Diamondback Energy Inc (FANG) 2014 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Diamondback Energy, second quarter earnings call. (Operator Instructions). I would now like to turn the conference over to Mr. Adam Lawlis, of Investor Relations. Sir, you may begin.

Thank you. Good morning, and welcome to Diamondback's Energy's second quarter conference call. Representing Diamondback today are, Travis Stice, CEO, Tracy Dick, CFO, and Russell Pantermuehl, VP 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 provides useful information for investors. We include reconciliations of those measures to GAAP in our Earnings Release. I will now turn the call over to Travis Stice.

Thank you, Adam. Welcome, everyone, and thank you all for listening to Diamondback's second quarter, 2014 conference call. Since our last call, we've issued an operations update that highlighted our pending lease hold acquisition primarily located in Midland and Glasscock Counties in the core of Northern Midland Basin, increased our four-year production guidance, successfully completed our southernmost test of the lower Spraberry in Upton County, and that we have placed on production the best horizontal well on a per-lateral foot basis in the Midland Basin.

Switching to second quarter results, we've continued our production growth by growing volumes over 170%, as compared to the second quarter of last year, and 32% from the prior quarter. We continue to expect to grow production by nearly 150% in 2014, as compared to 2013. This would mark the second consecutive year of nearly 150% production growth.

Our operating expenses continue to be within guidance, but with nearly 300 gross vertical wells acquired this year, we would expect cost to migrate towards the high end of guidance in the near term as we optimize these wells consistent with our prior practices.

Our low cost structure, combined with high oil cuts, continue to drive pure leading cash margins. We have several significant wells in various stages of development throughout our leasehold in the Midland Basin. We've drilled our first lower Spraberry well in Martin County, our first Cline well in Dawson county, and our first stacked Wolfcamp B, lower Spraberry well offset in our grid iron well in Midland county.

All are awaiting completion operations to begin in the next several weeks. Additionally, we're testing increased frac density in Midland country two adjacent 5,000 foot lateral wells using our standard 22 stage design on one, and an increased density frac design of 33 stages on the other. Expect further details on these well results in the upcoming quarters.

Finally, we have drilled and completed our first three well Wolfcamp B pad in Uptown County, realized savings of $1.25 million to $1.5, million bringing the total drilling to completion cost for all three wells to $15.3 million, or $5.1 million per well for a 5,000 foot lateral, our lowest cost to date. From spud to the first well to TD of the third well, operations took 38 days.

We're also currently drilling our first three well lower Spraberry pad on our Spanish trail lease in Midland County. As we continue to increase pad drilling, we expect some production lumpiness going forward as we conduct simultaneous operations on pad wells.

Adding a final point on execution, we have drilled a 10,000 foot lateral in Uptown County with a total measured depth of 19,350 feet in a record 14 days. We've now drilled over 80 horizontal wells in the Midland basin, and I'm pleased we're still setting records. As exciting as the growth story has been, and continues to be since our IPO, we're also excited about our growth in 2015 and beyond.

We're currently running two horizon rigs on our Spanish trail lease in Midland County, and one each in Andrews, Martin and Uptown counties. We expect to add a sixth horizontal rig in our existing acreage in the early first quarter of 2015 as well as a 7th horizontal rig on our recently acquired acreage. We also plan to add an 8th horizontal rig in the second half of 2015, and are contemplating adding a 9th in 2016.

Turning to well results, our Neal lower Spraberry well in Uptown County had a 30 day rate of nearly 750 BOEs a day from a 6,800 foot lateral on ESP, which is as good, or better, than our average Wolfcamp B wells in Uptown county setting up for additional years of drilling in this asset area. In Midland county, the Spanish trail northwest 25-1 lower Spraberry had a 30 day rate of 859 barrels a day from a 4,400 foot lateral on ESP. We've completed our second successful Clearfork shale well in Andrews county with a 30-day average rate of 473 BOEs a day from a 7,200 foot lateral, which is 15% to 20% higher than our initial well.

Well cost in this Clearfork will trend towards $6 million for 7,500 foot lateral enabling development costs to compete with other investment opportunities in our portfolio. Our second and third Wolfcamp B wells in northern Midland County posted positive results with a 30-day naturally flowing average of 684 BOEs a day, combined from an average lateral length 7,300 feet. These wells typically don't reach peak production until placed on artificial lift, which we will likely do this month. Early results from these two wells are at or above results seen from our initial well.

As a reminder, we report our well results on a two stream basis. While we continue to be active in the acquisition arena, we maintain our disciplined approach to valuating deals. I've consistently communicated that we will do only accretive deals and each acquisition is evaluated in relation to the stock price we would receive from financing each opportunity.

We firmly believe the greatest long-term shareholder value is created through consistent application of this discipline. When you couple this strategy with existing best in class execution and organic growth, you have a winning combination with Diamondback. With these comments complete, allow me to turn the call over to Tracy.

Thank you, Travis, and welcome everyone. I'll provide a quick overview of the financial highlights. Our net income for the second quarter was $27.8 million, or $0.54 per diluted share, versus net income of $14.5 million, or $0.36 per diluted share for the same period in 2013. Adjusted net income for the quarter included a loss on commodity derivatives of $11.1 million, and a loss of sale assets of $1.4 million.

Excluding the losses and the related income tax effect, our adjusted net income was $35.8 million, or $0.70 per diluted share. As previously reported, our production for the second quarter was approximately 17,836 BOE per day. These volumes generated revenues in the second quarter of $127 million, compared to $45 million for the same quarter in 2013.

Realized pricing for the second quarter before the effective hedges was $78.25, and with the effective hedges, it was $76.02. Our averaged realized oil price before hedges was $95.19, and with the effective hedges it was $92.20. Our EBITDA for the quarter was $103 million. Turning to cost, our LOE was $6.47 per BOE in the second quarter. Our general and administrative costs came in at $2.42 per BOE which includes non-cash stock-based compensation. Excluding stock-based compensation, G&A costs are $1.73 per BOE.

Our current hedge positions through 2015 have been laid out in our earnings release. We currently have about 40% of our estimated crude oil production hedged for the remainder of 2014. We continually asses our hedging opportunities, and we intend to continue to layer on additional hedges as our production grows.

In the second quarter of 2014, we generated $87 million of operating cash flow, and $85 million of discretionary cash flow, or $1.70, and $1.66 per diluted share, respectively. During the second quarter of 2014, we spent $124.1 million for drilling, completion and infrastructure.

Our liquidity position remains strong with approximately $37 million of cash on hand at June 30, 2014 and, we had drawn $46 million on our secured revolving credit facility which had a borrowing base of $350 million. We have subsequently reduced the outstanding balance to zero with a portion of the proceeds from our equity offering in July. I'll now turn will call back over to Travis for his closing remarks.

Thank you, Tracy. To summarize, we are again adding acreage in the core of the Northern Midland basin play, and we've recently increased production guidance for the second time this year. I am proud of our continued success in driving production growth, continued improvement executing on these complex well pads, and confirming new zones like the lower Spraberry in Upton County and Clearfork shale in Andrews county.

I believe we continue to deliver results and stockholder returns that are among the best in the Midland basin. Before I open the call for questions, I want to knowledge our employees and all they've accomplished in the first half of this year, and especially welcome those be employees that are new to Diamondback. On behalf of the board and employees at Diamondback Energy, I would like to thank you for your participation today. This concludes our prepared comments. Operator, please open the call to questions.

(Operator Instructions). Our first question is from Dave Kistler of Simmons and Company. You may begin.

Good morning, guys.

Good morning, Dave.

Real quickly, looking at the Martin County Wolfcamp B results and the Andrews County Clearfork results, can you talk a little bit about what that does for increasing development inventory on a longer term basis, and then where those might fall in terms of competing for capital as you go forward with the development?

Sure, Dave. And, thank you. I think in my prepared remarks I actually referenced those Wolfcamp B wells in Midland County and, of course, they're in Northern Martin County, so I apologize for that misspeak there. But, specifically, on those Martin County wells now. This is the second and third well and we're confirming that reserve target of between 650,000 and 700,000 barrels of oil equivalent. And that's going to place these in that 50% to 60% rate of return. So, it's really time for us to go to work there now. We've got three wells that are spread across the acreage that really confirms the viability of Wolfcamp B. So, I think it's logical to assume that we'll park a rig there and really focus on well to well efficiencies.

Now, moving over to the Clearfork shale in Andrews County. As I mentioned, those well costs are going to be around $6 million. I actually think, as we get in there with repeatable wells we can drive those costs down, but as it sits right now at the $6 million cost, that Clearfork shale is going to be somewhere between 30% and 40% rate of return and, probably 450,000 to 500,000 BOEs on an equivalent basis. And, while 30% to 40% rate of return is still a good well, it doesn't compare when you look at the plus 70% to almost 100% rate of return, including the effect of minerals [inaudible] in the County.

So, don't expect us to get out there and just start drilling one well right after another. But we've probably got about 50 to depending on spacing, maybe over 50 locations in the Clearfork shale. But, what I think is more logical is that you'll see us early next year, maybe late this year, move back into there and drill a two well pad and see if we can get some cost efficiencies on a two well pad and improve the economics there.

Great. I appreciate that. And then maybe switching to something a little bit different. One of your peers recently contracted for a bunch of water sourcing looking forward and talked about what their water needs will be for doing completions over the next ten years. Obviously a ways away, but can you talk a little bit about how you're handling the water situation right now and how that factors into the rig ramp that you've outlined for us getting to nine rigs by 2016?

Sure, Dave. What we've done is gone through each of our development areas and put in place what we call a water usage plan and that water usage plan is sort of the holistic approach to access, accumulation and disposal of water and we've really got to be effective in addressing each of those three things for each of our asset areas because once we have a real well laid out strategy for those three items, then we go in and put rigs on top of that.

And I think we're going to need all sources of stimulation water going forward whether it's existing fresh water, brackish, Santa Rosa water or recycled water in order to match our rig needs. It's an issue that we're paying real close attention to and trying to make sure it's consistent with our development strategy.

Great. Appreciate that. And just as long as we're on things that could be potential bottlenecks going forth, what are the other bottlenecks that concern you as you look at this aggregated portfolio and how you develop it going forward?

Well, in fact in the journal yesterday there was a nice article on sand and you're seeing more and more sand being used in our industry whether it's in the Eagleford or the Bakin and even in our own backyard where we're talking about increasing a 6 million pound job up to a 9 million pound job. To the extent that the industry migrates toward more and more sand in these horizontal wells, I think it's realistic that we've got to make sure that we've got the full supply chain figured out to make sure we and our service companies can access the sand at the time we need it. And then between sand and stimulation water, Dave, those are the two things that I think about.

Okay, great. I really appreciate the clarification. Great work, guys.

Thank you, Dave.

Thank you. Our next question comes from Gordon Douthat, of Wells Fargo. You may begin.

Thanks, good morning everybody. Just to dovetail off of that hast question, recognizing it's a bit earlier in the Permian delineation but there's been a lot of talk recently about evolution and completion designs and since you mentioned thoughts about increasing the [inaudible], how are you thinking about the evolution of your completion designs going forward?

Well, you know, Gordon, we've always continued to tweak our completion designs, always looking for ways to extract more oil out of this rock at a competitive price. Just as an aside, I know there's a lot of communication in the industry now about the effective slick water fracs.

We did our first horizontal well over two years ago down in Upton County as one of the first operators to start drilling horizontal wells in areas that have been predominantly drilled vertically. In that first horizontal well was slick water job and that's really when you've got over 80 of them completed and I think 79 of them have had slick water frac or applied to it. So, we continue to tweak sand per foot, water per foot, and in this most recent test we're going to try to hold as many variables constant as we can and just increase the number of stages across the lateral and that's that 22 stage going up to 33 stage and we're doing it on a sister well.

So, it's a pad well and one well will do it with 22 stages and then immediately over we'll do the next well with 33 stages and we think that will give us the best way to measure our improvement. It's about three million more pounds of sand. It's probably going to cost us about a $1 million but if we can pick up about 10,000 more barrels on a EUR it will probably pay for it. So, just look for us to provide more color as we go forward.

Okay. That's helpful. And then the question Travis, you mentioned in your comments, prepared remarks, that the rig allocation this year and as you add rigs next year I'm just wondering how you look into allocate those rigs across the various areas of your position?

We talked in our operations update a couple weeks ago about all the newly acquired acreage, I think we'll have a rig-and-a-half on that new acreage. So there's one-and-a-half rigs there. The other rigs, we're going to try to keep as many rigs as we can in our Spanish trail acreage, where Diamondback owns 93% of the minerals there now. We'll keep as many there. We'll keep one rig down in Uptown County. That's why I was excited about this new lower Spraberry well that gives us some good opportunities there. One of our competitors talked about a nice [inaudible] result down in Upton County as well which we haven't tested yet but obviously we'll pay close attention to there. Two, three Midland county, two, three in the northern blocks, one and a half in our newly acquired acreage and one or so down south will get you into that 7 and a half, 8 rig cadence.

Okay. And under that program, any preliminary thoughts on how the growth profile will trend?

Gordon, we've not signaled yet what our 2015 is going to be. I think we have a November call scheduled and that's when we'll have a more full-some discussion on 2015.

Okay. Thanks a lot, guys

Thank you, Gordon.

Thank you. Our next question is from Mike Kelly of Global Hunter Securities. You may begin.

Thanks, guys. Good morning. Travis, I was hoping you could talk about the opportunity set for Viper. You guys are really a first mover here with the mineral rights and an MLT. I was hoping you could talk about that and also curious if there's, beyond just being a 92% owner of venom, if there's any other added benefits that might not be obvious for FANG shareholders having that MLP in place? Thanks.

Thanks, Mike. You know, really, on the Viper side, the counsel's advised me to not be speaking too publicly about the status of our acquisitions. I can tell you in a general sense I've been really pleased with the amount of opportunities we've already had in the first 30 days and look forward to us providing more color on Viper in our upcoming calls. Specifically, again, we laid out the benefits to Diamondback pretty clearly during our IPO on Viper and I think you can just refer back to our Viper web page and you can see all of those details.

Okay. Fair enough. With Viper, is there the desire to go outside of the Permian and look for deals, does that ultimately mean, obviously very Midland focused, talk about ramping to nine rigs there. Does that ultimately lead you to want to take Diamondback outside of the Permian as well? Thank you.

You bet. Thanks, Mike. Specifically on Viper, as we talked about during the IPO, Viper is not constrained to the Midland basin. Obviously Diamondback is laser focused on execution and results in the Midland basin but the Viper level, you know, we're looking for accretive deals in all the other basins and the three kind of criteria we're looking for are basins that are actively being developed, oil-weighted basins, and the operator that's developing the minerals is a competent operator. So those are kind of the three broad focus items that we look at when we start screening deals for Viper.

Great. Thank you.

Thank you. Our next question is from Jason Wangler, of Wunderlich. You may begin

Good morning, guys. Just curious, you talked a lot about just different infrastructure and bottle necks. Just curious on the frac side as you're seeing that one. Obviously, you keep ramping the rig count and the plan is to ramp it further later this year and into next. What are you seeing as far as frac and as far as the contracts that you may have now or what you may have to look at as you go forward?

We're continuing to see some cross pressures from the pressure pumping side of the business. One of the things we're pleased with is that we've got two dedicated crews working for us right now and we've got roughly 40 or so wells to complete in the second half of this year and of those 40, roughly 30 of them will be on pads. The efficiencies that I talked about in my prepared remarks on the cost side, a lot of that comes on the stimulation side because you can set a crew right there on location and get two or three wells at one time. And so, I'm still trying to do everything I can to hold the line on cost and offset any increases in cost with improved efficiencies but I do think the tension is getting pretty tight now. We've got two dedicated crews, as I mentioned, and we're looking at maybe bringing a third dedicated crew on later this year, early in the first quarter.

One of the things the stimulation companies have communicated to us is that they really like working for Diamondback Energy because even though, like right now, we're just running five rigs, it's really equivalent to working for another company that's running eight or nine or ten rigs because of how fast we get these wells drilled. So, it really builds a nice inventory of wells that they can just move to very quickly. And that helps efficiency on their side and it helps on our cost side as well.

That's helpful. And then maybe just on the other side of it, as you get the oil out, I know that you're always focused on the take away. How are you seeing that market playing out? I think there was a little bit of differential issues somewhat in the quarter at one point with the refinery down but how are you seeing that playing out so far?

We know there's several large pipelines that are getting ready to either start filling, or will here shortly in the second half of this year, ultimately, that differential blowout that occurred a couple of weeks ago, a month ago, will come back into more traditional trading levels on the mid-cush differential. We're continuing to look at space that's available on these other pipelines that are leaving the Permian that are not going to Cushing, Oklahoma. And, just as a reminder, we've got 8,000 barrels a day gross that we've already committed and are moving right now on the Magellan Longhorn Pipeline and we receive LOS pricing for that. So, any incremental barrels above 8,000 barrel a day have been subjected to that mid-cush differential but at least we've got a little insurance for our stock holders on 8,000 barrels a day and we're looking to get more space on pipelines away from Cushing, Oklahoma to try to address that issue.

Great. I'll turn it back. Thank you.

Thank you. Our next question is from Jeffrey Connolly, with Mizuho Securities. You may begin.

Hi, guys. Thanks for taking the questions. You mentioned in the prepared remarks, production might be a little lumpy due to a lot of wells on pads. Can you give us any color on the completion schedule in the third and fourth quarter that might help us model production?

I was just talking with Jason there. I think we've got 40 wells that we have kind of scheduled between now and the end of the year and with two full dedicated crews right now, it ought to be in that 20ish wells per quarter. And again, we've got to have a little flexibility in that. But in order to get our annual guidance of wells completed, we need to be in that 20 wells per quarter, and that's where we've got laid it out right now.

All right. Thank you. That's helpful. I'll jump back in the queue. That's it for me.

Thanks, Jeff.

Thank you. Our next question comes from Willis Fitzpatrick, of Johnson Rice. You may begin.

Good morning. I know that you guys have hit on this a little bit, but, the majority of yours wells going forward should be at least on two well pads. Can you talk about any potential to accelerate or to make those three or even more wells per pad, and then also the availability of walking rigs where you are?

Yes. I'll answer those in reverse. The walking rigs, we try to have about half or three quarters of our rig fleet available that walk from well to well. For example, that three-well pad that we talked about down in Upton County, that rig was set up with walking feet and it moved from well to well in less than 8 hours. It typically takes you two-and-a-half days to move a rig and so and a three-well pad we moved them in 8 hours. About a half to three quarters of our rig fleet will be set up to do that. We also, because we still are geographically diverse, we need to have these rigs that are quick to move. A minimum number of loads and then can move from area-for-area so I can't have all of my rig fleet that are set up with feet because I need those fast-moving rigs. I'll look to Mike here real quick but out of the six rigs we'll have at the end of this year, Mike, how many of those will be set up with rig feet?

You'll have four with walking feet and you'll have two that are H&P rigs that are quick movers. And rig release to spud times, you're looking at two-and-a-half to 2.8 days for the H&P rigs, and a full pad with walking feet to move from pad-to-pad is about thee-and-a-half days from one of the big 1500 horse rigs with the feet. And then, as Travis mentioned, between wells, it's about 8 hours. Actually, rig release to spud will run you about .8 days on a pad where we can walk the rig from one to the next.

Thank you, Mike.

Yes.

Perfect. And then just one more sort of in the same vein. It seems like those cost savings per well were a little bit higher than expected, but should we think about that as generally shifting towards the lower end of the 9-6 to 7-4 completed well cost range or should we think of that as actually shifting that range?

Well, I wish I could tell you that it was shifting the range lower. What I think it may end up doing is offsetting some of the cost increases that we're seeing. So, at this point I don't want to signal that we're going to be lowering our range on per well completions.

That's perfect. Thank you so much.

Thank you. Our next question is from Joseph Rigor, of Ross Capital Partners. You may begin.

Good morning, guys. Most of my questions have been answered but just one key point is, with all the water supply issues that have been going on in many of the basins, how are you guys planning ahead for this with the additions of up to three more rigs over the next 18 months?

Well, Joe, I talked a few minutes ago about our water usage plan for each area and a little bit more detail on that, when it comes to access and accumulation, that means it's the number of fresh water, or brackish water, wells that we drilled in advance of the drilling rig arriving. And it also means we've got to size appropriately our storage frac pits for these types of waters. So, that's what we're doing. On the newly acquired acreage, we're rapidly coming up with a water usage plan that gets all the way to how prolific the brackish water wells are, how prolific the fresh water wells are and then what size frac ponds we need to accommodate our rig schedule. I think I had a previous question about increasing from two to three well pads, and ideally we would like to stay with three-well pads but some of that hinges on our ability to accumulate water, and also, lateral length as well, too. The longer lateral's also require obviously, more stimulation fluids. So, it take as little longer to accumulate that amount of stimulation fluid.

Okay. And do you guys have an idea of what kind of relative cost inflation impact the water supply situation has had on you guys over, say, the last 12 months?

Yeah. I wouldn't say that the water supply has impacted the cost. What I would say is that it's more on the pressure pumping side, the hydraulic horsepower charges that we're seeing are working their way up. Really, the only difference on the stimulation fluid is that when we drill these brackish wells, they're a couple of hundred thousand dollar as piece as opposed to a fresh water well which is $10,000 to $20,000 a piece.

Okay. Thank you.

Thank you. I would now like to turn the conference back over to Travis Stice for closing remarks.

Thank you. Thanks again to everyone participating today's call. If you have any questions, please reach out to us using the contact information provided.

Ladies and gentlemen, this concludes today's conference. Thank you for your participation, and have a wonderful day.