Good day, ladies and gentlemen, welcome to Diamondback Energy 2014 Guidance Conference Call. At this time, all participants are in the listening mode. Later, we'll conduct a question and answer session, and instructions will be given at that time. As a reminder, this call may be recorded. Now I'd like to introduce your host for today's conference, Adam Lawlis, Investor Relations. You may begin.
Thank you, Mercy. Good morning, 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 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, 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 million worth of acquisitions, raising capital to pay for them, and further ramping our production curve. We recently celebrated our first 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 with lots of investors here in Midland and on the road as part of group events and individual meetings, 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, I do understand dedication, commitment, skill, and a West Texas work ethic, 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 horizontal rig to arrive in early November and initiate our delineation program in some of the new 11,150 net acres we acquired at the end of the third quarter in Martin County. Depending on frack scheduling, results of these wells are expected in the first quarter of 2014.
Successful results this year have de-risked both Upton and Midland counties for the Wolfcamp B, in our opinion. Our recent successes in Andrews County have now added 2 additional development horizons in our portfolio, one in the Clear Fork 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've demonstrated this year, drilling these wells faster. 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 2024 CapEx of between $425 million 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 our recent minerals interest acquisition. We expect to drill between 65 and 75 gross horizontal wells in 2014, with gross costs expected to range between $6.9 million and $7.4 million for a 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 ad valorem 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 to the other. The reason we did this was to be more consistent with the way our peer group does, most of which who report this way.
Lease operating expenses for 2014 are now expected to be in the range of $6 per BOE to $7 per BOE, down from our prior adjusted guidance in 2013 of $9.50 per BOE to $11.50 per BOE, which represents a year-over-year reduction of approximately 35%. G&A per BOE should decline to between $2 a barrel to $3 a barrel, down from the prior range of $3 a barrel to $5 a barrel in 2013. 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. First, timely access to frack water. While we anticipate utilizing frack water late this year, we still need to be strategic in the location of our wells, ensuring timely completions once the drilling rig moves off locations. Secondly, interwell frack 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 frack operations and keep them shut in until we get the wells cleaned out and put online. While we don't expect any EUR impact, 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 POP times, or our 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 four 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. 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've 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, 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?
Ladies and gentlemen, if you have a question at this time, please press star then one on your touchtone telephone. If your question has been answered or you wish to remove yourself from the queue, please press the pound key. Our first question is from Ryan Oatman from SunTrust. Your line is open.
Hi, good morning.
Hey, 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 Cline, et cetera, Spraberry. 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 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 anxiously awaiting some competitors or some offset operators down in that area to deliver some more Wolfcamp A results. 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. Moving into Midland County. Midland County, I think we've communicated before, Ryan, about a middle Spraberry test that we hopefully in our upcoming call will give you some color on, as well as a second lower Spraberry well, although that well is not scheduled to be fracked until middle of November.
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. Depending on the results in the middle Spraberry, you might see some well there also. Specifically, we'll start next week, as a matter of fact, or maybe week after next, drilling our first well in Martin County. That'll be a Wolfcamp B well, and we'll drill a well or two in Martin County, and then we'll move the rig back into Andrews County and drill our second Wolfcamp B well. Specific to your question on the Clear Fork, as I outlined in my press release, the Clear Fork well is describing quite a bit different looking production profile than what we typically see in a Wolfcamp B well.
We need several more months on that to make sure we understand what that well production's going to look like in relation to the anticipated D&C cost that we require for a full-scale development program. That gives you a range, but in the second half of the year, 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, then I'll jump back in the queue. It does sound like you guys are perhaps a little bit more confident on Spraberry than I would've anticipated at this point. What provides that confidence for you guys at this point?
It's a good question, Ryan, really the most meaningful data we have is quite a bit of production history on the one well that's a mile and a half to the west of our Midland County acreage. That well's been online for how many months, Russell?
About six months.
Yeah, about six months of production, it's drawn a real nice production curve that's very equivalent to what we'd see in the Wolfcamp B. With that kind of production history and that proximity to our acreage, 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 third-party operator. It's just not online yet, we're pretty confident in that lower Spraberry.
Great. Thank you guys.
Our next question is from Pearce Hammond from Simmons & Company International. Your line is open.
Yeah, good morning, guys. Thanks for taking my questions.
You bet, Pearce.
Kind of first off, thinking towards full year 2014 production, I know you guys try to stray away from providing too much quarterly color, I was curious if you could provide any details pertaining to the production profile for the year or so. Right now, I'm kind of thinking that production likely increases in one Q and three Q more drastically than two Q, four Q. Could you confirm that or give any color for the general production profile in the year?
Pearce, since we're doubling production next year, and we've 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'm not 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 third quarter of 2014 is going to look like. 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.
Okay, great. Sounds good. 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 two 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's most prospective in the Cline. We're still a ways away from testing the Cline.
Okay, great. Last question from me. I'll jump back in. Sounds like drilling times continue to trend impressively lower, and by my math, it looks like horizontals are estimated to be drilled in an average of about 23 days in 2014. I'm 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 being more efficient in executing the operatorship of these wells?
Yeah. At the end of the day, it's all about execution, and execution implies efficiency. As Michael 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 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, 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 Mark Lear from Credit Suisse. Your line is open.
Hey, good morning, guys. First question just on the cost front, definitely making some good progress on drill and complete costs. 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?
Well, on the drilling side, Mark, a couple of our rigs that are capable of walking or being skidded efficiently, we've locked those in for one-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 sand side as you've seen frack fleets from gas basins migrate their way into the Permian. We don't have any specific long-term contract locked up with the sand service providers. At this point, we're still seeing real nice frack-on-frack competition for our services. Those are conversations we're having, but we don't have anything locked up yet.
Got you. Just on the development of the mineral interests, with the fifth rig coming, is there a potential to see more activity than two operated rigs in Midland County in 2014 to accelerate the value of those interests?
Yeah, 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. 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 running one 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. What are the communication levels between you guys? Are you guys working closely on developing that asset?
Absolutely. Yeah, 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 Gabe Daoud 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 or efficiency gains baked into that number? Do you see more upside to the cost savings as you get further into pad drilling?
Yeah, I could 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, Gabe, is 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. 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.
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 right now, and we're drilling our second well on our second two-well pad. Very quickly through the end of this year, you'll see us migrate to three-well pads. Probably, Russell, the wells next year, will they mostly be three-well pads?
Yeah, it really depends on the water situation. I'd say about half of them, the way we've got them scheduled right now, are three-well pads where we're confident we have enough water availability to not delay the fracs too long on the three-well pads. The other half we've got scheduled as two-well pads, but those could migrate to three-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%-35% of our initial fracs potentially could use recycled water. 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 flow back. We've kind of got to move up the learning curve on exactly how that's going to work. That would impact, as Russell pointed out, that would impact a two-well versus a three-well pad decision.
Okay. Then on the productivity side, with your guidance, what type curve is that? Can you remind us what EURs you're modeling for those type curves and is there any upside to that?
Well, we've given you a blended type or what we've done is we've got 1 blended type curve across our entire acreage base of about 600,000 BOEs on a two-stream basis.
For a 7,500 foot lateral.
For a 7,500 foot lateral. Thank you, Russell. That's a two-stream basis.
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. 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, Gabe.
Our next question is from Tim Rezvan from Stifel . 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. Then, if you can talk about what is baked into the EBITDA sensitivity table that you provided on 2014.
Yeah, I'll talk a little bit about GOR. In general, as we've talked about previously, the GORs in the southern area, Upton County, generally are higher than what we've seen as we've moved 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. 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 1,500 GOR after 6 to 9 months. There's some wells that remained at roughly 1,000 GOR over that same period.
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.
Tim, just on that EBITDA table, what I was just asking Tracy to calculate for us some sensitivities to EBITDA. 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 one year. It's just a way for us to sensitize on plus or minus $10 or $20 a barrel and 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 A bench wells from W&T Offshore 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.
Yeah. We're still modeling that same 600,000 barrel, two-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 two 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. 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 and to the right as you move forward in time.
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. Looks like both the productivity decline profile and the well cost is materially lower than what you've seen in the Wolfcamp B. Just wondering how the preliminary IRR for the Clear Fork stacks up against what you've seen for the Wolfcamp, and if there are any other zones in that portion of Andrews County that you may look to test horizontally.
Yeah. 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'll do in terms of total reserves. Of course, we need that to describe the future economics of investment. 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'll have to lower costs, even from the $6.5 million or $6.8 million range that we spent on that well. The guys already have their scalpels 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. Again, any specific numbers on that, still premature at this point.
Yeah, 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. I think there's a pretty good chance the Wolfcamp B will be economic on part of that acreage. There's another operator that has drilled but not completed or at least not reported any production results yet just to the north of our acreage there. We're watching that pretty closely as well.
Just to clarify, when we talk about Andrews County, we kind of bifurcated into a northeast portion where we've already drilled that Goodwell well. 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. The comments that Russell was just making are specific to that kind of western 9,000 acres that we have.
Got it. Very helpful. Thanks very much.
You bet.
Our next question is from Jeb Bachmann from Howard Weil. Your line is open.
Just had a couple quick questions for you. One, with the fall redetermination essentially concluded, get any kind of insight into what reserves could look like at the end of this year?
Yeah, Jeb, we're going through that process right now. We updated reserves September 1st and had almost 58 million barrels of reserves at September 1st, we've communicated that. Russell, he's got Ryder Scott engaged right now doing our end-of-year reserves.
Okay. The other one, with Longhorn, can you give us an update on how many volumes you're putting through there at this point?
Yeah. There was a total collapse for the month of October on the forecasted WTI and LLS. If you guys remember, that contract that we have is a better of pricing. For the month of October, when I say better of pricing, once you get to Midland tank farms, you can choose the better of pricing going to Midland-Cushing, or down to the Longhorn Pipeline. For the month of October, our deliveries were back into Midland-Cushing because economics supported that decision. In the last two or three days, we've got all the noise in the system on what's going on again with the MidCush differential and maybe making the economics more favorable for deliveries back into the Longhorn Pipeline for the month of November.
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, last one from me. Are 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. Certainly even on a much smaller scale, Jeb, swapping and coring up acreage, I think that's a good business practice as well, too. 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. 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.
Yeah, appreciate the commentary.
You bet. Thanks, Jeb.
The next question is from Richard Tullis from Capital One. Your line is open.
Thanks. Good morning, everyone.
Hey, Richard.
Travis, on the horizontal guidance well cost range for next year, $6.9 million-$7.4 million, 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?
Certainly, 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. There's a big piece of that or a big portion of that kind of range there, which is Upton County versus Midland County. Again, we're never satisfied on our D&C costs, we're continuing to tweak and push and congeal and try different things that are, one, more efficient in terms of cycle time, and of course, days or dollars. We're looking at changing things that can give you a nice cost advantage. It's a process, 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, 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-$7 per barrel. Right now, we're just trying to report like our peers are, that transportation third party is not included in that number.
How much are you expecting that to run next year, roughly?
It's the oil gathering.
Yeah. Richard, are you talking about oil gathering cost, or are you talking about gas gathering?
Well, combined basis, if you have it on a barrel BOE basis.
Yeah. When you look at oil, crude somewhere typically on truck, it's going to run you about $250 to $350 a barrel. Probably more biased towards the lower end. gas.
$0.25
$0.25 to $0.35 an Mcf for gas gathering.
Okay. Just lastly, where do you expect you'll be concentrating the vertical drilling in 2014?
Well, we're going to honor all of our lease obligations, 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. In addition to those obligation wells, again, vertical wells where we own the minerals in Midland County are highly economic, and you'll see us continue to drill a few wells there. 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 into the more expensive horizontal rigs. We want to keep our optionality open there 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.
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.
The deduct for the gas is very minimal.
All right. Thank you. Appreciate it.
Sure. Uh-huh.
Our next question is from Josh Jones from Robeco Boston Partners. Your line is open.
Hi, guys. Thanks for breaking out 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 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.
Okay.
Same wells, yeah. It's the same wells.
Okay, great. That's my only question. Thanks a lot.
You bet. Thanks, Josh.
Our next question is from Brett Riley from Zimmer Partners. Your line is open.
Hey, Travis. It's actually Stuart Zimmer. Before I ask my question.
Hey Stuart, how are you today?
I'm doing well, Travis, and you?
Yeah, blessed. Thank you. Good to hear from you.
Likewise. The first thing I wanted to say before I ask my question is, looking at this screen, the stock's $51. I realize 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, Stuart.
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, we think there's plenty of capacity on a normal basis. 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. It's generally related to refinery issues and hopefully, there's no existing pipeline disruptions. 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. My second quick question is, I'm curious how much water infrastructure CapEx is baked into next year's guidance, if you can share it.
Yeah, Stuart, we've got about $25 million ballpark of infrastructure-related expenditures next year. The bulk of that is for putting in these large frack ponds, putting in tank batteries that are of a size and scale that are capable of handling multiple horizontal wells. In a general sense, most all of that $20 million-$25 million next year will be spent on some form of handling water, either getting water available 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, 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 in what seems to have been a very well-priced, for us, well-priced purchase of those royalty interests. 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. It's really up to us to keep communicating with our shareholders how that value proposition's 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 it with the drilling on the acres that we operate. As we've talked before, we got a cash flow of $70 million-$80 million premised for next year. 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.
At this point right now, we're providing the optics and 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 owning 15,000 acres of minerals in Midland County, where I'm drilling in what's my most prospective area. Hopefully we can continue to push our story out that way.
Thanks, Travis. It's great to hear your voice.
Yeah, likewise, Stuart. 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. The Longhorn Pipeline, how you're seeing that, I just wanted to see what you're seeing, because obviously you were just talking a little bit about the differentials. Are you seeing more barrels getting into that? Because I know you have a pro rata share.
Yeah. 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. 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. 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.
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.
That's helpful. Thanks, guys.
Ladies and gentlemen, if you have a question at this time, please press star one. Our next question is from Ipsita Mohanty from Concord. Your line is open.
Guys, 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 2014 wells, rather the 14 wells that you want to drill into short, medium, or longer laterals, would you be comfortable doing it at this point, or is it too early?
Let's see. For 2014, I guess we've got a preliminary breakout for 2014. It looks like about 36 5,000-foot laterals, about 23 7,500-foot laterals, and about 11 10,000-foot laterals. Again, the reason I 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. There's a potential that the number of those 5,000-foot wells could go down and be offset with the longer laterals. Again, sitting here in October and looking at 12 months of drilling for next year, that's how we have it broke out.
Understand that. Appreciate it. When I looked at the fact that you talked about drilling about 35 to 40 wells in 2013 for $290 million-$320 million. Going forward in 2014, how would you split your CapEx, your preliminary guided $450 million midpoint into D&C facility and non-op, if you might?
Yeah, I think we were just talking to Stuart on the other question. We were talking about that facilities and infrastructure piece, which is around $20 million-$25 million.
Sure.
We've got about 10 to 15 or so for non-op expenditures in there.
Okay.
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 Brine Capital. Your line is open.
Hi. Good morning, guys.
Hey, 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. It's different in that a Wolfcamp B well typically starts cutting oil in the 0%-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 first 20-30 days of production, and I pointed out that this Clear Fork well had 30 days of inclining production. We're still in that "have we peaked, or is it still going up?" phase right now. 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 and also appreciate your time on the call this morning. You guys have Adam's contact information, and I 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.