Diamondback Energy's CEO Hosts 2014 Guidance Conference (Transcript)

Oct.24.13 | About: Diamondback Energy (FANG)

Diamondback Energy (NASDAQ:FANG)

2014 Guidance Conference

October 24, 2013 10:00 AM ET

Executives

Adam Lawlis - IR

Travis Stice - President and CEO

Tracy Dick - CFO and SVP

Russell Pantermuehl - VP of Reservoir Engineering

Analysts

Ryan Oatman - SunTrust Robinson Humphrey

Kerr Friedman - Simmons & Company

Mark Lear - Credit Suisse

Gordon Douthat - Wells Fargo

Tim Rezvan - Sterne Agee

Richard Tullis - Capital One

Stuart Zimmer - Zimmer Partners

Jason Wangler - Wunderlich Securities

Ipsit Mohanty - Canaccord Genuity

Jeffrey Connolly - Brean Capital

Eli Kantor - IBERIA Capital

Jeb Bachmann - Howard Weil

Operator

Good day ladies and gentlemen and welcome to Diamondback Energy 2014 Guidance Conference Call. At this time all participants are in a listen only mode. Later we'll conduct a question-and-answer session and instructions will be given at that time. As a reminder this call maybe recorded. I'd now like to introduce your host for today's conference Adam Lawlis, Investor Relations, you may begin.

Adam Lawlis

Thank you, Mercy. Good morning and welcome to Diamondback Energy's 2014 guidance conference call. 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 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.

During our call today, we'll reference certain non-GAAP financial measures which, we believe, provide useful information for investors, including reconciliations of those measures to GAAP in our filings with the SEC. I will now turn the call over to Travis Stice.

Travis Stice

Thank you Adam, good morning and thanks for joining us today as we host our call to discuss our plans for 2014. As you know from our press releases, over the past weeks, we've been quite busy since our last quarterly conference call executing on roughly $600 million worth of acquisitions, raising capital paid for them and further ramping our production curve. We recently celebrated our first year anniversary as a public company with the buying (Ph) crossing the 10,000 barrel a day production threshold at the same time. We've been meeting lots of investors here in Midland and on the road as part of group events and individual meetings but this is our first Diamondback call where we're speaking with everyone together since our last earnings call.

Before I get started, I wanted to commend my leadership team and organization on their continued ability to execute despite all the growth that we've been enjoying. As you guys know I'm not a Wall Street trained guy but I do understand dedication, commitment, skill and a West Texas work ethic and I'm proud to be surrounded by the team I have as we enter into another exciting year of growth in 2014.

First of all let me update you on our current activity as outlined in our press release from yesterday. We expect a fourth rig to arrive in early November and initiate our delineation program as some of the new 11,150 net acres we acquired at the end of the third quarter in Martin County. The opinion on frac schedule and results of these wells are expected in the first quarter of 2014. Successful results this year have de-risked both Upton and Midland County for the Wolfcamp B in our opinion, and our recent successes in Andrews County have now added two additional development horizons in our portfolio, one in the Clearfork and one in the Wolfcamp B shale.

Additionally, we expect a fifth rig to come on in the second quarter of 2014. As we prove up and are successful in this new northern acreage, we'll likely have the opportunity to accelerate either in the form of adding additional rigs or as we demonstrated this year drilling these wells faster or said another way drilling more wells with the same number of rigs.

Looking ahead into 2014, we've outlined our production guidance of between 15,000 and 16,000 barrels a day which represents an increase over 2013 average production by more than a 100%. 2,500 to 3000 barrels of this is expected to come from these recently acquired minerals that we bought. This is based on a range of 24 CapEx between $425 and $475 million; nearly 48% more than what we anticipate spending in 2013. Naturally, this 2014 spending guidance excludes any additional acquisitions and is expected to be entirely financed with internal cash flow and revolver debt. We expect our balance sheet and liquidity to remain strong through this production ramp up partially enhanced by recent minerals interest acquisition. We expect to drill between 65 and 75 gross horizontal wells in 2014, with gross cost expected to range between $6.9 and $7.4 million for a 7500 foot lateral horizontal which is down over 10% from our 2013 guidance. It should be noted that while we traditionally speak about a 7500 foot lateral, the average lateral length for 2014 is expected to average approximately 6500 feet due to lease geometry. It's anticipated that roughly half of the wells drilled in 2014 will be from pad locations which should support these cost savings over our 2013 levels, we've revised guidance somewhat on the cost side, now reclassifying ad valorem as part of a production tax rather than as LOE. This works out to a shift of roughly a $1.50 a barrel from one line to the other and the reason we did this was to more consistent with the way our peer group does, most of which we report this way.

Lease operating expenses for 2014 are now expected to be in the range of $6 to $7 per Boe, down from our prior adjusted guidance in 2013 of $9.50 to $11.50 per Boe, which represents a year-over-year reduction of approximately 35%. G&A per Boe declined to between $2 to $3 a barrel down from the prior range of $3 to $5 in 2013.

Given the substantial difference in cost structure and capital intensity, 2014 guidance for our mineral interest have been broken out for transparency purposes. Mineral interests are fully consolidated on a line-by-line basis but represent a 20% to 25% net revenue interest in the production associated with our Spanish Trail in Midland County.

As most of you know, our business can be at the same time very simple and very complex. Our plans that we’ve just laid out have risks associated with them. While you can expect this team to manage those risks, I’ll lay out for you the top things I worry about in delivering our 2014 plan.

First, timely access to frac water. While we anticipate utilizing frac water late this year, we still need to be strategic in the location of our wells ensuring timely completions and once the drill rig moves off locations;

Secondly, inner-well frac interference. Best practices that we’ve seen not only in the Permian basin but in our experience in other Shale basins around the lower 48 is to shut in our offset wells prior to frac operations and keep them shutting until we get the wells cleaned out and put on line. Now, while we don’t expect an EUR impact to short-term production interruptions are possible.

Third, pad drilling. I think I mentioned earlier that roughly half of our wells are scheduled to be on pads next year. We know that the cost savings justify that decision but our part times are all placed on production times were likely to be extended and our production will have these periods of irregular growth. For example, our 2013 exit rate, I quoted yesterday in our press release was I think I said in excess of 11,000 barrels a day.

We’re completing our first two well pad this week and we’re drilling our second well on our second pad, that’s four wells that I hope to have on line by the end of the year. If we do, our exit numbers will likely to be higher if we don’t, you’ll see that higher production in the month of January.

And then fourthly, our third party gas gathering. With the tremendous growth in production that we’ve seen in the Permian basin, particularly in the Midland portion of the Permian basin, we noticed that our infrastructure is lagging from our third party gas gatherers in several of our leases. This impacts our business in the form of high line pressure at our tank batteries with occasional flaring. While it’s not a large revenue impact since we do report equivalent two stream volumes missing that gas can have an impact to our reported numbers.

Again you can expect this team to manage through these but I wanted to provide you with this transparency.

In closing, we’re in the process of wrapping up 2013, a year where we’ve seen significant growth in volumes and cash flow, declining well costs, declining expenses and the infusion of new drillable inventory through the acquisitions we closed. We look forward to an equally exciting 2014.

Operator, at this time, would you please open the lines up for questions?

Question-and-Answer Session

Operator

(Operator Instructions) Our first question is from Ryan Oatman from SunTrust. Your line is open.

Ryan Oatman - SunTrust Robinson Humphrey

Hi. Good morning. I know that Midland County and Wolfcamp B is going to be the primary driver. But I was wondering if you guys could break out the 2014 plan between additional zones that you might test, whether it’s the Wolfcamp A or Clearfork or Cline, and et cetera, Spraberry? And then also a little bit more on the geographic split. How you plan to de-risk some of the most recently acquired acreage?

Travis Stice

Sure Ryan. Let me just kind of go south to north and we’ll start down in Upton County. Most of the Upton County program this year will be Wolfcamp B. we’re kind of anxiously awaiting some competitors or some offset operators down in that area to deliver some more Wolfcamp A results. And you know for us to begin more of a development program with lower Spraberry for sure and depending on the results in the middle Spraberry you might see some more there also. And then specifically we'll start next week as a matter of fact or maybe week after next drilling our first well in Martin County.

And that will be a Wolfcamp B well, and we'll drill a well or two in Martin County and we'll remove the rig back into Andrews County and drill our second Wolfcamp B well. And then specific to your question on the Clearfork as I outlined in my press release, the Clearfork well is describing quite a bit different looking production profile than what we typically see in the Wolfcamp B wells. So we need sort of more months on that to make sure we understand what that well production is going to look like in relation to the anticipated DMC cost that would require for a full scale development program.

So that kind of gives you a range, but in the second half of the year Ron that's where we anticipate success in both Martin and Southern Dawson County, and that as I mentioned some of the acceleration opportunities that I think our shareholders can expect from this given success.

Ryan Oatman - SunTrust Robinson Humphrey

Excellent. One follow-up from me and then I will jump back in the queue. It does sound like you guys are perhaps a little bit more confident on Spraberry than I would have anticipated at this point. What provides that confidence for you guys at this point?

Travis Stice

It's a good question Ron, and really the most meaningful data we have is quite a bit of production history on the one well that's 1.5 mile to the west of our Midland County acreage. And that well has been online for how many months Russell?

Russell Pantermuehl

About six months.

Travis Stice

Yeah about six months of production and it’s drawn a real nice production curve, that's very equivalent to what we have seen the Wolfcamp B. So with that kind of production history and that proximity to our acreage, and then again when you look at the depositional setting of the Spraberry, it's very contiguous across the entire Midland base and gives us confidence to kind of offset that well, which we have done through participating with the third party operator, it's just not online yet. But we’re pretty confident that lower Spraberry.

Operator

Our next question is from Kerr Friedman from Simmons & Company. Your line is open.

Kerr Friedman - Simmons & Company

So kind of first off, thinking towards full year '14 production, I know you guys try to stray away from providing too much quarterly color but I was curious if you could provide any details pertaining to the production profile for the year or so? Right now I am kind of thinking that production likely increases in 1Q and 3Q more drastically than 2Q, 4Q. Could you confirm that or do you have any color for the general production profile on the year?

Travis Stice

Yeah, Kerr since we’re doubling production next year and we have got not quite a steady rig cadence, we're picking the fifth rig up in early second quarter. We're not guiding towards any kind of quarterly numbers, and I am not trying to be resistant in doing that, it's just really when you look at some of these pad wells and our uncertainty in how quickly we can get pad wells on line and producing. I am afraid you will hold me accountable to a quarterly number that here in the middle of October is hard to predict what the third quarter of 2014 is going to look like.

So we give you annual guidance and expect to be in that range of our annual guidance and we'll provide color for each quarter as we have our quarterly conference calls.

Kerr Friedman - Simmons & Company

We potentially see you guys bring rig into Ector County in 2014?

Travis Stice

Likely not into Ector County in 2014, there may be a vertical well or two that we need to drill the whole lease obligations together there, but probably not until we move into a testing and development mode in the Cline, that's where we think Ector County is most perspective in the Cline. So we’re still away from testing the Cline.

Kerr Friedman - Simmons & Company

And then last question from me and I will jump back in, but drilling times continue to turning just a bit lower by my math looks like horizontals are estimated to be drilled in an average of about 23 days 2014. So I am curious if you could provide a little color as to the primary credit for bringing these drill times lower in 2014. I mean is it primarily attributable to pad drilling? Or just be more efficient in executing the operatorship of these wells?

Travis Stice

At the end of the day it's all about execution and execution and cost efficiency and so as Mike Hollis and the drilling organization continue to hold each other accountable for deeper and cheaper and faster, it's really that extreme focus on efficiencies in the course cost follow on very nicely with that.

Pad drilling in terms of cycle time does offer you a little bit when you are making rig moves in four to 12 hours versus rig moves in three to seven days. You do pick up a cycle time improvement, but it’s really that minute by minute, hour by hour focus on execution that allows us to differentially drill these wells faster than just about anybody else out here.

Operator

Our next question is from Mark Lear from Credit Suisse. Your line is open.

Mark Lear - Credit Suisse

First question, just on the cost front, definitely making some good progress on drilling complete cost, have you been able to lock in, I know probably a good chunk of that’s because of pad drilling, but have you been able to lock in services and in consumables, you know should keep that from drifting higher in 2014.

Travis Stice

Well on the drilling side, Mark, a couple of our rigs, you know that are capable of walking or being skidded (Ph) efficiently. We have locked those in for a one-year contract, and those are just getting started. On the completion side, you know we are seeing some nice reduction over the last 12 months or so, on the stem side as you’ve seen frac fleets from our gas basins migrate their way into the Permian. We don’t have any specific long-term contract locked up with our stand service providers. But at this point we are still seeing real nice frac-on-frac competition for our services. So those are conversations we are having, but we don’t have anything locked up yet.

Mark Lear - Credit Suisse

Got you, and then just on the development of the mineral interest, you know with the fifth rig coming, is there potential to see more activity than two operated rigs, in Midland County in 2014 to accelerate the value at those interests?

Travis Stice

Yes, absolutely Mark. We are looking at water system or water supply system right now for fracing these wells to see if we can support potentially a third rig in Midland County for different portions of the year. And then again as I commented earlier when we assumed production levels on the non-ops, which is roughly half of that 15,000 acres. We have only assumed those non-operators won’t run in one drilling rig. You know I think it’s reasonable to expect, given, if they can replicate our kind of results, you know either expecting to accelerate activities well. But that’s not the way we have got it modeled.

Mark Lear - Credit Suisse

Got you, and then what are the communication levels between you guys. Are you guys working closely in developing that asset?

Travis Stice

Absolutely, yes, very close to those are great guys and we are proud that they are our business partners.

Operator

The next question is from Gordon Douthat from Wells Fargo, your line is open.

Gordon Douthat - Wells Fargo

Question again on the cost side, for well cost, are those reductions due solely to pad drilling or do you have other savings, efficiency games bagged into that number? And do you seem do you want to get further into pad drilling?

Travis Stice

Yes, I could tell you, just like on the LOE expense side you know we’re never happy with cost. We always try to push the envelope and the phrase that you’ve heard me use before, Gordon, it’s not a destination. It’s a journey. We do anticipate further cost savings as we dial in more and more pad wells as a percent of our total wells drilled. And, quite obviously, I still expect both the productions and the operations organization to drive more efficiencies in their day-to-day activities which are also going to reduce cost as well.

Gordon Douthat - Wells Fargo

Okay, and then on the well that you are drilling on pad, how many wells per pad will you be drilling?

Travis Stice

The first two pads that we have got, we will frac in our first two well pad right now, and we are drilling our second well in our second two well pad. But very quickly through the end of this year you will see us migrate to three well pads. And then probably Russell, the wells next year, will then mostly be three well pads.

Russell Pantermuehl

Yes, it really depends on the water situation, I will tell you about half of them, the way we got them scheduled right now, are three well pads. We’re confident; we have enough water availability to you know not delay the fracs too longer on the three well pads. In the other half, we have got scheduled is 2 well pads, but you know those could migrate to three well pads as well as you know our water infrastructure develops.

Travis Stice

You know, specific to that comment we’ve talked in the past and in fact we’ve allocated capital this year and we’re just about finished with our water gathering project which will allow us to take water out of the system in our Spanish drill area and provide makeup water as much as 25% to 35% of our initial fracs, potentially could use our recycled water. So as that program gets up and running and we understand the true efficiencies of fracing with recycled water, you know we could have moved towards more and more, or higher and higher percentage of our total fluid being provided from flow back. But we kind of got to move up the learning curve on exactly how that’s going to work. But that would impact as Russell pointed out, that would impact two well versus a three well pad decision.

Gordon Douthat - Wells Fargo

Okay, and then on the productivity side with your guidance, what type of curve is that? Can you remind us with your larger modeling for those type curves, and is it in the upside to them?

Travis Stice

Well we have given you a blended type, what we have done is we have given one blended type curve across our entire equity base of about 600,000 BOEs on a two stream basis.

Russell Pantermuehl

For certainly 7500 for the lat….

Gordon Douthat - Wells Fargo

For a 7500 for the lateral?

Russell Pantermuehl

For a 75 on foot lateral things also -- again that’s a two stream basis.

Travis Stice

So that’s really no change from our current type curve obviously as we get these wells drilled in the Northern area and see little more production data from our longer laterals in Midland County. We could revise that throughout the year, but right now we’re still sticking with the type curve we’ve been using the past.

Gordon Douthat - Wells Fargo

Okay good update today, thanks guys.

Operator

And this question is from Tim Rezvan from Sterne Agee. Your line is open.

Tim Rezvan - Sterne Agee

Folks, I’m kind of following up on that last question, I was wondering if you could talk about how GOR ratios are holding up and the wells that had been producing longer, and then if you could talk about what is baked into the EBITDA sensitivity table that you’ve provided on 2014?

Travis Stice

Yes, I will talk a little about GOR. In general, as we’ve talked about previously that the GORs in the Southern area Upton County generally are higher than what we’ve seen as we move to the North. Generally, all these wells start out was about 1000 GOR and what we’ve seen in Upton County is after about six to nine months the average GORs about 2000 in Upton County. It does vary a lot from well to well. We are still not really sure why there is the large variation that we’re seeing.

But again you up to that 2000 GOR after six to nine months in Upton Country, in Midland Country the GORs have remained lower on average, maybe a 1500 GOR after six to nine months, and there is some wells remained roughly 1000 GOR over that same period. So, on average, pretty much the same numbers as we’ve communicated previously, we’re still pretty early in our Andrews County, Wolfcamp B results but so far pretty similar to Midland County on a GOR basis.

Russell Pantermuehl

And Tim just on that EBITDA table, what I was just asking Tracy to calculate for us some sensitivities to EBITDA, and the way that table is actually put together is we’re just taking the midpoint of our production and we’re included any impacted hedges, just the midpoint of that production table with those different commodity prices held flat for one year. So it’s just a way for us to kind of sensitize on plus or minus $10 or $20 a barrel in relative impact to EBITDA.

Tim Rezvan - Sterne Agee

Thanks, I appreciate the colors guys.

Operator

Next question is from Eli Kantor from IBERIA Capital. Your line is open.

Eli Kantor - IBERIA Capital

Good morning, guys. Question on wellhead economics and you’ve recently acquired Martin and Dawson County acreage position, we’ve seen a highly prolific Wolfcamp B from pioneer just to the South and couple of A bench wells from W to the West, trying to get a sense that how we should be framing well productivity in that area that you recently acquired, and if there is going to be any kind of well class differences that might also have an impact on rates of return?

Travis Stice

We are still modeling that same 600,000 barrels two stream reserve number that Russell just quoted, you know, for even Martin County even in the face of some of those big pioneer well results. We have not drilled the well up there on horizontal well yet. Typically, you will see the first well or two that you move into an area. Your built typically be a little bit higher as you’re slightly more cautious in your development in your initial drilling before you move into full scale development. So you may have a marginally higher cost on the first couple wells.

But again all I looked is I go back and look at to track some our guys have left in the sand, every time we’ve given them a repeatable drilling in completion opportunity, and cost continue to move down to the right as you forward in time. So while you may have a little bit higher cost initially fully expect to be competitive with the rest of our development portfolio.

Eli Kantor - IBERIA Capital

Okay that’s helpful. Second question is on your recently completed Clearfork horizontal looks like both the productivity declined profile and well cost is entirely lower than what you’ve seen in Wolfcamp B, I was wondering how the preliminary IOR for the Clearfork stacks up against what you’ve seen for the Wolfcamp, after any other zones in that portion of Andrews County that you may look to test horizontally?

Travis Stice

Yes, I can’t give you a project EUR or project IRR yet because we just don’t have a good handle yet with just a few weeks of production on what that will do in terms of total reserves and of course we need that describe the future economics of investments. So that’s why Eli we’ve said we’re going to wait about six months before we come out and start talking about our next development scenario. We do know that in order to be competitive, we will have to lower costs even from the $6.5 million or $6.8 million range that we spent on that well and the guys already have their scalpels out and are starting to carve away costs right now for what a full scale development program would look like and the associated costs for Clearfork development but again any specific numbers on that still premature at this point.

Russell Pantermuehl

Just to comment to other zones in that area; the Wolfcamp B shale is just present in that area. It is getting a little thinner than some of our other acreage but we have actually been pleasantly surprised by some Wolfcamp B wells and in Ector County where the shale is pretty thin. So, I think there is a pretty good chance that Wolfcamp B will be economic on part of that acreage and there is another operator that is drilled but not completed or at least not reported any production results yet just to the north of our acreage there. So, we’re watching that pretty closely as well.

Travis Stice

And just to clarify when we talk about Andrews County we kind of bifurcated into northeast portion where we’ve already drilled that good wells so that’s all good Wolfcamp B country, the specific area we’re talking about now is the portion that is more in central Andrews County and a little bit west where that’s approaching the edge of central basin platform. So, the comments that Russell was just making is specific to that kind of western 9000 acres that we have.

Operator

And this question is from Jeb Bachmann from Howard Weil. Your line is open.

Jeb Bachmann - Howard Weil

One, with the fall of redetermination essentially concluded get any kind of insight into what reserves could like at the end of this year?

Travis Stice

We’re going to that process right now. We updated reserves September 1 and had almost 58 million barrels of reserves at September 1 and we’ve communicated that and then Russell’s, he’s got Ryder Scott engaged right now doing on end users.

Jeb Bachmann - Howard Weil

The other one on with Longhorn, can you give us an update on how many volumes you putting to do there at this point?

Travis Stice

There was a total collapse for the month of October and forecasted the WTI nevertheless but you guys remember that contract that we have is a better of pricing. And so for the month of October, when I say better of pricing once you get to know timeframes you can chose the better of pricing going to Midland-Cushing or down to Longhorn pipeline. So, for the month of October, our deliveries were back into Midland Cushing because economics supported that decision.

Now in the last two three days we get all the moves in the systems or what’s going on again with the Mid-Cush differential and now you making economics more favorable for deliveries back into Longhorn pipeline for the month of November but we’ve got spreadsheet we’re working on that right now to figure out what’s the best economic return when we get those barrels to Midland [indiscernible].

Jeb Bachmann - Howard Weil

You guys looking at any opportunities to maybe core up acreage positions by swapping with other guys we might not have the large positions if you guys get opportunities out there?

Travis Stice

Yes. We are not consistent with shareholders that it’s reasonable to expect any kind of large transaction or small transactions that Diamondback Energy should be involved in those conversations and certainly even on the much smaller scale Jeb, swapping and coring up acreage I think that’s a good business practices in this, we’re very active in that as well too. It’s just at this point it’s probably not material to our 65,000 mid acreage but it’s very material in terms of any individual well that gets drilled. So, welcome you through each one of the individual wells and what acreage swaps we might and might not have done, and tend to focus you on more than the macro acquisition opportunities.

Operator

The next question is from Richard Tullis from Capital One, your line is open.

Richard Tullis - Capital One

Travis, on the horizontal guidance well cost range for next year is 6.9 million to 7.4 million. Is the low end to that range more related to the shallower wells that you plan to drill or can you see Wolfcamp B wells getting down to that level?

Travis Stice

Well certainly depth is a function of cost and our Upton County wells in general are less expensive than Midland County wells because we’re gaining about a thousand feet depth as you move from Upton County and the Midland County. So, there is a big piece of that, big portion of that kind of range there which is Upton County versus Midland County.

But again, we’re never satisfied on our D&C cost and so we’re continuing to tweak [indiscernible] and try different things that are more and more efficient in terms of cycle time and of course days are dollars to picking to changing things that can you give you a nice cost advantage. So, it’s a process and as we marquee a couple of big items, we’ll be able to talk to you about them. Right now, it’s easier to think of shallower is cheaper and so that’s kind of the Upton County to Midland County and Martin County range.

Richard Tullis - Capital One

Okay, are you including gathering and transportation in your LOE guidance for next year, Travis?

Travis Stice

Not in that $6 to $7 per barrel, we have got it, right now we're just trying to report like our peers are so that transportation, third parties is not included in that number.

Richard Tullis - Capital One

And how much do you expect that to run next year roughly.

Travis Stice

I mean, Rich are you talking about all gathering costs, are you talking about gas gathering, what?

Richard Tullis - Capital One

Well, on a combined basis if you have it on a barrel, Boe basis.

Travis Stice

When you look at all crude somewhere typically on truck it's going to run you about 250 to 350 a barrel, probably more biased towards the lower end and gas we typically $0.25 to $0.35 an mcf for gas gathering.

Richard Tullis - Capital One

And then just lastly, where do you expect to be concentrated in the vertical drilling, in 2014?

Travis Stice

Well we're going to honor all of our lease obligations and to the extent we can't honor our lease obligations with drilling horizontal wells, we'll keep that vertical rig available to go, you know knock one of those wells out. But in addition to those obligation wells, again vertical wells, where we own the minerals in Midland County are highly, highly economic and you'll see us continue to drill a few wells there. And then again just on the cost front, we're talking about and testing using some lower cost vertical wells to set deep intermediately on these horizontals before we move in the more expensive horizontal rig. So we want to keep our optionality open there you know in the event we can prove that up to be an efficient way to reduce costs.

Tracy Dick

Hey Richard, just want to clarify that the transportation on our oil is always netted out of our realized price. It's not a separate line item that hits. So the deduct for the gas is very minimal.

Operator

Our next question is from Josh Jones from [indiscernible] your line is open.

Unidentified Analyst

Hi guys, thanks for breaking out this, the details on the mineral rights production next year, I guess my question is, I think if I heard you right you said you're using a kind of a blended average plus your acreage base for your Wolfcamp B type curve to form your guidance. Are you using that same EUR 600,000 for the mineral rights production or are you using something more specific to that area?

Travis Stice

It's the same curve all the way across, same wells.

Operator

Our next question is from Brett Riley from Zimmer Partners, your line is open.

Stuart Zimmer - Zimmer Partners

Hey Travis, it's actually Stuart Zimmer. So, the first thing I wanted to say before I ask my question is, looking at this screen the stock is $51. I realized that in the last year you've literally tripled our money since the IPO and since that doesn't happen to me very often I just wanted to take a moment to say thank you and great job.

The first question on my mind was thinking about Midland pricing versus Cushing, I'm curious if you see any constraints in pipeline capacity that would cause Midland to disconnect from WTI.

Russell Pantermuehl

You know right now, I mean we think there's plenty of capacity on a normal basis so it's really, right now as Travis mentioned earlier just in the last few days you know we'd seen a big deduct for the Midland to Cushing differentials, but you know it's generally related to you know refinery issues. Hopefully there's no existing pipeline disruptions but I think under a normal scenario where there's not a pipeline disruption or refinery disruption we think that Midland to Cushing differential ought to be close to its long term average which is roughly $1 a barrel.

Stuart Zimmer - Zimmer Partners

Right, okay that's helpful, second quick question is, I am curious if how much water infrastructure cap ex is baked into next year's guidance if you can share it.

Travis Stice

Yes, we've got about $25 million ballpark of infrastructure related expenditures next year and the bulk of that is for putting in these large frac prongs, putting in tank batteries that are of the size and scale that are capable of handling multiple horizontal wells, and so in a general sense most all of that $20 to $25 million next year will be spent on some form of handling water, either getting water available for fracing operations or getting rid of it once we flow it back.

Stuart Zimmer - Zimmer Partners

My last question is, do I think about the royalty interest, the number seems so robust to me, I am curious to hear your thoughts about whether there is anything strategically, just your thoughts around that business to get more full realization but seems to have been a very, very well priced for us, well priced purchases, royalty interest. And do you have any thoughts on how to get for the recognition or strategic thoughts around those that you’d be willing to share on this call?

Travis Stice

Well, Stuart I think you’re right in your observations on how we view what we’ve paid for that acquisition versus what we think it’s ultimately worth. And it’s really up to us to keep communicating with our shareholders how that value proposition is going to be realized over time. I think in a general sense it’s simply a cash flow stream that we can control the vast majority with the drilling on acres that we operate. And as we’ve talked before we kind of got a cash flow of $70 million to $80 million premised for next year, and that cash flow is going to grow as full scale horizon development occurs on not only our side of the piece that we operate but also what the non-operator is.

So at this point right now we’re providing the optics in our guidance by breaking out just the minerals piece as we go forward in time we’ll continue to try to push of our shareholders to understand the true value proposition of owning 15,000 acres of minerals in Midland County. We’re on drilling and what’s our most perspective area. So hopefully we can continue to push our story out that way.

Stuart Zimmer - Zimmer Partners

Thanks Travis. It’s great to hear your voice.

Travis Stice

Yes, I likewise Stuart, take care.

Operator

Our next question is from Jason Wangler from Wunderlich Securities. Your line is open.

Jason Wangler - Wunderlich Securities

Just one quick on sorry I jumped on little bit late. But the Longhorn pipeline, how you’re seeing that? Just wanted to see what you’re seeing, because obviously we’re just talking a little bit about the differentials. Are you seeing more barrels getting into that? Because I know you have kind of a pro rata share?

Travis Stice

Yes, again, that’s not a function of Diamondback’s decision other than that better up pricing proposition that I was talking about earlier. It’s really a function of when that pipeline can get up and run and get to its fully 225,000 barrel a day capacity. And as of a couple of days ago they weren’t at that capacity level yet and they still got some growing pains that they’re going through to try to get up to that full capacity.

And I know they must be bullish about the prospectivity of that pipeline because I think I saw an announcement where they’re even talking about expanding that line. So at the end of the day we get allocated our barrels and we make our decision based on what’s the best return to our shareholders on whether we go down that route or go back up to Cushing.

Jason Wangler - Wunderlich Securities

That’s helpful. Thanks guys.

Operator

Our next question is from Ipsit Mohanty from Canaccord. Your line is open.

Ipsit Mohanty - Canaccord Genuity

Thanks for taking my question. Most of my questions are answered but if I might push in one, which is, if you could break up the 2013 or the ’14 wells rather the ’14 wells that you want to drill in the short, medium or longer laterals, would you be comfortable doing it at this point or is it too early?

Travis Stice

Let’s see, for 2014, I guess, we’ve got kind of a preliminary breakout for 2014. And it looks like this it looks like about 36 5,000 foot laterals, about 23 7,500 foot laterals and about 11 10,000 foot laterals. Now, again the reason I kind of hesitate a little bit on providing that color is that with that many 5,000 foot laterals we’re still testing the operational efficiency of these 10,000 foot laterals and their corresponding EUR relative to short laterals. In the third quarter call here in a couple of weeks I’ll give you some more commentary on that. So there is a potential that those, that number of those 5,000 foot wells could go down and be offset with the longer laterals. But again sitting here in October and looking at 12 months of drilling for next year that’s kind of how we ever broke out.

Ipsit Mohanty - Canaccord Genuity

Understand that, appreciate it. When I looked at the fact that you talked about drilling about 35 to 40 wells in ’13 for 290-320 million, how would you, going forward in ’14, how would you split your CapEx your preliminary guided 450 midpoint, 450 million midpoint into D&C facility and non-op (Ph) if you might?

Travis Stice

Yes, I think we’re just talking with Stuart on the other question and we were talking about that facilities and infrastructure piece which is around $20 million to $25 million. We’ve got about 10 to 15 or so, for non-op expenditures in there. So that and the rest of that is going to be drill bit related.

Ipsit Mohanty - Canaccord Genuity

Understand that. I guess that’s about it. Thank you.

Travis Stice

You bet, thank you.

Operator

Our next question is from Jeffrey Connolly from Brean Capital. Your line is open.

Jeffrey Connolly - Brean Capital

Good morning guys. One quick one, can you give us any details on the Clearfork wells production and how that came on line versus the typical Wolfcamp well?

Travis Stice

Well I described it in the press release Jeffery it’s different in that, Wolfcamp B well typically starts cutting oil in the 0% to 10% of load recovery. This Clearfork well didn't start cutting oil till about 30% load recovery. The other thing I pointed out was that Wolfcamp B wells typically peak within the first 20 days to 30 days of production. And I pointed out that this Clearfork well had 30 days of inclining production and we're still kind of in that peak; those are still going up right now.

So I will give you in a couple of more weeks when we have our earnings call and we're focused more on than 2013 and we're today like on 2014 I will give you some more color at that point.

Operator

Thank you. We have no further questions; I will now like to turn the call over to Travis Stice for his further remarks.

Travis Stice

Thank you Mercy, if there is no further questions I just want to tell you how much I appreciate you guys taking the time, I know these events with the information that comes out after market close, puts a little strain on the system. But I appreciate you guy’s interest in Diamondback Energy and also appreciate your time on the call this morning. So you guys have Adam's contact information, and look forward to further conversations with you guys in the upcoming weeks. Thanks again and we'll talk soon.

Operator

Ladies and gentleman this does conclude today's conference. You may now disconnect. Thank you.

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