuss this with the board a few times each week to keep them updated. Their guidance suggests we aim for hedging between 40% and 70%, but we are currently not close to that percentage for 2016. We see a promising trend in commodity prices, monitoring it closely, and may start to add hedges in the near future.

As you increase that rig activity, really kind of looking at the '16 forward time frame, should we anticipate that the number of wells on your pads will also increase? Or how should we think about that?

Yes, Gail, I believe the most effective use of capital is achieved by keeping a rig on the pad for as many cycles as possible. Our ideal scenario appears to involve approximately a three-well pad. This involves various aspects such as drilling and simultaneous operations with adjacent completions. As we continue to add rigs, a growing number will be located on multi-well pads. While we haven't thoroughly examined 2016 yet, particularly with the new acquisition, the majority of our rigs will operate on multi-well pads. The only horizontal rigs that won't be on pads will be those that move around a bit in the Northeast Andrews County and Northwest Martin County. Aside from that, we will primarily focus on pad work.

Okay, great. I was wondering if you could provide any update on the Lower Spraberry well in Dawson County and its performance.

Yes, the Dawson County well has been producing for quite some time now. It continues to meet our earlier projections, which are around 600 MBOE. Given the current commodity prices, I would say it's above our threshold rate of return. While it doesn't quite match some of our other Lower Spraberry results, we are optimistic that as commodity prices improve, we will also develop that acreage block further.

I was hoping to maybe get your thoughts on production growth throughout the remainder of the year, I know you guys don't like to give quarterly guidance, but looking like maybe 2Q, maybe a little bit stagnant as you start. And then maybe you just start working down the backlog. I assume second half will be stronger. And is the assumption that a lot that is probably going to hit 4Q? Or maybe some contribution in 3Q? Just kind of getting your thoughts on production cadence throughout the remainder of the year.

Yes, that's a great question. As you noted, we don’t provide quarterly guidance. However, earlier this year, we emphasized the importance of capital discipline and returns, which led us to defer completions and reduce the number of rigs. The impact of this decision will primarily be seen in the second quarter, resulting in fewer wells completed compared to the first quarter. Your initial thought on how the production profile will appear is likely accurate. As we ramp up rig activity and completions, we expect to return to a trend of increasing volume, whether that’s at the end of the year or at the start of next year.

Okay, that's helpful. And on the acquired properties, obviously getting a nice leg of production there. Do you guys kind of have a sense for what the base decline is with those existing wells? Seems like with a mix of newer horizontal and I guess some legacy verticals there.

Obviously, the biggest majority of those are vertical wells. And the horizontal wells that are on there right now are some non-operated wells where we have a low working interest, so that's very little impact. Most of those vertical wells have been on production for 4 or 5 years. So we're down in kind of that 15%, 20% decline rate on the PDP.

Okay, perfect. And then last one for me. I guess with the planned acceleration in activities, is there an increased interest on your end to test more downspacing, other types of upside projects across your acreage position? Or is it still just kind of going for the known quantities in your portfolio?

Yes, Jeff, that's a good question. I don't think we're ever satisfied that we're extracting all that we can out of these unconventional rocks. So we continue to try different things. More, I would say, tweaks as opposed to complete overhauls on our completion strategy. Again, Jeff White and his completion organization, they stay up to speed on all the ongoing completion enhancements that are taking place out here in the Permian. And in selective instances, they try that, and we monitor it so that we make sure we can get good feedback on the changes that were made. But in the general sense, it's more tweaks than complete overhauls.

Can you give us an update on the Lower Spraberry wells you drilled on 500-foot spacing? And if you think that the 500-foot spacing is applicable across your acreage? And if you're not there yet, kind of what you need to see before you get comfortable with that?

Yes, if you look at the slide showing our Lower Spraberry results for Midland County, it's in Slide #6. The 500-foot spacing for the ST West, 7-1LS and 7-2LS wells shows the average of those two wells on that pad. So far, it's tracking with the results of the other wells, but it's still early. We've had about 150 days of production on those two wells, and the results are quite encouraging. Currently, in the Spanish Trail area, we're proceeding with the 500-foot spacing and will test that spacing in our other areas as well. We recently completed a microseismic survey on a three-well pad in Spanish Trail, which we conducted at 660-foot spacing, and we are just now receiving those results. We will carefully analyze the microseismic results and adjust our spacing as necessary moving forward.

Okay, great. And then Diamondback's talked about being cash flow neutral or positive in the second half this year. Is that still the case if you choose to add the 2 rigs? And then are those 2 rigs included in the $400 million to $450 million CapEx program?

Yes, Jeff, as indicated in our prepared remarks, this increased activity will still be within our original guided CapEx range because of the cost concessions that we've seen today. So that's a not too subtle message that we're able to stay within our original CapEx guidance, not increase it, but get increased activity.

Travis, just a quick question on the acquisition. Just wondering, the vertical well control, is that across the acreage to give you enough confidence in that cross section that you provided, I guess, on Slide 17, with the different targets?

Yes, absolutely, Jeb. We've got real fulsome analysis from a cross-section perspective, both East to West and North to South, across this acreage block. So extremely good coverage with vertical well control. And then again, as I highlighted and we've included in our slide deck, there's enough offset production data as well to further enhance our confidence.

Can you update us on what you're doing right now to possibly improve those EURs above what Ryder Scott provided earlier this year?

Well, as I mentioned on the previous call, we're not making major overhauls to our completion design. We continue to go 300,000 or so, 300,000, 350,000 pounds per stage, our per-foot concentration is 1,200 to 1,500 pounds per foot. And we're predominantly using white sand in our Wolfcamp completions and brown sand mostly now on our Lower Spraberry completions. We continue to tweak the number of clusters between each stage and also tighten the interstage distances to get a few more fracs in there. And we've done that on a couple of 2-well pads now. And we're monitoring results real closely to see if tighter spacing has a corresponding impact on the EUR.

Travis, just had one for you. Obviously, coming back and starting with the inventory and then the second frac crew. Just curious, do you have a rough idea of what your backlog looks like now? And what you think it will look like on a steady-state basis as we get to the end of the year?

Yes, we are currently in the range of approximately 15 or more wells waiting to be completed. A reasonable backlog for each rig is around 2 to 3 completions. This seems to be the most efficient way for us to manage operations and transition the crew to the next well that is ready. From a planning perspective, you can anticipate having 2 to 3 wells waiting for completion for each drilling rig.

Two quick questions. So this acquisition should bring your total to around 89,000 net acres in the Permian. You looks like you let a couple thousand acres go in February in Crockett County. What's the outlook for any additional exploration of acreage this year? Particularly interested in acreage in Central Andrews. I guess you have maybe upward of 10,000 acres there. What's the outlook for that?

Sure, Richard. We often joke that we're hunters, not farmers, and we're never completely satisfied that our inventory is where it should be. We're always looking to grow by making acquisitions that add value. We'll remain active in the mergers and acquisitions space starting today. We're not strictly an exploration-focused company, but we will keep engaging in the M&A market. I'll let Russell address the question about Central Andrews County.

In Central Andrews County, we have tested the Clearfork formation with a couple of horizontal wells. As mentioned previously, the second Clearfork well we drilled in the Lower Clearfork Shale has maintained strong performance, with declines that are much flatter than we initially anticipated. The outlook for the Clearfork continues to improve based on the performance of that second well. At current commodity prices, it is certainly economic, but it doesn’t rank in the top quartile of our inventory. We will likely test the Clearfork again within the next year to verify these results, but we do not have a program for 2015 at this time.

Okay, Russell. That's helpful. And then lastly, Travis, I'm not sure if you covered this earlier. How do you divide that between internal efficiencies and vendor reductions?

That's a good question, Richard. I think the split is probably closer to 80-20, maybe 90-10. But you have to keep in mind that as we've built this company over the last 3 years, our efficiencies. So we've never satisfied that we've got all the pennies picked up off the ground from an efficiency perspective. But probably 80-20, 90-10, with the larger number being associated with service cost concessions.

Travis, I was just wondering that slide you have that shows the downspace and stack pay potential, I guess my question, are you still pretty optimistic about on the 3 areas there on the Middle Spraberry going from 6 to 8 per section? And then looking at the lower 8 to 10? And then obviously, the Wolfcamp from 4 to 8? On not just in Spanish Trail, but your thoughts about sort of that similar downspacing if I look at either Southwestern or Northwest Martin or Howard or Glasscock.

Yes, Neal, we might be a bit cautious in how we assess the number of laterals in a section. We consider this a measure of risk. The less we know about a zone, the fewer laterals we will include. The industry has demonstrated that when shale plays are productive and financially viable, the optimal range tends to be between 6 and 10 laterals. In the Middle Spraberry, we have a few wells drilled and some testing underway, but we lack extensive information. The industry has shown, especially in the Permian and other basins with shale developments, that the spacing tends to become tighter over time as more wells are drilled. Thus, our well planning and counts are generally skewed upwards based on the success observed in these productive zones.

Got it. Lastly, for you or Tracy, regarding your comment about the positive cash flow in the second half, what commodity prices are you using there? Are you assuming current costs?

Yes, current costs, but we modeled the company at $50 flat.

I just had a quick follow-up question on the Howard County acquisition. So the acreage there looks to have very good oil in place and thermal maturity. Can you just talk to the porosity and permeability that you're seeing there? And maybe kind of compare that to the Glasscock asset that you acquired last year?

What we've observed regarding porosity is quite similar. Measuring permeability can be challenging, but the performance of the offset horizontal wells on our Howard County acreage indicates that permeability in that area is promising based on those results. In Glasscock County, particularly in the Wolfcamp section, it is thicker and contains more oil in place. There has been less horizontal drilling activity in that area, although some recent well results from Apache nearby have been very encouraging according to public data. We remain optimistic about our Glasscock County acreage and plan to drill our first wells there in the second half of this year.

Okay, that's helpful. Just one last question regarding Viper. I understand there's limited cash flow from the override related to the Howard County acquisition reflected in the revised 2015 production guidance for Viper. I'm curious if you could discuss how you expect the cash flow profile of that asset to develop and the reasoning behind the valuation of $33.7 million.

One of the things we were really excited about regarding the Viper level was that the growth potential associated with the overrides that Diamondback has provided to Viper actually surpasses the growth potential found in the legacy Viper assets. After spending the last nine months searching nationwide for acquisitions at the Viper level, it’s quite unusual to identify this type of growth profile. As we laid out our Viper strategy, we aimed to acquire assets managed by a capable operator, which in this case is Diamondback Energy. We were focused on acquiring assets that are either actively being developed or are close to development, which, as Russell pointed out, is set to happen soon with significant activity on the horizon. Additionally, the high oil component is approximately 75% to 80%. Therefore, this acquisition aligned perfectly with our objectives.

I guess one question. I just wanted to try and get at was given the accelerated ramp in '15, slightly accelerated, and the outlook for potential additional rig adds in '16. Any color or commentary on what that could do for 2016 production growth? And what that might look like in 2 different scenarios?

Yes, Michael, we haven't really focused on what 2016 will look like as of early May. However, as we progress through this year and bring on more rigs, we'll be able to provide better clarity about 2016. One thing I can say is that as we add rigs and boost completion activity, volume growth tends to respond positively. Therefore, we expect that with more rigs and increased completion activities, our growth profile will continue to advance in the future.

Make sense. Figured it was early, but worth a shot. And then I guess, I was also curious on your views on concurrent completions in the Wolfcamp and Spraberry and how important that is, or not important, as you think about full development on the various assets.

Yes. I think when you look at our assets on the Western side on the Northern Midland Basin, you've got some pretty nice distinctive zones with some nice frac barriers in between the Wolfcamp and the Lower Spraberry, for example. As you move east and you get some thickening in the shale deposition, it starts to make more sense to us to do stacked laterals. And so while we've not definitively come out and exactly spelled out what our strategy is going to look like, I think it's more likely than not that we'll be drilling stacked laterals, not only in Glasscock County but also in this Northwest Howard County block as well.

Okay, that's helpful. And then on the cost front, what's the average AFE you guys are expecting now in the second half for a 7,500-foot lateral?

Yes, we anticipate being at the lower end of our guidance, which is between $6.2 million and $6.7 million. There’s a highlight in my remarks regarding some wells we are finalizing, and while we don't have all the costs yet, they seem likely to fall in the $6 million range. However, since we are completing several wells that were drilled last year before all the cost adjustments were made, we still expect to remain within the guidance of $6.2 million to $6.7 million for a 7,500-foot well.

Okay. And then last one on my end is just around completion capacity. You've got the rigs outlined or contracts, it sounds like, are lined for the back half of the year. Any needed additional completion capacity? And have you arranged for that? I imagine there's plenty available.

Yes, that is a consideration. There is a lot available. However, our approach typically allocates one dedicated crew for every two to three rigs. Once we reach eight rigs, we will likely have two fully dedicated crews and possibly one partially dedicated crew. Consequently, that ratio of one dedicated crew to two or three rigs serves as a good planning guideline.

Thanks again for everyone participating in today's call. If you've got any questions, please reach out to us using the contact information provided. Thanks, everyone, and look forward to talking to you again in the future.