Good day, ladies and gentlemen, and welcome to the Diamondback Energy and Viper Energy Partners 4th Quarter 2015 Earnings Conference Call. At As a reminder, this conference call is being recorded. I would now like to introduce your host for today's conference, Adam Lawlis, Investor Relations. Sir, you may begin.
Thank you. Good morning, and welcome to Diamondback Energy and Viper Energy Partners' joint 4th quarter 20 15 Conference Call. During our call today, we will reference an updated presentation, which can be found on Diamondback's website. Representing Diamondback today are Travis Stice, CEO Mike Hollis, COO and Tracy Dix, CFO. 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 found in the company's filings with the SEC. In addition, we will make reference to certain non GAAP measures. The reconciliations with the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon. I will now turn the call over to Travis Stice.
Travis?
Thank you, Adam. Welcome, everyone, and thank you for listening to Diamondback and Viper Energy Partners' Q4 2015 conference call. To begin, I want to discuss Diamondback views the current environment and how we are responding before I turn the comments over to Mike and Tracy to highlight operational and financial details. 2016 began with oil prices testing recent lows. Diamondback Energy is well positioned in this environment and continues to demonstrate that we are a low cost operator with superior execution abilities.
After our equity raise last month, Diamondback had over $250,000,000 in cash at the end of January 2016 and an undrawn revolver. Our all in cash costs, including G and A, LOE, transportation and production taxes are currently below $10 a BOE. To further illustrate our cost structure, Diamondback has 140 employees producing almost 38,000 BOEs a day. We've always run a lean organization and times like now remind us how that's a prudent practice to follow. We continue to emphasize our strategy of capital discipline, especially in light of current low oil prices and their impact on stockholder returns.
We've consistently communicated that we accelerate development when returns to our stockholders are increasing and decelerate when returns weaken. We have widened our 2016 production and capital guidance ranges to allow for capital flexibility in our operations as rig count and completion cadence may fluctuate through the year. If you look at Slide 5, we've outlined our actions on how we've responded to a low price environment. We've reduced D and C costs and deferred drilling and completion activity while maintaining our leasehold position. This allows Diamondback to preserve capital flexibility, maintain our conservative balance sheet and keep leverage low.
Also on Slide 5, in a lower for longer 30 $5 per barrel WTI price scenario, Diamondback believes it can maintain conservative net debt to EBITDA under 2x through the end of the price tranche of $25 to $35 WTI. At the midpoint of this range, Diamondback has almost 500 economic locations and we have over 1500 economic locations at $40 WTI. We've been able to increase the number of gross locations at each oil price since the last presentation because leading edge D and C costs are currently at $5,250,000 for a 7,500 foot lateral, down from 6 previously. Turning briefly to M and A strategies. Diamondback Energy believes the current environment will present opportunities to grow company.
We believe our execution ability and low cost structure make us natural consolidator within the basin. However, we will only do deals that are accretive to our stockholders. Viper Energy Partners continues to look for accretive mineral opportunities inside and outside the Midland Basin. We also recognize the opportunity for Viper to provide liquidity to distressed sellers through the purchase of their royalty interests. As I stated previously, Diamondback has an undrawn revolver and over $250,000,000 in cash.
Diamondback will continue to run its business in a prudently conservative manner until we believe that oil prices have recovered, sufficient to allow us to return to a growth mode. We had hoped that oil price bottom was going to be at the end of 2015, but now we are hopeful that it will happen later this year. However, if our expectations are wrong, Diamondback can weather the storm. In a prolonged period of low oil prices, Diamondback expects to be the last man standing. I'll now turn the comments over to Mike.
Thank you, Travis. As mentioned in last night's press release, we have now completed our first three well pad in Glasscock County targeting the Lower
and produced a 7 day average
of over 3,600 BOE per and produced a 7 day average of over 3,600 BOE per day on a combined basis. At the end of 20 15, we also drilled a 2 well pad in Glasscock County targeting the Wolfcamp A and Wolfcamp B that is currently flowing back. Slide 8 shows Diamondback's Glascott County activity as well as notable offset results. We have also delineated our IP data on this slide. In Howard County, we have drilled a three well pad that targets the Lower Spraberry, Wolfcamp A and Wolfcamp B, and we're currently drilling a second three well pad.
We intend to complete these wells in mid-twenty 16. 1 of these wells was a 9,600 foot lateral that was drilled in less than 12 days from spud to total depth, which we believe to be fastest well to TD in the area. A map of Diamondback's Howard County acreage and notable offset results is located on Slide 9. Slide 10 shows that in all of our core operating areas, Diamondback continues to drill wells faster than offsetting peers. We drilled a 3 well pad in Spanish Trail in 37 days from spud of the first well to rig release of the 3rd well.
In Martin County, we drilled a well with a 7,500 foot lateral in less than 10 days from spud to TD. In addition to our continued efforts to drill wells faster, we have also managed to lower other drilling expenses. To that point, we were able to move a rig roughly 90 miles from Spanish Trail to Howard County in less than 3 days from rig release to spud of the next well. Slide 11 shows our current realized well cost reductions, which have come down roughly 30% to 35% since the peak in 2014. Leading edge drill, complete and equip costs are trending between $5,000,000 $5,500,000 for a 7,500 foot well and between $6,500,000 $7,000,000 for a 10,000 foot lateral well.
Slide 12 shows reductions to our current realized lease operating expenses since the peak of 2014. We are extremely proud of our production organization for lowering LOE per BOE from nearly $8 a barrel in 2014 to less than $7 a barrel in 2015. By gathering the data to fix the wells right the first time, we have reduced our rod and pump failure rates, translating to lower LOE. We were able to integrate 139 existing vertical high operating cost wells primarily in Howard County in the second half of twenty fifteen while lowering LOE. Slide 13 illustrates Diamondback's proved reserves, which increased 39% as of December 31, 2015 to approximately $157,000,000 BOE.
Additions replaced 4 65 percent of 2015 production with a drill bit F and D cost of $5.51 per BOE. Drill bit F and D declined by 50% from $11 per BOE in 2014 as we continued to decrease development cost and lower the and target the Lower Spraberry in new horizontal formations such as the Wolfcamp A and Middle Spraberry. With these comments now complete, I will turn the call over to Tracy.
Thank you, Mike. Diamondback's adjusted net income for the Q4 of 2015 was $39,000,000 or $0.58 per diluted share. Diamondback's consolidated adjusted EBITDA for the Q4 of 2015 was $123,000,000 which is 11% above EBITDA in the Q4 of 2014, despite price realization being significantly stronger in 2014. Our Q4 2015 average realized price per BOE including the effect of hedges was $55 Diamondback continues to have pure leading cash margins driven by our focus on execution and cost optimization. Slide 14 shows that our 2015 operating expenses are 29% lower than the peer average for the 1st 3 quarters of 2015.
Also on that same slide, we show that Diamondback continues to be one of the leanest operators with G and A less than half that of this year average for the same period. In the Q4 of 2015, our cash G and A costs were $1.06 per BOE, while non cash G and A costs were 1 point $4.0 During the Q4 of 2015, our capital spent for drilling, completing and equipping our wells was $70,000,000 dollars Our infrastructure costs were $5,000,000 and we paid $20,000,000 on our non operated properties. The company spent an additional $24,000,000 on primarily bolt on acquisitions during the Q4 of 2015. At the end of January 2016, we were undrawn on our secured revolving credit facility after paying down the balance with proceeds from our recent equity raise. With over 2 $50,000,000 in cash and $500,000,000 in undrawn revolver capacity, we have ample liquidity to fund our 2016 drilling program.
Pro form a for proceeds from the equity offering, our net debt to annualized 4th quarter 2015 EBITDA is 24 times as shown on Slide 1516. Moving to Slide 17, we provide our guidance for 20 16. As announced last night, we widened our 2016 production guidance to a range of 32,000 to 38,000 BOE per day, including a range of 6,000 to 6,500 BOE per day attributable to Viper to account for the continued volatility and uncertainty in the commodity market. We expect our capital spend to range from $250,000,000 to $375,000,000 for 2016. Turning to operating costs per BOE, our 2016 LOE is guided to the range of $6 to $7 and gathering and transportation to a range of $0.50 to $1 Our cash G and A projection is $1 to $2 and our non cash G and A is expected to be in the range of $1.50 to $2.50 We have forecasted our DD and A rate from $13 to $15 and production and ad valorem taxes are expected to be 8% of revenue.
I'll now turn to Viper Energy Partners, which recently announced a distribution of $0.228 per unit for the 4th quarter, 14% above the 3rd quarter cash distribution. This distribution represents an approximate 6% yield when annualized based on the February 12 closing price. Viper has no minimum quarterly distribution or complex ownership hierarchy. The majority of cash flow is returned to unitholders through quarterly distribution, providing upside when oil prices rebound. On Slide 18, we show how Viper's distribution remains resilient despite lower oil prices due to organic production growth.
Spanish Trail remains one of the most economic areas in the Permian Basin and we expect the operators will continue to drill there. At the end of 2015, Viper had $34,500,000 drawn on its revolver. Now turning to Viper's guidance, we expect a production range of 6 to 6,500 BOE per day. On a per BOE basis, we anticipate cash G and A costs of $0.50 to 1.50 dollars and non cash G and A of $2 to $3 in 20.16. We expect DD and A to range between $14 $16 and gathering and transportation of $0.25 to $0.50 with production and ad valorem taxes at 8% of revenue.
As a reminder, Viper does not incur LOE or capital expenditures. I'll now turn the call back over to Travis for his closing remarks.
Thank you, Tracy. In summary, Diamondback has taken the correct steps to respond to current low commodity prices. We're well positioned to live in a $35 WTI world through the end of the decade and developed plans that reflect net debt to EBITDA of less than 2x without accessing the capital markets or drawing on our revolver. We've laid out plans to respond to difficult commodity prices and are poised to return to growth mode when market conditions improve. Lastly, we've maintained our unwavering focus on execution, continuing to push our advantage in low cost D and C operations and peer leading expense structure and remain transparent with our business strategy.
Operator, please open the line for questions.
Thank you. The first question is from John Nelson of Goldman Sachs. Your
The press release made reference to opportunities for accretive growth, given you guys are guiding to organic production kind of flat at best, I'm assuming that means you expect to be more active in the acquisition market. Can you comment on what you're seeing in the acquisition pipeline? Are these corporate assets I'm sorry, corporate transactions, asset deals, private equity players, public operators? And to the point on accretive growth, is this really just your multiple premium that you think is the differentiator here? Or is Diamondback's efficiency advantage also something you would expect to add material value in acquisition?
John, there's a lot of questions embedded in there. Let me just kind of talk from it from a high level from Diamondback's perspective. What I talked about in January when we did our equity raise is that we were seeing an increase in the amount of smaller bolt on transactions or what we call around here little a type acquisitions, and we're continuing to see those. I think the fact that you're not seeing a lot of announced trades on larger acreage blocks, probably tell you that the spread between bid and ask is still relatively high. I believe the sellers probably have a price forecast that's above of what the acquirers are looking for.
And then the bigger type C Corp combinations, we continue to evaluate different opportunities there, again, to do so only in an accretive fashion. Diamondback has a long history from the very beginning of being an acquired and exploit company. So we're not increasing our efforts on the acquisition front. We're really just continuing what we've always done, which is to look for accretive opportunities that we believe we can demonstrate that, that rock is worth more in Diamondback's hands than somebody else's through our conversion process of rocking the cash flow. So how the other elements that you were describing are trying to move around in the acquisition space, you're probably best answer those guys.
But Diamondback is committed to doing smart deals that are accretive. And we kind of believe that we're the right operator. And if we find the right rock, we'll generate the right
moving to, I guess, expenses on the quarter. Aggregate LOE dropped despite sort of the increase in volumes. It was pretty impressive. Your 2016 guidance seems to imply you give most of that back though. Was there anything kind of one time that sort of aided 4Q results?
Or is there maybe some conservatism built into 2016 LOE guidance?
Yes. Just on any guidance in 2016, we don't typically build in a conservative guidance at all. We try to put our best estimates forward and communicate that in a transparent fashion. Now specifically to what happened in the Q4, Mike mentioned it in some of his prepared remarks, but when we acquired our properties in Northwest Howard County kind of midsummer of last year, in our accrual process for accounting for expenses, we were using the prior operators' run rate on expenses. And because our operations our inventory, they really responded in a very quick fashion to get these wells operating like Diamondback expects.
And as a result, we kind of overshot what we were thinking the expenses were going to be in the Q3 and the Q4 was the beneficiary of those that overshooting. So I wouldn't really characterize it as giving back any of the expenses. We tend to try to hold on to every penny we ever pick up, but that's specifically what happened in the Q4. We believe our guidance is $6 to $7 a barrel for 2016 is right down the middle of the fairway.
Perfect. Congrats on the quarter.
I'll let somebody else hop on. Thanks, John.
Thank you. The next question is from Michael Glick of JPMorgan. Your line is open.
Just on your flat $35 a barrel case,
could you give us some color
on what the company would look like
a couple of years out?
Well, obviously, Mike, we've got the company modeled out there. I'm not a big fan of given multi year forecast out there. I can tell you from a general perspective, if Diamondback was to run 1 to 2 rigs, our production is flat to slightly declining. If we were to run 2 plus rigs, it's going to be flat to a slight growth as you look out into the future. Obviously, with a lot of capital flexibility this year, predicting exactly what 2017 is going to look like is a little early to do on the 17th day of February.
So we're going to try to model the company and give you updates kind of each quarterly update. But I think in a general sense that 1 to 2 rigs kind of flat to decline and 2 rigs more flat to up sort of forecast what the future is going to look like. To make that statement though, we were at the lower end of our rig cadence, kind of that 1, 2 rig cadence to get to that $35 comment that I made.
Got it. And then at the low end of capital, how
should we think about the cadence of completions moving through the year? And how many DUCs would you expect to have at year end?
Yes. At the low end of the CapEx guide, we'd probably end up with 30 to 40 DUCs by the end of this year. And if we were at the high end of that guide, we'd probably end up with 10 or less DUCs.
Got it. Okay. That's it for me. Thank you very much.
Thanks, Mike.
Thank you. The next question is from Neal Dingmann of SunTrust. Your line is open.
Hey, good morning, Travis. So, Travis, just kind of add on to that last question. When you look at the plan for this year, not just the DUCs, but how do you see as far as the areas of drilling more when you look at the Spanish Trail? Obviously, you had success now in this new Glasscock. You mentioned that obviously the very quick well you're able to drill up in Howard.
How should we sort of think about the entire plan under kind of that lower for longer scenario or if you were going to upsize things a bit?
Sure. Well, I'll kind of put the endpoints on it, Neil. If we were to run 2 to 4 rigs, which would be towards the upper end of the guidance, and of course, as I stated in my commentary, we'd have to have some pretty good confidence in oil price before we went to the upper end of that rig count. But if we were running 2 to 4 rigs, we'd keep the 2 rigs in Spanish Trail and we'd have 1 rig in Glasscock, 1 rig in Howard. And then if we moved a rig around, we'd probably catch a well or 2 in Northeast Andrews County where we've had some really nice results.
If you're at the lower end, I mean, if we get all the way down to 1 rig, like we talked about potentially in mid summer if commodity prices continue to soften from this point. That rig would be mostly drilling obligations, which should be heavily weighted towards Howard County, where we've got 3 wells drilled and drilling our second 3 well pad now. And then you'd probably be bouncing the rig occasionally in and out of Spanish Trail as well. So that's kind of the way it looks, Neil, with 1 rig all the way up to 4 rigs.
That clarifies. And then just lastly, you all have unique benefit, obviously, when obviously when went through and Tracy went through with Viper to have that. Obviously, to me, I think the shares certainly with oil prices haven't rebounded maybe where they once could here. Do you anticipate you mentioned with accretive acquisitions. I'm just wondering, is there a way to use Viper at all or you just or will you just sort of continue if this environment continues, you'll just kind of continue how you've been with the higher interest with it?
Or is there anything else you could do with those?
Well, I mean, of course, without getting into any kind of deal specifics, we recognize that the Diamondback is uniquely advantaged with those Viper units and that does represent something that we can do in a trade that nobody else can do, whether it's a co bid strategy with Viper bidding alongside Diamondback or even Diamondback using the Viper as the form of liquidity in a transaction. We are seeing increased interest in Viper units at these low commodity prices as people embolden themselves that commodity prices might be bottoming out and beginning to recover. So I guess it's I can't give you any deal specifics, Neil, but I do think that there's a likelihood that some kind of transaction that Diamondback gets involved in the future would include Viper ownership.
Yes. Nice to have him. Thanks, Travis.
Yes. Thank you, Neal.
Thank you. The next question is from Mike Kelly of Seaport Global. Your line is open.
Thanks. Good morning. Travis, you detailed out what we could expect on the deferred completion front really for 2016 in a couple of different What's What are you doing with oil kind of, Pete, around $30 Thanks.
Yes. Thank you, Mike. Yes, with oil below $30 a barrel, as
I laid out in one
of those slides, I think Slide 5 or 6, we're actually deferring some completions right now. So we'll likely continue to defer completions through the end of the year. And in order to get to that 30 to 40 total DUCs, we're going to be probably deferring 4 to 5 DUCs a quarter to get to that number. So that's kind of how we're looking at it right now, Mike. The one thing to know about DUCs is that once we're convinced that commodity price has recovered, we believe that we can go out really quickly and prosecute an execution plan that gets these DUCs completed inside the current year.
Again, we're going to be very judicious in that decision process though.
Okay, great. That's it for me. You laid out guidance to 2020, so I've got no further questions. Thanks.
Thank you. The next question is from Gordon Boutet of Wells Fargo. Your line is open.
Hey, good morning, everybody. Just kind of more questions on the table on Slide 6. Just trying to get a sense on how you toggle activity levels, first with the completion of the DUCs and then beyond that the potential to add additional rigs. As we kind of move through these different pricing scenarios, should we assume that the rig count or increases as you move through up through these levels? Or how should we kind of interpret that slide?
Well, yes, we tried to lay it out as clear as we could, Gordon, on rig counts. As oil price moves up with some confidence that it's going to remain there, we'll pick those additional rigs up. I think the most likely scenario is the first lever we pull on under recovered oil price is working on those DUCs and then the second lever would be stand up and additional rigs. So in a general sense, we've always talked about sort of whatever the first number on oil price is, is about the number of rigs we're going to run. And I think that still holds in Slide 6.
All right. Thank you. And then regarding comment on opportunities for accretive growth, when you look at acquisition opportunities, does this necessarily involve for it to be accretive, the use of Viper in one form or another, joint bid or use of Viper as a source of liquidity? Or are you looking at standalone Diamondback Beds? Or how do you weigh that as you kind of look at these deals?
Gordon, again, without giving a lot of commentary on what our exact acquisitions bid strategy is. All of those things you just laid out are available to Diamondback as we try to do an accretive deal. So I think it's deal specific and we'll look at all of the combinations that you just laid out in order to create the greatest accretion to our shareholders.
All right. Thanks again.
Thank you. The next question is from Michael Hall of Heikkinen Energy. Your line is open.
Thanks. Good morning. I guess just one more on the M and A angle or A and D angle. I'm just curious, we often look at the public equities and try to back into an implied commodity price and see something today that's premium to the current strip. I was wondering if we could take that analogy and you could help us try to apply that in the private market.
When you talk about the bid ask spread being wide, what sort of price levels are maybe being implied as you look at these deals? What sort of price levels are being implied by the sellers as sufficient to win a bid at this point?
I know I appreciate the interest behind that question. Again, I'm not going to talk a lot about how Diamondback used things. But I'll tell you, Michael, in a general sense, what I believe is that the sellers always hold on to the last trade that was publicly announced. And so if you've not seen any transactions occur on the private on the acreage size, it's probably because the most of the sellers are hanging on to what the last announced trade was. And I believe you can do your own reconnaissance on that, but somewhere north of $30,000 an acre.
So I think we'll just have to wait and see, Michael, until you see some transactions come across the board that whether or not that gap is really closed.
Fair enough. I figured it's worth a shot. I guess also I'm just trying to think through, I guess, capital efficiencies in the kind of low case scenarios, not only for yourselves, but across the industry. I guess, how do we think about things like pad development and what might be the most efficient way in a vacuum to develop things as opposed to the realities of trying to hold leasehold and things along those lines. Would you say that the low case of the low end of the range that you provided is kind of exhibiting those fixed costs flowing through and provide like a range of capital efficiency in terms of how we think about moving forward things will really ratchet higher from a capital efficiency standpoint?
Michael, I'm going to answer the I'm going to kind of answer the macro question and then specifically on the low end, I'm going to let Tracy answer the on the low end side of the capital efficiency. So on a macro view, the more rigs that you run, typically the more efficient your operations are because you're keeping a rig there on location longer and getting a 3 well pad drilled and you're bringing the completions in. And it's a more efficient process when you can kind of keep a rig in a general area. And let it do let the drilling and completion cadence follow in an efficient manner. When you actually go to a world where you're only running 1 rig, you're by definition given up some of those efficiencies because where you might want to keep a rig on for 2 months to get 3 wells drilled, you may actually have to only drill one well there.
You may only have the time to drill one well there and then move that rig to another location. So you sort of give up some efficiencies there. That's in a macro sense. I'd rather be more efficient running more rigs. But again, now I've got an offset with cash burn.
So specifically to your question on the low end of our CapEx guide, I think there's another element that Tracy is going to explain to you.
Hi, Michael. Yes, on the low end there, we do have probably some efficiency loss there. But to clarify what's going on, we have a guidance out there of 30 completions, but when we're running that low, we're actually going to be drilling more wells than we complete. So there's capital being burnt there and you're not really getting it in the well count when you're doing the division as well as running lower amount of rigs, we're going to have some rig penalties in there. And then lastly, there is a little bit of there are some wells that you start in 2015 that you end up paying for in 2016.
So again, when you're dividing them just by 30 wells versus, let's say, the upper end of 70, it shows a lower capital efficiency in the amount. So that's how our low end is working.
Okay. That's helpful. It makes sense. Last one on my end is just around the Glasscock wells. Does completion designs on those wells vary between themselves and then relative to how you complete wells further to the west or any changes around that?
Yes, Michael, on those first three well pad that we talked about, that Mike talked about, first, just again, I'm going to reemphasize how pleased we are with the early flowback data from those wells. I think they're at or above our expectations at each of the three intervals and we've kind of outlined that on the one slide that's in the deck. So what we did when we moved into that area, we wanted to make sure we tried to get our best assessment relative to how we completed the wells in Midland County. So we actually followed the same recipe in Midland County almost Glasscock County wells and that gives us a better comparison. Now, we didn't talk about the 2 well pad, that's a Wolfcamp A B that we've only been flowing back for about a week now.
We actually increased the sand concentration, the completion density on those 2 well pads. So as we get the 3 well pad that's flowing back right now, we get information out of that. That's done with our traditional Midland County completion. We'll be able to compare it right next door to it with a 2 well pad with the increased sand that we put there. So we think we're doing it kind of the smart way in terms of trying to assess the science so that when we kick into full scale development, we'll have the best recipe.
But I'll tell you again, just to reemphasize, the Wolfcamp A, Wolfcamp B at or above expectations and the Lower Spraberry actually has been the most surprising zone in Westcott County because it appears to be as good as the Wolfcamp B and A and then certainly better than the wells in the 15 mile radius around there. So really excited about the Lower Spraberry.
And that Lower Spraberry well, has it peaked yet or is it kind of exhibiting a similar profile to those in Midland County?
Yes, it's probably we put that well on sub pump about 3.5 weeks ago. So it's probably at its peak rate.
Okay, Great. Appreciate the color. Thanks.
Thanks, Michael.
Thank you. The next question is from Kashy Harrison of Simmons and Company. Your line is open.
Good morning and thanks for taking my question. When we think about the $250,000,000 to $375,000,000 CapEx range, how should we think about the commodity price assumptions that are embedded into that guidance? Is that kind of $25 to $35 range?
I think the $25 to $35 range, that's the 1 to 2 rigs and that's going to put you at the lower end of that CapEx range. If you're in that $35 to $45 WTI range, that's 2 to 3 rigs and that's going to push it towards the upper end of that CapEx range. And we tied that back cash into also the production range that did. So we're intellectually honest between rigs, CapEx spend and production guidance.
Okay. Thanks for that. And then when we look beyond 2016, do you see the company eventually transitioning to 2 mile laterals, to a 2 mile lateral program? I know right now you guys are running kind of 7,500 on average, but could that go to 10,000 beyond 20 16?
In a general sense, Kashy, we try to drill as long as we can that at least geometry allows us. So we actually have some 12,500 foot wells on the board this year. We believe the capital efficiency is much better and we've demonstrated it on these longer laterals. We always want to try to drill longer. That was one of the reasons we're so excited about Howard County is over half of those wells as we develop up there are going to be of the 10,000 foot variety.
So I'm not looking into 2017 to drill longer. I'm looking into next month to drill these wells longer. But again, it's somewhat limited by lease geometry.
Okay. And just the last one for me. In terms of service cost concessions from the service guys, do you still see some room there in 20 16? Or do you think we've gotten all of it that we've gotten all we can get from those guys?
Well, certainly our business partners on the service side, they're under quite a bit of distress right now. And I know that as long as they have vital equipment in their yard, their pressure is to get prices set so that equipment can go to work. So I think there may be a little bit of movement still. But I'd tell you for planning purposes, and that's the way we're looking at it as well for planning purposes, I think the numbers that we gave you are good for the year. But if oil prices continue to soften, you could see a little bit of downward pressure.
But we believe that the costs are kind of in right now.
All right. That's it for me. Thanks for your time. Truly appreciate it. You bet, Kashy.
Thanks.
Thank you. The next question is from Jason Wangler of Wunderlich. Your line is open.
Hey, good morning, Travis. Just kind of dovetailing on one, you kind of mentioned kind of the plans as you'd have either a 1 rig program or a 3, just kind of with you dropping the 3rd rig or looking to next month. With 2 rigs, would one be basically a Spanish Trail and the other kind of floating or just kind of how you see that if in the 2 scenario?
Yes. I think we were trying to spell that out earlier as well. But Jason, with 1 rig, that's going to be bouncing around for the various lease obligations, mostly in Howard County. If we're running 2 rigs, 1 rig will be we'll park 1 rig mostly in Spanish Trail and then probably a half to a 3 quarter of that rig will be moving around either to Glasscock or Howard County. But you're going to keep pretty much one rig in Howard County most of the year and then any other rigs will be added to 1st Spanish Trail and then secondly the Glasgow County and Northeast Andrews County.
Okay. And just kind of thank you for that. And on that, as you look at that, holding the leases in Howard, is that a couple of years that you'd have to do that? Would that be primarily done by the end of this year? Just kind of where you see that falling, I guess, in the lower scenario?
Yes. That's probably a fair statement for the next 12 months to 24 months. And of course, we're doing things also. I mean, if we're in a protracted low oil price, I mean, we'll have to look at lease extensions and things like that, that will allow us to avoid drilling right away. But in a general sense, at least for planning purposes, probably this year and next, we'll keep a rig up there in Howard County, which we haven't been able to demonstrate it to you yet until we complete these wells, but we think that will be a good economic proposition as well.
And then also now with the really outstanding well test we had in Glascotte County, now we've got real competitive returns down there as well too. So we've got some abilities to have some make our capital more fungible as we look at returns to our shareholders.
I appreciate it. Thank you.
Thank you. The next question is from Jeff Grampp of Northland Capital Markets. Your line is open.
Hey guys. Wanted to go back to the table you guys have regarding the economic locations at the various price decks. And just kind of looking back to your past decks, it looks like you about doubled your breakeven inventory in kind of that 40 ish price deck. So just kind of wanted some color on that if that's exclusively related to the lower well cost assumptions that you have been able to achieve lately or maybe there is some increased confidence about well performance in some newer areas or some newer zones that you guys are adding there?
Well, certainly, we are more confident every day. We get well tests in certainly Glasscock County and soon to be Howard County. But specifically, Jeff, though, all of the changes that were made in well count was a reflection of taking well cost from $6,000,000 per well for 7,500 foot lateral, the last time we used this in our last quarterly call down to $5,250,000 Makes a big difference in the number of locations that are economic. Okay. Thanks for that.
And then, shifting to kind
of looking
at the back end of your deck here, the updated well performance on some of the Lower Spraberry down spacing tests. Just kind of maybe if you could get a little bit more color about that 5 well multi pad where you had watering out type of issues it looks like. Is that something that you guys had kind of expected? Are these wells kind of performing in line? Just kind wondering how you guys are looking at these wells relative to the really staunch outperformance we saw from some of those earlier wider space wells?
Sure, Jeff. I'm going to let Russell, he's in the room for that. I'm going to let Russell answer that question.
Yes, Jeff. I know we've got a lot of different curves on that slide. I'll make it a little bit confusing. But we show one of the curves for the 500 foot spaced wells without the 5 well pad and you can see it pretty much mimics the results of the wider spacing on. But specifically to the 5 well pad, we were a little surprised there.
An offset operator came in and drilled some wells to us that watered out, temporarily watered out several of our wells on our 5 well pad. And 2 of those wells are kind of light time, so that's really affecting the end of the curve. 1 of those wells of R5 was a well that we drilled later and it was partially watered out as well. So it affects the early time. So it really affects the whole curve.
I think the thing that to look at is if you look at the very end of the curve and you see the slope, you can see that those wells over the last 20 or 30 days have started to recover and are essentially back to the rates that we projected. So I know you just look at it overall, it looks a little concerning. But when you actually step back and look at the individual wells and how they've recovered, I would say, the results look pretty encouraging at this point. And so we're continuing on the wells that we're drilling now. We're continuing to use the 500 foot spacing in Spanish drill.
Super helpful color, Russell. And then last one for me on the just kind of completion thoughts, seeing some other operators getting some encouraging results on some different completion optimizations and you guys talked yourselves about some increased proppant in Glasscock. Just kind of wondering how you guys are looking at progressing throughout the year, different tests you might have on the dock or concepts that you guys are looking at internally on the completion front? Yes.
Jeff, we spend a lot of time not only analyzing those results, but also analyzing what's said publicly from other operators. And we try to incorporate best practices and learnings from other operators quickly into our business. So I think you're seeing things like increased sand, increased cluster spacing, tighter distances, all of those things are reasonable to expect Diamondback to have some commentary on by the end of the year. And certainly now when costs are as low as they are on pressure pumping, now is a good time to be experimenting with that. There's a few things though that we're pretty confident we won't be trying and that's we have always been even since 2012, we've always been a slickwater shop and we intend to continue doing slickwater fracs.
Great. Thanks for the color.
Thank you. The next question is from Bob Bakkenauskas of GMP Securities. Your line is open.
Hi, good morning guys. Thanks for taking my question. Just hopping back to 2016 guidance range of 32,000 to 38,000 BOE per day, given it was a strong 4th quarter at about $37,000,000 and change.
I know you don't give guidance on
a quarterly basis, but could you just directionally sort of walk me through maybe in the low price scenario if you do end up going to 1 rig in the second quarter, just how volumes progress throughout the year?
Well, I think again, Bob, there's a reason we don't give quarterly guidance because there's just so much fluctuation when you can bring on a like we did in Glasgow County, you bring a 3 well pad on that's doing almost 4,000 barrels a day, that can materially impact 1 quarter. So it's really difficult for me to try to tell you exactly what quarter well, I can't tell you exactly what quarter over quarter production is going to do. Generally, Bob, if you've got 1 to 2 rigs running, you're going to have flat to declining production. If you're running 2 or more rigs, your production is going to build. And that statement sort of holds regardless of whether it's now or 2 years from now.
That's how we view production changing.
Okay, understood. And then just switching over to Howard County, looking forward to getting the results in the middle of the year. Could you just contrast with the Midland acreage in terms of which intervals are most perspective and maybe just talk generally about how the geology changes as you head Easton Howard?
Sure. Bob, I'm going to let Russell answer that question. Great.
Yes. I mean, based on other operators' results in the area, it looks like the Wolfcamp A is probably going to be the best zone in Howard County. But we think the Lower Spraberry is probably a close second. There hasn't been a whole lot of Wolfcamp B results, but generally the B thickens as you move to the Westmore Basinward. So we think on our particular acreage in Howard and as it moves a little bit over into Martin County, we think our B results there are probably going to be better than what you've seen out of the industry because most of their wells are closer to the shelf where the B stands.
Okay, got it. Very helpful. Thanks guys.
Thank you. The next question is from Joel Massante of Euro Pacific Capital. Your line is open.
Thanks. All my questions have been answered. Thanks. Appreciate it.
Thank you. The next question is from Ben Wyatt of Stephens. Your line is open.
Hey, good morning, guys. And sorry if this has been addressed and I missed it, but has there been a deep enough cut on the
services side to where you're starting to
see some maybe degradation
crews? And just would love you guys' thoughts if that's going to be a challenge when prices rebound. And maybe if you even guys if you guys have a price of where maybe that does become a concern and these service companies do start to get maybe some pricing power. We just love your thoughts on that.
Yes. Ben, our business partners on the service side, as I pointed out earlier, they're under quite a bit of distress right now. And they're very smart individuals in running their business and they know the importance of keeping good crews and good equipment. And regardless of our pace of activity, we expect and demand good service for
a fair
price and the service companies, our business partners respond accordingly. Now when recovery occurs and activity starts to ramp up, there probably will be some things exposed that you can't see right now under a much slower development activity. But we think that since Diamondback should be one of the first companies to go back to work under a recovered oil price that we'll be able to attract the best crews and the best equipment as we start ramping up activities. Could it be a problem in the future? Yes.
But there's right now, there's sure a lot of surplus equipment around both on the pressure pumping and on the drilling rig side.
That works. I appreciate it. That was it for me. Thanks guys.
Thanks, Dan. Thank you. The next question is from Dan McSpirit of BMO Capital. Your line is open.
Thank you and good morning. Can you speak further to how quickly a DUC can be converted to a well that's producing and online? Just asking in an effort to get a better sense of how quickly you can capture a steeper contango in the oil curve if that were to materialize?
Well, Dan, the first thing is you place a call into the to the pressure pumping provider and you find out what their availability is and what their cost is. And right costs are low and availability is high. So in theory, you could go to work on the DUCs right away. Now there's some things we have to do on the front end of that, like accumulation stimulation fluid, making sure the location is prepped for the completion. But those are the
things that we do on a day in
and day out basis. So really when it's time to mash on the accelerator, as I pointed out earlier, we'll start on the DUCs. And with a fully dedicated crew, we can get about how many miles per month can we get with a
dedicated crew? Probably get 4 or 5 wells.
Yes. So you can get 4 to 5 wells a month per dedicated crew. So you can start to eat into a in a quarter, you can start to eat into your drill bit uncompleted backlog pretty quick.
Okay, great. Helpful. And then lastly here, how much further east off your Glasscock County lease line would you go to acquire more acreage assuming such acreage is available?
Yes. We like where our acreage is right now and I don't think you'd see us moving east from our position.
Very good. Thank you. Have a great day.
Thanks, Dan.
Thank you. The first question is I'm sorry, the next question is from Sam Burwell of Canaccord Genuity. Your line is open.
Good morning, guys. I was wondering if you could quantify a little bit the share of completions this year that would be 10,000 foot laterals. And then if that share or that percentage would change meaningfully depending on the
laterals and through time, I think that percentage is probably going to increase as we trade acreage, core up more of our acreage, you'll see those lateral lengths continue to increase over time.
Okay, great. Appreciate the color And then just sneak one more in hedging. You guys are still unhedged. I was wondering how what would the curve have to look like, especially in say 2017 for you guys to consider laying around some hedges?
That's a good question, Sam. That's one we still struggle with every day. I mean, would we like to have a large hedge book right now that looks like cash on the balance sheet, which by the way is how we view hedges. Yes, probably so. But that being said, we also now we believe we're going to be able to participate in the most fullest way in an oil price recovery.
So I don't want to give a specific number, but the contango nature of the curve right now would probably lend us maybe to start thinking about hedges somewhere, well, north of where it is right now. I think I saw a quote this morning that next year's hedges are right around $40 a barrel. So we probably need something a little north of that. But it depends, Sam. It depends on what we think the future of the oil price is going to do and what our activity levels are going to look like.
And it's not just a binary decision that we struggle with daily on how to put hedges on there. But that being said, though, we've got, as we pointed out, cash on the balance sheet from our equity raise that's sort of, in a way, looks like a hedge as well. So I think we're in pretty good shape.
All right. Makes sense. Thanks, guys.
Thank you. Next question is from David Meats of Morningstar. Your line is open.
Hey, thanks guys. Most of my questions have been answered, but just one last one on the table on Slide 6. Just looking in the $65 to $75 scenario, you got 2,600 locations, that's 200 more than in the $55 to $65 scenario. I'm just wondering if there's any way, any scenario or possibility to kind of upgrade those 200 locations and make them work at the $55 to $65 level? Is there something that you guys can do or some circumstances that would make that happen?
Yes.
I mean, I think so those wells are generally short lateral wells that takes a higher price to make economic. And as I indicated before, all companies are working on data trades to core up their acreage to drill longer laterals. So that's really what it's probably going to take to make those wells economic and I think the chance of doing that is pretty high.
Okay. That's all I've got. Thanks.
Thank you. And at this time, I'd like to turn the call back over to Travis Theiss for closing remarks.
Thanks again to everyone participating in today's call. If you have any questions, please reach out to us using the contact information provided. Thanks again.
Thank you. Ladies and gentlemen, this concludes today's conference. You may now disconnect.