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 will conduct a question and answer session and instructions will be given at that time. As a reminder, this call may be recorded. I would now like to introduce your host for today's conference, Adam Lawlis, Investor Relations.
You may begin.
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 Panamuel, 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 will reference certain non GAAP financial measures, which we believe provide useful information for investors. We include reconciliations of those measures to GAAP in our filings with the SEC. I will now turn the call over to 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 few weeks, we've been quite busy since our last quarterly conference call, executing on roughly $600,000,000 worth of acquisitions, raising capital pay for them and further ramping our production curve. We recently celebrated our 1st year anniversary as a public company with a bang 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 the 4th horizontal rig to arrive in early November and initiate our delineation program in some of the new 11,100 and 50 net acres we acquired at the end of the Q3 in Martin County. Depending on frac schedule and the results of these wells are expected in the Q1 of 14.
Successful results this year have derisked both Upton and Midland Counties for the Wolfcamp B in our opinion and our recent successes in Andrews County have now added 2 additional development horizons in our portfolio, 1 in the Clear Fork and 1 in the Wolfcamp B Shale. Additionally, we expect a 5th rig to come on in the Q2 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've 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 100%. 2,500 to 3,000 barrels of this is expected to come from these recently acquired minerals that we bought.
This is based on a range of 24 CapEx of between $425,000,000 $475,000,000 nearly 48% more than what we anticipate spending in 2013. Naturally, this 20 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 our recent minerals interest acquisition. We expect to drill between 6575 gross horizontal wells in 2014, with gross cost expected to range between $6,900,000 $7,400,000 for 7,500 foot lateral horizontal, which is down over 10% from our 2013 guidance. It should be noted that while we traditionally speak about a 7,500 Foot Lateral, the average lateral length for 2014 is expected to average approximately 6,500 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 Advilarum as part of a production tax rather than as LOE. This works out to a shift of roughly 1.50 a barrel from one line dollars a barrel from one line to the other. And the reason we did this was to be more consistent with the way our peer group does most of which you 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 and A per BOE should decline to between $2 to $3 a barrel down from the prior range of $3 to $5 in 20.13. Given the substantial difference in cost structure and capital intensity, 2014 guidance for our mineral interests 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 leases 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. 1st, timely access to frac water. While we anticipate utilizing frac water late this year, we still need to be strategic in the locations of our wells ensuring timely completions the drilling rig moves off locations. Secondly, inter 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 forty eight is to shut in our offset wells prior to frac operations and keep them shut in until we get the wells cleaned out and put online.
Now while we don't expect any EUR impact, the short term production interruptions are possible. 3rd, 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 pop times are placed on production times will likely 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 4 wells that I hope to have online by the end of the year. If we do, our exit number will likely be higher. If we don't, you'll see that higher production in the month of January. And then fourthly, our 3rd 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've noticed that our infrastructure is lagging from our 3rd 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 2 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?
Our first question is from Ryan Ochman from SunTrust. Your line is open.
Hi, good morning. Hi, good morning, Ryan.
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 Clear Fork or Klein etcetera, 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?
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 if those vet out and prove to be economic, you might see us testing some Wolfcamp A down there in the second half of the year.
Now moving into Midland County. Midland County, I think we've communicated before, Ryan, about some Middle Spraberry well, although that well is not scheduled to be fracked in the second Lower Spraberry well, although that well is not scheduled to be fracked until middle of November. But I think next year it's reasonable to expect in Midland County for us to begin more of a development program in the 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'll be a Wolfcamp B well and we'll drill a well or 2 in Martin County and then we'll move the rig back into Andrews County and drill our 2nd Wolfcamp B well. And then specific to your question on the Clear Fork, as I outlined in my press release, this the Clear Fork well is describing quite a bit of different looking production profile than what we typically see in a Wolfcamp B well. So we need several more months on that to make sure we understand what that well production is going to look like in relation to the anticipated D and C 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, Ryan, Ryan, that's where we anticipate success in both the Martin and Southern Dawson County.
And that's, as I mentioned, some of the acceleration opportunities that I think our shareholders can expect from us given success.
Excellent. One follow-up for me and then I'll jump back in the queue. I mean, 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?
It's a good question, Ryan. 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? About 6 months. Yes, about 6 months of production and it's drawn a real nice production curve that's very equivalent to what we'd see in 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 Basin, gives us confidence to kind of offset that well which we've done through participating with the 3rd party operator. It's just not online yet. But we're pretty confident in that Lower Spraberry.
Great. Thank you, guys.
Our next question is from Kurt Friedman from Simmons and Company. Your line is open.
Yes. Good morning, guys. Thanks for taking my questions.
Good, Kurt.
So kind of first off, thinking towards full year 2014 production and 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. So right now I'm 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 in the year?
Yes, Kurt, since we're doubling production next year and we've got not quite a steady rig cadence, we're picking the 5th rig up in early Q2. We're not guiding towards any kind of quarterly numbers. And I'm not being trying to be resistant in doing that. It's just really when you look at some of these pad wells and our uncertainty and how quickly we can get pad wells online and producing, I'm afraid you'll hold me accountable to a quarterly number that here in the middle of
October is hard to predict what the Q3 of
2014 is going to look like. Of October is hard to predict what the Q3 of 2014 is going to look like. So we give you annual guidance and expect to be in range of our annual guidance and we'll provide color for each quarter as we have our quarterly conference calls.
Okay, great. Sounds good. And then could we potentially see you guys bring a rig into Ector County in 2014?
Likely not into Ector County in 2014. There may be a vertical well or 2 that we need to drill to hold lease obligations together there, but probably not until we move into a testing and development mode in the Cline. That's where we think the Ector County is most perspective in decline. So we're still a ways away from test and decline.
Okay, great. And then last question for me and I'll jump back in. But it sounds like drilling times continue to trend impressively lower. And by my math, it looks like horizontals are estimated to be drilled in the average of about 23 days in 2014. And so I'm curious if you could provide a little color as the primary credit for bringing these drill times lower in 2014.
I mean is it primarily attributable to pad drilling or just being more efficient
so 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 and of course cost to follow along very nicely with that. Pad Drilling in terms of cycle time does offer you a little bit when you're making rig moves in 4 to 12 hours versus rig moves in 3 to 7 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.
Great. Thanks guys.
Our next question is from Mike MacLeay from Credit Suisse. Your line is open.
Hey, good morning guys. First question on just on the cost front, definitely making some good progress on drilling complete costs. Have you been able to lock in and I know probably a good chunk of that's because of pad drilling, but have you been able to lock in services and
consumables that should
keep that from drifting higher in 2014?
Walking or being walking or being skidded efficiently. We've locked those in for 1 year contracts and those are just getting started. On the completion side, we've seen some nice reduction over the last 12 months or so on the stem side as you've seen frac fleets from gas basins migrate their way into the Permian. We don't have any specific long term contract locked up with the STAN service providers. But at this point, we're still seeing real nice frac on frac competition for our services.
So those are conversations we're having, but we don't have anything locked up yet.
Got you. And then just on the development of the mineral interests with the 5th rig coming, is there a potential to see more activity than 2 operated rigs in Midland County in 2014 to accelerate the value of that those interests?
Yes, absolutely Mark. We're looking at our water system, our water supply system right now for fracking 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 op, which is roughly half of that 15,000 acres, we've only assumed those non operators run-in 1 drilling rig. I think it's reasonable to expect given if they can replicate our kind of results, I'd expect them to accelerate activity as well. But that's not the way we've got it modeled.
Got you. And what are the communication levels between you guys? Are you guys working closely in developing that asset?
Absolutely. Yes, very closely. Those are great guys and we're proud that they're our business partners.
Great. Thanks a lot guys.
You bet, Mark. Thank you.
The next question is from Gordon Dutt from Wells Fargo. Your line is open.
Thanks. Good morning, everybody. Question again on the cost side for well costs. Are those reductions due solely to pad drilling? Or do you have other savings efficiency gains baked into that number?
And do you see more upside to the cost savings as you get further into the pad drilling?
Yes. I can tell you just like on the LOE expense side, we're never happy with cost. We always try to push the envelope. And the phrase that you've heard me use before, Gordon, is it's not a destination, it's a journey. And 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 honestly, I still expect both the production and the operations organization to drive more efficiencies in their day to day activities, which are also going to reduce cost as well.
Okay. And then on the wells that you are drilling on pads, how many wells per pad will you
be drilling? The first two pads that we've got, we're fracking our first two well pad And then probably
And then probably Russell, the wells next year, will they mostly be 3 well pads? Yes. It really depends on the water situation. I'd say about half of them the way we've got them scheduled right now are 3 well pads where we're confident we have enough water availability to not delay the fracs too long on the 3 well pads. And the other half, we've got scheduled as 2 well pads, but those could migrate to the 3 well pads as well as our water infrastructure develops.
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 Trail area and provide makeup water as much as 25% to 35 percent of our initial fracs potentially could use recycled water. So as that program gets up and running and we understand the true efficiencies of fracking with recycled water, we could move towards more and more or a higher and higher percentage of our total fluid being provided from flowback. But we've 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 a 2 well versus a 3 well pad decision.
Okay. And then on the productivity side with your guidance, what type curve is that? Can you remind us what the what EORs you're modeling for those type curves? And if there's any upside to that?
Well, we've given you a blended type curve. What we've done is we've got one blended type curve across our entire acreage base of about 600,000 BOEs on a 2 stream basis.
A 7,500 foot lateral.
For a 7,500 foot lateral. Thank you, Russell. Again, that's a 2 stream basis.
So that's really no change from our current type curve. Obviously, as we get these wells drilled in the northern area and see a 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 in the past.
Okay. Good update today. Thanks guys.
You bet. Thank you, Gordon.
Our next question is from Tim Rezvan from St. Ag. Your line is open.
Folks, kind of following up on that last question. I was wondering if you could talk about how GOR ratios are holding up in the wells that have been producing longer? And then if you can talk about what is baked into the EBITDA sensitivity table that you provided on 2014?
Yes. I'll talk a little bit about GOR. I mean, in general, as we talked about previously, 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 with about 1,000 GOR. What we've seen in Upton County is after about 6 to 9 months the average GOR is about 2,000 in Upton County.
It does vary a lot from well to well. We're still not real sure why there's the large variation that we're seeing. But again, you're up to about 2,000 GOR after 6 to 9 months in Upton County. In Midland County, the GORs have remained lower on average. We're at maybe a 1500 GOR after 6 to 9 months.
And there's some wells that remained at roughly 1,000 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 GUR basis. 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've just taken the midpoint of our production and we're not including any impact to hedges. Just the midpoint of that production table with those different commodity prices held flat for 1 year. So it's just a way for us to kind of sensitize on plus or minus $10 or $20 a barrel in the relative impact to EBITDA.
Okay. Thanks. I appreciate the color guys.
You bet, Tim. Thanks.
Next question is from Eli Kantor from Iberia Capital. Your line is open.
Hey, good morning guys. Hey Eli.
Question on wellhead economics in your recently acquired Martin and Dawson County acreage position. We've seen a highly prolific Wolfcamp B from Pioneer just to the south and a couple of 8 inch wells from WT to the west. Trying to get a sense of how we should be framing well productivity in that area that you recently acquired? And if there's going to be any kind of well cost differences that might also have an impact on rates of return?
Yes. We're still modeling that same 600,000 barrel 2 stream reserve number that Russell just quoted for even Martin County even in the face of some of those big Pioneer well results. We've not drilled a well up there a horizontal well yet. Typically, you'll see the first well or 2 that you move into an area. They'll 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 of wells. But again, all I look is I go back and look at the tracks my guys have left in the sand every time we've given them a repeatable drilling and completion opportunity and costs continue to move down to the right as you move forward in time. So while you may have a little bit higher cost initially, I fully expect them to be competitive with the rest of our development portfolio.
Okay. That's helpful. Second question is on your recently completed Clear Fork Horizontal. It looks like both the productivity decline profile and the well cost is materially lower than what you've seen in the Wolfcamp B. So wondering how the preliminary IRR for the Clear Fork stacks up against what you've seen for the Wolfcamp?
If there are any other zones in that portion of Andrews County that you may look to test horizontally?
Yes. I can't give you a project EUR or a project IRR yet because we just truthfully 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 to describe the future economics of investment. So that's why, Eli, we said we're going to wait about 6 months before we come out and start talking about our next development scenario. We do know that in order to be competitive, we'll have to lower costs even from the $6,500,000 or $6,800,000 range that we spent on that well.
And the guys already have their scaffolds out and are starting to carve away cost right now for what a full scale development program would look like and associated costs for Clear Fork development. But again, any specific numbers on that still premature at this point.
Yes. And just to comment on potential other zones in that area. The Wolfcamp B Shale is present in that area. It is getting a little thinner than some of our other acreage, but we've actually been pleasantly surprised by some Wolfcamp B wells in Ector County where the shale is pretty thin. So I think there's a pretty good chance that the Wolfcamp B will be economic on part of that acreage and there's 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. And just to clarify, when we talk about Andrews County, we kind of bifurcated into a northeast portion where we've already drilled that good UL well. So that's all good Wolfcamp B country. The specific area we're talking about now is the portion that's more in Central Andrews County and a little bit westward that's approaching the edge of the Central Basin platform.
So the comments that Russell was just making are specific to that kind of Western 9000 Acres that we have.
Got it. Very helpful. Thanks very much.
You bet.
Our next question is from Jaiv Beckman from Howard Will. Your line is open.
Just had a couple of quick questions for you. 1, with the fall redetermination essentially concluded, get any kind of insight into what reserves could look like at the end of this year?
Yes, Jeb. We're going through that process right now. We updated reserves September 1 and had almost 58,000,000 barrels of reserves at September 1 and we've communicated that. And then Russell's he's got Ryder Scott engaged right now doing our end of year reserves.
Okay. And then the other one on with Longhorn. Can you give us an update on how many volumes you're putting through there at this point?
Yes. There was a total collapse for the month of October on the forecasted WTI and LLS. And if you guys remember that contract that we have is a better of going to Midland Cushing or down to the Longhorn Pipeline. So for the month of October, our deliveries were back in the Midland Cushing because economics supported that decision. Now in the last 2 or 3 days, we've got all the noise in the system on what's going on again with the Mid Cush differential and maybe making the economics more favorable for deliveries back into the Longhorn pipeline for the month of November.
But we've got our spreadsheet wizards working on that right now to figure out what's the best economic return when we get those barrels to the Midland Tank Farm.
Okay. And last one for me. You guys looking at any opportunities to maybe core up acreage positions by swapping with other guys where we might not have the large contiguous positions and see those kinds of opportunities out there?
Yeah. What I consistently tell my shareholders that it's reasonable to expect any kind of large transaction or small transaction that Diamondback Energy should be involved in those conversations. And certainly even on the much smaller scale Jeb in swapping and corn up acreage, I think that's a good business practice as well too. And yes, we're very active in that as well too. It's just at this point, it's probably not material to our 65,000 net acres, but it's very material in terms of an individual well that gets drilled.
So rather than walking you through each one of the individual wells and what acreage swaps we might or might not have done, I tend to focus you on more the macro acquisition opportunities. Yes. Appreciate the commentary. You bet. Thanks, Jeb.
The next question is from Richard Collins from Capital One. Your line is open.
Thanks. Good morning, everyone. Hey, Richard. Travis, on the horizontal guidance well cost range next year $6,900,000 to $7,400,000 Is the low end of 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?
Well, certainly depth as you depth is a function of cost. And our Upton County wells in general are less expensive than our Midland County wells because we're gaining about 1,000 feet of depth as you move from Upton County into Midland County. So there's a big piece of that or a big portion of that kind of range there which is Upton County versus Midland County. But again we're never satisfied on our D and C cost. And so we're continuing to tweak and push and cajole and try different things that are 1 more efficiency and more efficient in terms of cycle time and of course days or dollars.
We're looking to change things that can 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. But 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.
Okay. Are you including gathering and transportation in your LOE guidance for next year, Travis?
Not in that $6 to $7 per barrel. We've got it. We just right now we're just trying to report like our peers are. So that transportation 3rd party is not included in that number.
And how much do you expect in that to run next year roughly?
It's the oil gathering?
Yes. I mean, Rich, are you talking about oil gathering cost? Or are you talking about gas gathering?
Well, on a combined basis if you have it on a barrel BOE basis.
Yes. When you look at oil, crude somewhere typically on truck, it's going to run you about $2.50 to $3.50 a barrel, probably more biased towards the lower end. And gas we typically $0.25 to $0.35 on Mcf for gas gathering.
Okay. And then just lastly, where do you expect you'll be concentrating the vertical drilling in 2014?
Well, we certainly got we're certainly 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 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 intermediate on these horizontals before we move in the more expensive horizontal rigs. So we want to keep our optionality open there to the event we in the event we can prove that up to be an efficient way to reduce costs.
Well, good. Thanks a bunch. I appreciate it.
You bet, Richard.
Hey, Richard.
Yes.
I 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.
I see.
You would see. Okay. So the deduct for the gas is very minimal.
All right. Thank you. Appreciate
it. Sure.
Our next question is from Josh Jones from Robocop Boston Partners. Your line is open.
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, said you're using a kind of a blended average across your acreage base for your Wolfcamp B type curves to form your guidance. Are you using that same 600,000 EUR for the mineral rights production? Or are you using something more specific to that
area? It's the same curve all the way across. Same wells, yes. It's the same wells.
Okay. That's my only question. Thanks a lot.
You bet. Thanks, Josh.
Our next question is from Brett Riley from Zima Partners. Your line is open.
Hey, Travis. It's actually Stuart Zimmer. Before I ask the question Stuart, how
are you today?
I'm doing well, Travis. And you?
Yes, blessed. Thank you. Good to hear from you.
Likewise. So the first thing I wanted to say before I ask my question is looking at the screen the stock $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.
Thank you, sir.
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?
Right now, I mean, we think there's plenty of capacity on a normal basis. So it's really I mean, right now, as Travis mentioned earlier, just in the last few days here, we've seen a big deduct for the Midland to Cushing differentials. But it's generally related to refinery issues and 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 a buck a barrel.
Right. Okay. That's helpful. A second quick question is, I'm curious if how much water infrastructure CapEx is baked into next year's guidance, if you can share it?
Yes. We've got Stuart, we've got about $25,000,000 $25,000,000 ballpark of infrastructure related expenditures next year and the bulk of that is for putting in these large frac ponds, 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 $20,000,000 to $25,000,000 next year will be spent on some form of handling water either getting water available for fracking operations or getting rid of it. For fracking operations or getting rid of it once we flow it back.
Right. My last question is, when I think about the royalty interest, I mean the numbers seem so robust to me. I'm curious to hear your thoughts about whether there's anything strategically just your thoughts around that business to get more full realization and what seems to have been a very, very well priced for us, well priced purchase of those royalty interests. And do you have any thoughts on how to get further recognition or strategic thoughts around those that you'd be willing to share on this call?
Well, Stuart, I think you're right in your observations on how we view what we 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 of the drilling on the acreage that we operate. And as we've talked before, we kind of got a cash flow of $70,000,000 to $80,000,000 premised for next year. And that cash flow is going to grow as full scale horizontal 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. And as we go forward in time, we'll continue to try to push for our shareholders to understand the true value proposition of to understand the true value proposition of owning 15,000 acres of minerals in the Midland County where I'm drilling in what's my most prospective area. So hopefully we can continue to push our story out that way.
Thanks, Travis. It's great to hear your voice.
Yeah. Likewise, Drew. Take care.
Our next question is from Jason Wangler from Wunderlich Securities. Your line is open.
Hey, guys. Just one quick one. I'm sorry, I jumped on a little bit late. But the Longhorn Pipeline, how you're seeing that? I just wanted to see what you're seeing, because obviously you'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.
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 running and get to its full 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.
Now 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 the decision. 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.
That's helpful. Thanks guys.
Our Our next question is from Heapsik Mahanty from Canaccord. Your line is open.
Guys, thanks for taking my question. Most of my questions are answered, but if I may 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 at this point? Or is it too early?
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, 5000 foot laterals, about 23, 7,500 foot laterals and about 11, 10000 foot laterals. Now again 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 Q3 call here in a couple of weeks. I'll give you some more commentary on that.
So there's a potential that those the number of those 5,000 foot wells could go down and be offset with the longer laterals. So but again sitting here in October and looking at 12 months of drilling for next year that's kind of how we have it broke out.
Understand that. Appreciate it. When I looked at the fact that you talked about drilling about 5 to 40 wells in 13 for $290,000,000 $320,000,000 How would you going forward in 20 14, how would you split your CapEx, your preliminary guided $450,000,000 midpoint into D and C facility and non op if you might?
Yeah. I think we were just talking to Stuart on the other question and we were talking about that facilities and infrastructure piece, which is around $20,000,000 $25,000,000 and we've got about $10,000,000 to $15,000,000 or so for non op expenditures in there. So that and the rest of that's going to be drill bit related.
Understand that. I guess that's about it. Thank you.
You bet. Thank you.
Our next question is from Jeffrey Connelly from Brent Capital. Your line is open.
Hi. Good morning, guys. Hi, good morning Jeff.
One quick one. Can you give us any details on the Clear Fork wells production and how that came online versus the typical Wolfcamp well?
Well, I described it for you in our press release, Jeffrey. And it's different in that it's that a Wolfcamp B well typically starts cutting oil in the 0% to 10% of load recovery. This Clear Fork 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 1st 20 to 30 days of production. And I pointed out that this Clear Fork well had 30 days of inclining production.
And we're still kind of in that have we peaked or is it still going up phase right now. So I'll give you in a couple of more weeks when we have our earnings call and we're focused more on the 2013 than we are today like on 2014. I'll give you some more color at that point.
All right. Thanks. That's helpful.
Thank you. We have no further questions. I would now like to turn the call over to Travis Stice, CEO for further remarks.
Great. Thank you, Mercy. If there's no further questions, I just want to tell you how much I appreciate you guys taking the time. I know these events with information that comes out after market close puts a little strain on the system. But I appreciate you guys' interest in Diamondback Energy 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.
Ladies and gentlemen, this does conclude today's conference. You may now disconnect. Thank you.