Good day, ladies and gentlemen, and welcome to the Diamondback Energy First Quarter Earnings 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, today's program is being recorded. I would now like to introduce your host for today's program, Adam Baulis, Investor Relations.
Please go ahead, sir.
Thank you. Good morning, and welcome to Diamondback Energy's Q1 conference call. Again, my name is Adam Wallace, and I manage Investor Relations at Diamondback. Representing Diamondback today are Travis Stice, CEO Tracy Dick, CFO and Russell Panamril, 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 earnings release. I will now turn the call over to Travis Stice.
Thanks, Adam. Welcome, everyone, and thank all of you for listening in to Diamondback's Q1 2013 conference call. When discussing quarter over quarter comparisons, I'll be referring to the pro form a numbers for 2012, which give effect to our acquisitions as if they had occurred at the beginning of 2012. Over the past few months, Diamondback has continued to make progress in expanding on our horizontal drilling with 15 horizontal Wolfcamp B wells in various stages of development with what we feel are very exciting results. Our acreage lies right in the heart of this emerging play in the Midland Basin, and we feel like we're leading the way in delivering horizontal well results to our stockholders.
We've achieved an average 24 hour IP rate from 8 horizontal wells of 836 BOEs per day, of which 87% is oil from lateral lengths that average just slightly less than 5,000 feet, with 2 marquee wells testing at rates exceeding 1,000 barrels a day equivalent. The average 30 day rate for this same set of wells was over 600 BOEs per day. We're currently running 2 horizontal rigs, 1 in Upton and 1 in Midland County. Operationally, we've been active on several fronts, including ramping production and increasing efficiencies in an effort to achieve best in basin margins. Now looking at our results.
We're pleased with our production for the Q1 of 2013, which averaged 4,800 BOEs per day. The production ramp we expected from horizontal wells was evident as we exited the quarter at 5,500 BOEs per day. This is almost a 1,000 barrel a day increase when compared to 2012 exit rate of 4,500 BOEs a day. Now looking just at the oil component of the production stream, which accounts for 87% of our revenue, our first quarter exit rate for oil was up 38% compared to the 4th quarter, reflecting the high percentage of oil we've seen from these horizontal wells. Although the production ramp we developed last year for 2013 started roughly a month later than planned due to some production delays associated with our choice to gather data in a microseismic fashion and an operational delay on our first horizontal well, both the vertical and horizontal wells are meeting or exceeding our expectations.
Although the
numbers are not finalized for April yet, our production is around for the month 6,000 BOEs per day. And when I'm looking at the 1st few days of May, we're over 6,500 BOEs per day. This production ramp gives us confidence in delivering on our growth profile for 2013. Our operations team continues to improve performance to a level we believe is among the best in the Midland Basin. We had a 7,500 foot lateral in Upton County that reached TD in 16.5 days and a 4,500 foot well also in Upton County that reached TD in 13.5 days.
Our first quarter well cost for short laterals was $6,000,000 which is a 22% improvement over the Q4 of last year and our longer laterals of 7,500 feet averaged $7,800,000 for this quarter, which is again a 10% improvement over the Q4 of last year. Expect our well cost to migrate to the low end of our guidance of between $7,500,000 to $8,500,000 for these 7,500 foot lateral wells with further upside possible as we continue to optimize our completions. We also saw improvements again this quarter on our vertical program with spud to TD times decreasing by 18% to average 9 days. 3 of these wells reach TD in less than 8 days. We plan to begin testing the horizontal potential of our Andrews County leasehold during the Q3 of 2013 with wells planned both in the Wolfcamp B and in the Clear Fork Shale intervals.
Acreage values continue to increase as seen in the recent results of the University Lands Auction with offset acreage selling at over $6,500 per acre, likely driven we feel by horizontal prospectivity. This acreage pricing reflects positively for our 18,000 net acres in Andrews County. Now as I said earlier, we've got over we've got 15 horizontal wells in various stages of development. Referring to our earnings release from yesterday, you can see all the details associated with each of these horizontal wells. The 2 best wells are from the Midland County ST 2501H that peaked at 10.54 BOEs per day and the Upton County Neal 8 2H that peaked at 11.34 BOEs per day.
The Spanish Trail 2501H result is particularly encouraging since that's a short lateral of only about 4,451 feet. Now we're currently flowing back our first 7,500 foot lateral well in Midland County and it's just now starting to produce oil. When we evaluate our performance using the early time data for these horizontal wells, we are at or above our type curve projections. We're also encouraged by the strong results recently delivered by the Pioneer operated horizontal Wolfcamp B Hut well, which is located within 18 miles of our acreage in Midland County. We believe our activity combined with industry results has essentially de risked our leasehold in Midland and Upton Counties in the Wolfcamp B target zone.
Our first quarter LOE per BOE has decreased 20% to $12.61 per BOE when compared to the Q4 of 2012. This is being driven lower as we place more water into pipelines and less into truck carriers. While we're just beginning to benefit from infrastructure expenditures, we believe we're well on our way of our goal to reduce our total LOE to between $11 $13 by the end of this year. This effort to reduce cost will continue and expect me to report on our efforts each call. We also expect to further improve our oil price realizations through our connection to the Magellan Longhorn pipeline.
Although our production is currently prorated, in May, we expect to move an estimated 14.22 gross barrels of oil per day into the pipeline and we anticipate monthly increases in deliveries until at full pipeline capacity in late 3Q. At that point, we expect to be delivering 8,000 gross barrels per day through the remainder of the 5 year term. If this pipeline had been operational during the Q1 of 2013, we would have increased our oil price realizations by $21 a barrel. Now while we've seen this spread contract recently between LLS and WTI, we feel that having 1,000 barrels a day of non interruptible transportation out of the Permian is a big advantage for our shareholders, not only in the physical movement of oil, but also improved price realizations if the basis differential widens again like we saw during the Q1. And lastly, we've added we've continued to add liquidity to the balance sheet as our borrowing base has increased 33% to $180,000,000 With these comments complete, allow me to turn the call over to Tracy.
Thanks, Travis. Our net income for the quarter was $5,400,000 or 0 point 15 dollars per share. Net income for the period included an unrealized gain on commodity derivatives of 1,500,000 dollars Excluding the unrealized gain and the related income tax effect, adjusted net income was $4,400,000 or $0.12 per diluted share. Revenues for the Q1 totaled $28,900,000 as compared to Q4 of 2012 of 27,000,000 dollars Our sequential quarter over quarter $2,000,000 increase is supported by higher price realizations and increased production volumes. The net dollar effect of the increases in both price and production was $900,000 $1,100,000 respectively.
Our average realized price before the effect of hedges was $67.09 per BOE compared to $63.96 per BOE for the prior quarter. Our average realized price, including the effect of hedges, was $63.51 per BOE compared to $61.43 per BOE for the prior quarter. EBITDA for the quarter was $20,300,000 Our LOE was $12.61 per BOE as compared to $15.68 per BOE in the Q4 of 'twelve. Our LOE per BOE is in with our LOE guidance of between $11 $13 Our general and administrative costs came in at $5.73 per BOE. We expect unit costs to decline with higher volumes and trend toward our guidance of $3 to $5 per BOE in the 2nd quarter.
Our production tax and DD and A are both in line with guidance. At quarter's end, we had $36,500,000 in debt, leaving $104,000,000 of liquidity in the form of cash on hand and additional borrowing capacity. With our borrowing base redetermination recently completed and increased to $180,000,000 our liquidity has increased by an additional $45,000,000 Our current debt outstanding today is 44,000,000 dollars Our debt to capitalization ratio was 7% at the end of the quarter. In the 1st 3 months of 2013, we generated $17,000,000 of cash flow or $0.46 a share. We spent 74,100,000 dollars This includes approximately $15,000,000 for drilling and completion, dollars 18,600,000 to Gulfport for the final settlement of a post closing cash adjustment in connection with the acquisition of their properties and the remainder on infrastructure, facilities and acquisitions.
I'll now turn the call back over to Travis for his closing remarks.
Thanks, Tracy. To summarize and like I said in my opening comments, we're pleased with our performance during the Q1 this year as we've migrated the company to increase our horizontal development and we're well on our way to delivering our volume growth projections. We've ramped our production through these results off of these horizontal wells. Our expenses are down. We're executing at or near the top in our anticipated drilling results.
Development costs on both horizontal and vertical wells are trending down, and we've added liquidity with our increased borrowing base. We feel like we have the right assets and the right people to deliver on a very exciting 2013. Now before I open the call to questions, please note that we filed an S-one registration statement with the SEC on April 11th in conjunction with a proposed follow on equity offering to raise additional equity to accelerate horizontal activity. We're still in the filing process with the SEC and I may be precluded from answering some of your questions. On behalf of the Board and employees of Diamondback Energy, I'd like to thank you for your participation today.
This concludes our prepared comments. Operator, please open the call to questions.
Our first question comes from the line of Ryan O'Bond from SunTrust. Your question please.
Hi, good morning Travis. Hi, good morning Ryan.
You mentioned you feel that Midland and Upton County acreage is substantially derisked. Can you just remind us how much acreage you have in those two counties?
Yes. Ryan, good question. In Midland, we've got about 10,000 acres. And in Upton County, we also have about 10,000 acres, and those are net acres.
Okay, great. And then shifting to Andrews County, what makes the Clear Fork the attractive target there versus say the Wolfcamp B?
Well, if you noticed when I said Andrews County, we're testing both. We're testing the Wolfcamp B sort of on the eastern edge of Andrews County where we think the shale thickness and offset activity has really given us some excitement to test that zone. And as we move a little further west in Andrews County where we've got a large acreage block, the Clear Fork Shale looks really exciting. We've done a lot of science on the Clear Fork Dale, the Clear Fork there including a vertical well test in the Clear Fork shale only, which tested at about 50 barrels a day. And we've also done some sidewalk core analysis and some advanced shale logging, all of which indicate that this is a really prospective shale zone force.
And then we're also watching offset operator activity as well as they test the Clear Fork shale. And as you move kind of off the shelf's edge into where our acreage is that Clear Fork gets deeper and thicker, which we think are both accretive to our acreage position.
Great. Thank you for that color there. And then curious what you can tell us on this Kindra well, which is currently flowing back. Did you have any issues there? Do you feel like you had an effective stimulation, state and zone, etcetera, etcetera?
Yes. That well was effectively stimulated as standard. It was our standard completion technique with roughly £300,000 of sand per stage. It's a sort of a long lateral. You can see the lateral length in our earnings release and it was drilled and completed without incident.
And we've had it on now for about a week and a half. It's about 15% load recovery and it's increasing oil every day. I think last night it made about 5 20 barrels of oil and it's still flowing up casing.
Okay, great. And that 520, how does that compare to say what you saw earlier in the Neil A or Neil B wells?
It's right in line, Ron. It's just it's tracking almost exactly.
Okay. Very good. Appreciate all that. I'll hop back in the queue.
Great. Thanks, Ryan.
Thanks.
Thank you. Our next question comes from the line of Gordon Douthat from Wells Fargo. Your question, please.
Good morning guys. Good morning. Travis, you mentioned you're having success getting well costs down and you're tracking towards the low end of your targets or you hope to be there by year end. Can you talk about some of the things that you're seeing on both the drilling and completion side that's allowing you to realize these reductions?
Yes. Specifically on the drilling side, what the drilling organization is doing is with the extreme focus on just almost every connection on the drill pipe they've improved efficiency. So they can tell you how many minutes it takes to make a connection. And so what that really translates to is a behavior that actually cuts days out of the total execution. So when I talk about a 16.5 day well that's out there to 7,500 feet, it's through a lot of hard work and diligence on the drilling side of the organization.
And then on the completion side, what these guys are doing is continue to optimize the completion methodology without sacrificing EUR or initial production rate. Specifically what we're doing is we've tested with kind of cutting out the same cutting out stages, but still pumping the same amount of proppant and fluid. And what that really does is it cuts time out of the completion. And when you cut time out of the completion, you also cut dollars. So when you combine all that together with the extreme focus on costs that we have and on our execution, you start seeing the results that we're seeing right now with quarter over quarter improvements.
Okay. That's good color. And can you get into maybe more specifics about your standard completion? I know you mentioned £300 of proppant per stage. But as you complete these wells both on the long and the short laterals, how do you look to space the frac stages?
And what type of completion recipe are you fracking these wells with?
Sure. Our current recipe is, like I said, about £300,000 per stage. And the kind of the interstage distance is about 250 feet. And we're using slickwater transport fluid and fortyseventy sand, white sand.
Okay. And then just last question for me. You mentioned the B bench looks to be derisked. When do you think you'll outside of Andrews that are in actually I should say in Midland and Upton, when do you think you'll test other benches the A or maybe the other benches?
Well, we ask ourselves that question almost every day. And what's hard for us to try to justify is when we're bringing on wells that are making 1,000 barrels a day to go test other benches. And really what I think we're doing right now is there's a lot of industry activity that's been announced out there where other benches are being tested. And so I'm going to continue to try to keep my drill bit in the Wolfcamp B and I'll follow very closely with the industry reports in these other benches and we'll be able to respond very quickly if somebody has comes up with a zone that's better than a Wolfcamp B. But right now, I'm going try to keep my drill bit in the Wolfcamp B there in Midland County.
All right. Makes sense. Thank you.
Thank you. Our next question comes from the line of Jason Wangler from Weddellux Securities. Your question please.
Good morning. Just one quick one on the CapEx side. The $18,600,000 to Gulfport, assuming obviously that's the final settlement there. Is there any other payments like that that are expected? Or I assume that's it.
And then is that baked into the current CapEx guidance? Just want to make sure that I'm going to account for that right.
Sure. No further payments and yes it's backed into our CapEx guidance. Perfect. That's all I had. Thank you.
Thank you. Our next question comes from the line of Jeb Bachman from Howard Weil. Your question please.
Going back to Travis, going back to the your completion methods, can you tell us or talk to us about the differences that you're seeing between the submersible pumps and the gas lifts on these horizontal Wolfcamp wells? Sure. When we originally started with the gas lift, we did that, 1, to sort of minimize operational risk and 2, we were looking at it to save an extra rig up. And a rig up on one of these top wells typically runs around $25,000 to $30,000 And we avoided that by going to gas lift because we're drilling out with stick pipe, that's our standard method right now. And the reason we're drilling out with stick pipe is because as we test these longer 10,000 foot laterals, we know we can't use coil to clean out that whole lateral.
So we're building our game up to drill out these wells with the stick pipe, which is what we're doing. So what we do when we already have a rig on there since we're using stick pipe, we'll just run-in there with tubing with gas lift valves and let the well start producing the well up the tubing. If I just let the well flow, I have to wait for it to flow and then deplete on flowback and then rig up again where that incremental cost comes in and put a sub pump on there. Now having said all of that, what we really did was we set up 2 test wells where we could kind of measure them side by side the 25.1H which is on sub pump and the 25.2H which is on gas lift. And what we're looking at is we're looking at the total cume production under the 1st 90 day period and kind of get a gauge on whether or not the sub pumps are kind of differentially better than the gas lift.
But I tell you what we're seeing right now, these early rates, it just appears that the sub pumps are capable of moving more fluid early on, when I say early on, probably in the 1st 30 days than the gas lift wells are. So our operations program is migrating towards more sub pumps. Great. Thanks. And then one other clarification for me, Travis, on you mentioned the 38% exit rate for oil increase over 1Q 'thirteen over 4Q 'twelve.
Was that a 4Q 'twelve exit rate or the 4Q 'twelve average? That was 4Q 'twelve exit rate. Okay, great. Thanks guys.
Thank you. Our next question comes from the line of John Friedman from Raymond James. Your question please.
Good morning guys. On the your vertical, the plans for the 35 to 40 gross vertical wells that's currently guided to, What spud to TD time does that assume?
I think for your planning purposes, kind of 2 wells per month on these vertical wells. We're averaging, like I said, in the Q1 spud at TD of about 9 days. It gives us a day or so to run casing and a couple of days to move the rig. So just from a planning purpose, I think you can go about 2 vertical wells per month.
Okay. Yes. I mean that's kind of what I was getting as it looks like doing a little bit better on the days and what you originally budgeted for and just was curious if we might see maybe next quarter that vertical well count guidance maybe go up a little bit just because of the run rate?
Yes. That's a fair question. But right now for your planning purposes I just stay with 2 per month.
Okay. And then back on the completion side on these horizontals, just to make sure that I'm understanding this correctly, as you all have been testing the longer laterals so far at least you've stayed with a consistent sort of £300,000 of sand per stage. You haven't sort of adjusted to see if as you go longer maybe to increase that?
Well, so far, the only when we said we go longer, we've gone from a 1 mile lateral or the 5,000 foot laterals to the 7,500 foot. And no, we've not really changed the recipe there. The next well we've got on the drilling schedule is a 10,000 footer down in Upton County and we're working the design of that right now. So there may be a slight change in a 10,000 foot design.
Okay, great. Thanks guys.
Thank you. Our next question comes from the line of Ipsit Mahaney from Canaccord. Your question please.
Good morning guys.
Hi. Good morning Ipsit.
Let me start off with the Texas with the Magdalen LongHorn pipeline. If you could provide some more color on the time line, like is this current quarter be the first one to realize pricing? Or are we going to see a lag?
Yes. The pipeline started filling in April and the producers that have committed firm transportation to the line were notified late April and we nominated barrels starting in May. So in May would be the first time we realized the uptick in LLS versus WTI. And what Magellan is telling us is that there's 3 kind of milestone production points that they're going to reach. The first is 75,000 barrels a day, which they hope to reach end of this month, early next month.
And then they'll go to 135,000 barrels, which is kind of in the July timeframe. And then they anticipate being at 225,000 barrels kind of in late October. And what they'll do at each one of those milestones is they'll come back to the producers and they'll increase the allotment up until for Diamondback up until we're at our 8,000 barrels a day of firm transportation when they're at 225,000 barrels a day of full capacity.
Travis on pricing, is that a spot pricing that you fixed with them? Or is it a fixed pricing, if you could talk about that a little bit?
Yes. It's simply it's a deduct. So we receive LLS pricing less about $7 a barrel.
Got you. Great. And then a follow-up on the horizontal Wolfcamp wells in Midland and Uptown. If you could talk do you plan to drill any laterals longer than the 7,500 And just approximately how many of them to kind of test out the ultra long laterals?
Yes. What we've seen, Ipsit, is that there is a cost efficiency as you increase the lateral length. And we've seen that when we went from 5,000 foot laterals to 7,500 foot laterals. And as I just mentioned, we're getting ready to test our first 10,000 foot lateral in Upton County and we anticipate seeing that same cost efficiency as we add another 2,500 feet of lateral length. Now granted every time you add lateral length you increase risk a little bit.
So that's kind of the offset there. But in a general sense, we let our lateral lengths be dictated by our lease geometry. So our sort of preferred lateral length is in that 7,500 to 8,000 foot range because most of our leaseholds are kind of 3 miles stand up sections and we can develop 3 miles with 27,500 foot laterals. Where we can now is rather than drill 2 short laterals, we're going to try to drill just one long 10,000 foot lateral. And we think there's a material cost improvement or cost efficiency improvement there.
But we've got to get 1 on the Board first. And so when I look ahead for this year, I think we've got Russell we've got 5, roughly 5, 10000 foot laterals on the Board for the rest of this year. But the first one in Upton County is the one that we're really going to test.
Travis, you might have talked about this, but I assume your additional rig in the Wolfcamp will be in the Midland County?
That's a fair assumption.
All right. And given what you've just seen with putting submersible pumps on these wells, are you going to do that across the board on all wells? Or is it a case by case basis?
Right now, my operations organization is saying they're liking what they see, and it's probably going to be all future wells will go with the sub pump.
Wonderful. Thank you, Travis.
Thank you. Our next question comes from the line of Jeffrey Connolly from Breen Capital. Your question please.
Hey, good morning guys. One quick follow-up on CapEx. The 3rd horizontal rig, that's baked into the guidance too, right?
That's correct.
And then around the announcement of the S-one, you guys mentioned potentially raising CapEx to accelerate horizontal drilling. Can you give us some idea what an accelerated horizontal program would look like?
That's one of those things that I mentioned earlier. In this quiet period with the SEC, I can't comment on any of that until we actually get effective and then get out on the road with our story. Okay. That's fine. Well, thank you very much.
That's it for me. You bet. Thanks.
Thank you. Our final question comes from the line of Matt Portillo from Tudor, Pickering. Your question, please.
Good morning, guys.
Hi. Good morning, Matt.
Just a few quick questions for me. One of the interesting comments you just made was potentially drilling a longer 10,000 foot lateral versus 2 shorter 4,500 foot laterals. I was curious if you guys have a rough kind of AFE estimate of what you'd be looking for on the 10,000 foot lateral? Just trying to get a sense of kind of the potential improvement on capital efficiency.
Yes. We're putting the final touches on the AFE right now, but it's kind of like in that $9,000,000 range. And as I reported our current Q1 performance on the shorter laterals were $6,000,000 So if you kind of just look at those two endpoints, a $9,000,000 10,000 footer versus a $12,000,000 for 2, 5000 foot laterals. So I mean that's where you start seeing the economies of scale there, which makes the risk profile worth probably taking.
Perfect. And then just on the Wolf Barry, I was wondering if you could just give us an update on kind of where your AFE costs are coming in there? And do you guys continue to see some cost efficiencies you can ring out on kind of the Wolf Barry wells?
Yes. We're running about $2,000,000 to 2.1 dollars $2,000,000 to $2,100,000 right now on actuals. And we're picking up pennies right now on the vertical program. So I won't say that we'll never be happy with cost performance in a general sense. We always strive to reduce costs, but we're really pretty close to the edge right now.
Great. And then I know you guys are focusing obviously on the Wolfcamp horizontals and that's been covered in detail here. I was just curious on the Wolf Barry, as we think about kind of the 20 acre down spacing opportunity, I know that kind of at the time of the IPO, that was something you may have been looking at late this year or early in 2014. I was wondering if that was still kind of in the plans and if you've seen any other offset operators testing some of the additional 20 acre down spacing that would give you confidence in limited interference on the wells?
Yes. In our plans right now for this year, we don't anticipate doing any 20 acre infill wells. In fact, most of the vertical program we'll have in front of us is just simply to hold acreage. But we are actively involved in conversations with some private operators around town that are active active in down spacing. And so we're in conversations with those guys.
And in a general sense, the jury is still out on there. But I think as we think about it, somewhere around an 80% reduction from the 40 acre well is reasonable. So you'll just have to do the economics on cost and recoveries to see if that's an economic venture. But it's not a decision that we're faced with right now. It's still future economic inventory for our shareholders going forward.
But right now, we're drilling the highest rate of return investments we can. And right now, those are the Wolfcamp B horizontal wells.
Perfect. And then just my last question. We've seen some softness in the A and D market as of late with some failed private opportunities, and I assume that may provide you guys some opportunity to pick up additional leasehold acreage, although we are clearly operating, it is still a pretty hot market. Just wondered if you could give us any commentary on kind of how you see the A and D market at the moment and really the opportunity set you see for picking up incremental acreage within Midland or maybe some of the other basins within the Permian?
Well, you're right in your comment about the acreage being pretty tightly held. But I think it's fair for our shareholders to expect that Diamondback is involved in every negotiation or every conversation about acquisitions here in the Midland Basin. In terms of picking up acreage, I think I announced last quarter that we picked up about 2,500 acres and I think we've added 100 about 150 to 200 acres just this quarter as well too. So it's we're picking up parcels and they're bolt on acreage and we're active in the game of in the A and D arena as well.
Thank you very much.
Thank you. This does conclude the question and answer session of today's program. I'd like to hand the program back to Travis Stice for any concluding remarks.
Great. I know this is a busy time and a busy day for a lot of the equity analysts out there. So I appreciate the attention this morning that we that Diamondback got. And also I appreciate everybody else that was on the call as well too expressing your interest in Diamondback Energy. If you've got any questions, we're in our offices all week.
We've got Adam Lawlis now and his contact information is on our website. So if you've got any further questions, I encourage you to reach out to Adam. But just really thanks guys for the interest in Diamondback Energy and we look forward to having some more conversations with you guys in the future.