Diamondback Energy Inc (FANG) — Q4 2015 Earnings Call Transcript

Thank you. Good morning. Welcome to Diamondback Energy and Viper Energy Partners joint fourth quarter 2015 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 Dick, CFO. During this conference call, the participants may make certain forward-looking statements related 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. 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' fourth quarter 2015 conference call. To begin, I want to discuss how 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 million in cash at the end of January 2016 and an undrawn revolver. Our all-in cash costs including G&A, LOE, transportation, and production taxes are currently below $10 of 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 completions cadence may fluctuate through the year. If you look at slide 5, we've outlined our actions on how we responded to a low price environment. We've reduced D&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 $35 per barrel WTI price scenario, Diamondback believes it can maintain conservative net debt to EBITDA under 2 times through the end of the decade without accessing the capital market or drawing on our revolver. On slide 6, we provided a more detailed scenario analysis highlighting the number of locations economic at different WTI prices and added a lower 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&C costs are currently at $5.25 million per 7500-foot lateral, down from $6 million used previously. Turning briefly to M&A strategies, Diamondback Energy believes the current environment will present opportunities to grow our Company. We believe our execution ability and low cost structure make us a 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 interest. As I stated previously, Diamondback has an undrawn revolver and over $250 million in cash. Diamondback will continue to run its business in a prudently conservative manner until we believe that oil prices have recovered sufficiently 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 will 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 Spraberry, Wolfcamp A, and Wolfcamp B. These wells had an average lateral length of approximately 7400 feet and produced a seven-day average of over 3600 BOE per day on a combined basis. At the end of 2015, we also drilled a two-well pad in Glasscock County targeting the Wolfcamp A and Wolfcamp B that's currently flowing back. Slide 8 shows Diamondback's Glasscock County activity as well as notable offset results. We've 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 are currently drilling a second three-well pad. We intend to complete these wells in mid-2016. One of these wells was a 9600-foot lateral that was drilled in less than 12 days from spud to total depth, which we believe to be the 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 three-well pad in Spanish Trail in 37 days from spud of the first well to rig release of the third well. In Martin County, we drilled a well with a 7500-foot lateral in less than 10 days from spud to TD. In addition to our continued efforts to drill wells faster, we've 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 three 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 million and $5.5 million for a 7500-foot well and between $6.5 million and $7 million 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 the 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 on 139 existing vertical high operating cost wells primarily in Howard County in the second half of 2015 while lowering the LOE. Slide 13 illustrates Diamondback's crude reserves, which increased 39% as of December 31, 2015 to approximately $157 million BOE. Additions replaced 465% of 2015 production with a drill bit F&D cost of $5.51 per BOE. Drill bit F&B declined by 50% from $11 per BOE in 2014 as we continue to decrease development cost and target the Lower Spraberry and 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 fourth quarter of 2015 was $39 million or $0.58 per diluted share. Diamondback's consolidated adjusted EBITDA for the fourth quarter of 2015 was $123 million, which is 11% above EBITDA in the fourth quarter of 2014 despite price realizations being significantly stronger in 2014. Our fourth quarter 2015 average realized price per BOE including the effect of hedges was $55. Diamondback continues to have peer-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 first three quarters of 2015. Also on that same slide, we show that Diamondback continues to be one of the leanest operators with G&A less than half that of the peer average for the same period. In the fourth quarter of 2015, our cash G&A costs were $1.06 per BOE while non-cash G&A costs were $1.40. During the fourth quarter of 2015, our capital spend for drilling, completing, and equipping our wells was $70 million. Our infrastructure costs were $5 million, and we paid $20 million on our non-operated property. The Company spent an additional $24 million on primarily bolt-on acquisitions during the fourth quarter 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 $250 million in cash and $500 million in undrawn revolver capacity, we have ample liquidity to fund our 2016 drilling program. Pro forma for proceeds from the equity offering, our net debt to annualized fourth quarter 2015 EBITDA is 0.4 times as shown on slides 15 and 16. Moving to slide 17, we provide our guidance for 2016. 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 6000 to 6500 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 million to $375 million for 2016. Turning to operating cost 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&A projection is $1 to $2, and our non-cash G&A is expected to be in the range of $1.50 to $2.50. We have forecasted our DD&A rate from $13 to $15, and production and ad valorem taxes are expected to be 8% of revenue. I will now turn to Viper Energy Partners, which recently announced a distribution of $0.228 per unit for the fourth quarter, 14% above the third 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 unit holders 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 $34.5 million drawn on its revolver. Now turning to Viper's guidance, we expect a production range of 6000 to 6500 BOE per day. On a per BOE basis, we anticipate cash G&A costs of $0.50 to $1.50 and non-cash G&A of $2 to $3 in 2016. We expect DD&A to range between $14 and $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 will 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 less than 2 times without accessing 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 maintained our unwavering focus on execution, continuing to push our advantage in low-cost D&C operations in peer-leading expense structure and remain transparent with our business strategy. Operator, please open the line for questions.

The press release made reference to opportunities for accretive growth given you guys are guiding to organic production flat at best I'm assuming that means you expect to be more active in the acquisition market. Can you comment on what you are seeing in the acquisition pipeline? Are these 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 a differentiator here or is Diamondback's efficiency advantage also something you expect to add material value in acquisition?

John, there's a lot of questions embedded in there. Let me talk 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 are not seeing a lot of announced trades on larger acreage blocks probably tells you that the spread between bid and ask is still relatively high and I believe the sellers probably have a price forecast that's above what the acquirers are looking for. The bigger sequel of 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 acquire and exploit company, so we’re increasing our efforts on the opposition fronts. We're really just continuing what we've always done, which is to look for accretive opportunities that we believe we can demonstrate that are better in Diamondback's hands than in somebody else's through our conversion process of rocking the cash flow. How the other elements that you are describing are trying to move around in the acquisition space, probably best answered by those guys, but Diamondback is committed to doing smart deals that are accretive and we believe that we are the right operator, and if we find the right rock we will generate the right returns for it.

Just moving to expenses on the quarter, aggregate LOE dropped despite the increase in volumes. It was pretty impressive. Your '16 guidance seems to imply you give most of that back though, was there anything one time that sort of aided 4Q results or is there maybe some conservativism built into 2016 LOE guidance?

Yes, just on any guidance in 2016, we don't typically build in 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 fourth quarter, Mike mentioned some in his prepared remarks but when we acquired our properties in Northwest Howard County kind of midsummer of last year, in our accrual process for accounted for expenses we were using the prior operator's run rate on expenses, and because our operations organization has had the opportunity now a couple of times to assimilate large high-cost vertical wells into our inventory, they really responded in a very quick fashion to get these wells operating like Diamondback expects. As a result, we kind of overshot what we were thinking expenses were going to be up in the third quarter and the fourth quarter was the beneficiary of that overshooting. So I would really characterize it as giving back any of the expenses we tend to try to hold onto every penny we ever pick up but that’s specifically what happened in the fourth quarter. We believe our guidance of $6 to $7 a barrel for 2016 is right down in the middle of the fairway.

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 model that they are not a big fan of giving multi-year forecasts out there. I can tell you from a general perspective if Diamondback was to run one to two rigs, our production is flat to slightly declining; if we were to run two 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 of each quarterly update but I think in a general sense that one to two rigs will be flat to decline and two rigs more flat to up sort of forecast what the future is going to look like. To make that statement though we are at the lower end of our rig cage, kind of that 1, 2 rig cadence to get to that $35 comment that I made.

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?

At the low-end of the CapEx guide we probably end up with 30 to 40 DUCs by the end of this year. And if we were at the higher end of that guide we probably end up with 10 or less DUCs.

Say, Travis just add onto that last question. When you look at the plan for this, but 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 on these new Glasscock, you mentioned obviously the very quick well you were able to drill up in Howard. How should we think about the entire plan under that kind of that lower for longer scenario or if you were going to upsize things a bit?

Sure. I will put the endpoint on it Neal. If we were to run two to four rigs, which would be towards the upper end of the guidance and of course, as I stated in my commentary, we would have to have some pretty good confidence in oil prices before we went to the upper end of the rig count. But if we were running three to four rigs, we keep the two rigs in Spanish Trail and we would have one rig in Glasscock, one rig in Howard and then if we moved the rig around we probably catch a well or two in Northeast Andrews County where we've had some really nice results. If you go to the lower end, I mean if we get all the way down to one rig like we talked about potentially in midsummer if commodity prices continue to soften from this point, that rig would be mostly the drilling obligations which would be heavily weighted towards Howard County where we've got three wells drilled and drilling our second three-well pad now and probably bouncing the rig occasionally in and out of Spanish Trail as well. So that's the way it looks Neal with the one rig all the way up to four rigs.

Lastly, you all have a unique advantage, as Tracy explained with Viper. I believe the shares have not rebounded as much as they might have with oil prices. You mentioned the potential for accretive acquisitions, and I’m curious if there’s a way to utilize Viper in this situation or if you plan to stick with your current approach in a higher interest environment. Is there anything else you can do with those?

Well of course without getting into any deal specifics we recognize that 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 is a co-bid strategy, Viper bidding alongside Diamondback or even Diamondback using the Viper as a form of liquidity in a transaction. We’re seeing increased interest in Viper units at these low commodity prices as people involve themselves that commodity prices may be bottoming out and beginning to recover. I guess I can't give you any deal specifics Neal, but I do think that there's a likelihood that some kind of transaction that Diamondback is involved in the future would include Viper ownership.

Travis, you detailed out what we could expect on the deferred completions front really for 2016 and a couple of different scenarios, but I'm just curious what you are doing right now, what the strategy is? Are you really completing wells? What are you doing with oil around $30? Thanks.

With oil below $30 a barrel as I laid out in one of those slides, I think slides 5 or 6, you know we’re actually deferring some completions right now. So we will 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 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.

Just kind of more lessons 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 move through these different pricing scenarios, should we assume that the rig count increases as you move through up through these levels or how should we interpret that slide?

We tried to lay this out as clearly as we could Gordon on rig counts; as oil price moves up with some confidence that it is going to remain there, we will pick those additional rigs up. I think the most likely scenario is the first lever we pull under recovered oil prices is working on those DUCs and then the second lever would be to stand up an additional rig. So in a general sense we've always talked about sort of whatever the first number on oil prices is about the number of rigs we're going to run. I think that still holds in slide 6.

And then regarding your 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; a joint bid or use of Viper as a source of liquidity or are you looking at standalone Diamondback bids? How do you weigh that as you look at these deals?

Gordon, again without giving a lot of commentary on what our exact acquisition bid strategy is, all of those things you just laid out are available to Diamondback as we try to do an accretive deal. I think it's deal specific and we will look at all of the combinations that you just laid out in order to create the greatest accretion to our shareholders.

I guess just one more on the M&A angle or ANDA 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 is a decent premium to the current strip. I was wondering if we can take that analogy, and you could help us try to apply that in the private market and you talk about the bid-ask spread being wide. What sort of price levels are maybe being applied as you look at these deals? What sort of price levels are being implied by the sellers sufficient to win a bid at this point?

I appreciate the interest behind that question. Again, I'm not going to talk a lot about how Diamondback views these things, but I 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. So if you have not seen any transactions occur on the acreage size, it is probably because most of the sellers are hanging on to the last amounts traded. I believe you can do your own reconnaissance on that, but somewhere north of $30,000 per acre. So I think we will have to wait and see Michael until you see some transactions come across the Board whether or not that gap is really closed.

I'm considering capital efficiencies in lower case scenarios, not just for your company but for the entire industry. How should we approach aspects like pad development in the most efficient way, while also considering the practicalities of maintaining leasehold agreements? Would you say that the lower end of the range you provided reflects those fixed costs and offers a perspective on capital efficiency? Moving forward, it will be necessary to significantly improve capital efficiency.

I'm going to answer the macro question and then specifically on the low-end, I'm going to let Tracy answer on the low-end side of the capital efficiency. On a macro view, the more rigs that you run, typically the more efficient your operations are because you are keeping a rig there on location longer and getting a three-well pad drilled, and you’re bringing in a completions and it is a more efficient process when you can keep a rig in the general area and let the drilling and completion cadence follow in an efficient manner. When you actually go to a world where you’re only running one rig you’re by definition giving up some of those efficiencies because where you might want to keep a rig on there for two months to get three wells drilled you might actually have to only drill one well there, and move the 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 now I've got about some 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.

On the low end, there is probably some efficiency loss, but to clarify, we have guidance of 30 completions. However, when we're operating at that low level, we will be drilling more wells than we complete, which results in capital being spent without reflecting in the well count. Additionally, with fewer rigs in operation, we will incur some rig penalties. Lastly, some wells that were started in 2015 will incur costs in 2016. Therefore, when you divide by 30 wells compared to the upper end of 70, it indicates lower capital efficiency, but that’s how our low end is functioning.

Last one on my end is just around the Glasscock cut wells. Is completion designs on those wells vary between themselves then relative to how you complete wells further west or any changes around that?

Yes, Michael on the first three well pad that we talked about that Mike talked about, first just again I'm going to reemphasize how pleased we’re with the early flowback data from those wells. I think they are at or above our expectations at each of the three intervals and we 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 that we try 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 on those Glasscock County wells and that gives us a better comparison. We didn’t talk about the two well pads that we've only been flowing back for about a week now. We actually increased the same concentration, the completion density on those two well pads so as we get the three well pad that's flowing back right now we get information out of that that's done with our traditional Midland County completion we will be able to compare it right next with a two well pad with the increased sand that we put there. So we think we are doing it kind of the smart way in terms of trying to assess the size of that when we kick in the full-scale development we will have the best recipe but I would tell you again just to reemphasize the Wolfcamp A, Wolfcamp B at or above expert rates actually has been the most surprising zone in Glasscock County because it appears to be as good as the Wolfcamp B and A and certainly better than the wells 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 exhibiting a similar profile to those in Midland County?

Yes, we put that well online about 3.5 weeks ago, so it is likely at its peak rate.

When we think about the 2150 to 2375 million CapEx range, how should we think about the commodity prices assumptions that are embedded into that guidance? Is that $25 to $35 range?

I believe the $25 to $35 range corresponds to one to two rigs, which would align you with the lower end of the CapEx range. If you consider the $35 to $45 WTI range, that indicates two to three rigs and would bring you closer to the upper end of the CapEx range. We analyze the production range to ensure we are accurately reflecting the breaks and CapEx reduction guidance.

When we look beyond 2016, do you see the Company eventually transitioning to two mount laterals? I know you are averaging 7500, but is it possible to reach 210,000 beyond 2016?

In general, we attempt to drill for as long as our geometry permits, and we have plans for the Board this year. We believe the capital efficiency is much improved, and we have shown this commitment. We always aim to drill longer, which is one of the reasons we are so enthusiastic that more than half of our wells will be of the 10,000-foot variety. Looking ahead to 2017, we are planning to drill longer. I am looking toward next month to extend this duration, but it is somewhat constrained by the geometry.

Just a last one for me in terms of service cost concessions from the service guys, do you still see some room there in 2016 or do you think we've gotten all we can get from those guys?

Certainly our business partners on the service side are under quite a bit of stress right now and I know that as long as they have vital equipment in their guard, 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 totally for planning purposes, and that's the way we are looking at it as well for planning purposes, I think the numbers that we gave you are good for the year. But it gets it will be downward pressure but we believe the cost kind of in right now.

Just dovetailing on what you mentioned the plans you have either one rig program or three, adjust with a copy the third rig you are looking to ask month, with two rigs with 1 B basically Spanish Trail and the other voting or just how you see that in the number two scenario?

I think we were trying to lay this out earlier as well but Jason with one rig that's going to be bouncing around for the various lease obligations mostly in Howard County. If we are running two rigs, one rig would be part one rig in Spanish Trail and then probably have one-quarter of that rig will be around in Glasscock or Howard County. But you are going to keep pretty much one rig in Howard County, most of the year and then any other rigs will be added to first Spanish Trail and then secondly to Glasscock County and Northeast Andrews County.

And on that, as you look at that holding the leases and Howard, is that a couple of years you would have to do that? Would you be ready merely done but by the end of this year or where you see that falling in the lower scenario?

Yes, that seems like a reasonable expectation for the next 12 to 24 months. We are taking measures to evaluate extensions that can help us delay drilling if necessary. For planning purposes, we intend to keep our rig in Howard County this year and next, as we believe it will be an economically viable option once we finish drilling the wells. Additionally, we had impressive test results in Glasscock County that showed competitive returns, and we are positioned to invest more capital to enhance returns for our shareholders.

I wanted to go back to the table you guys have regarding the economic locations of the various price tags and looking back to your past that's it looks like you about doubled your week even inventory in that were you should price tags so just wanted some color on that if that's exclusively related to the lower well cost assumptions that you guys have been able to Julie be or maybe there is some increased confidence about well performance in some newer areas or some newer zones you guys are adding there?

Certainly we are more confident everyday we get well test actually Glasscock County and soon-to-be Howard County, but specifically Jeff though, the well cost from $6 million per well for 7500-foot lateral, the last time you visited our last quarterly call, makes a big difference in the number of locations that are economic.

Not considering the details from your previous report, can you provide more information on the improved well performance from the Lower Spraberry? Were the watering out issues something you anticipated? I'm curious about how you view these wells in comparison to the wider spaced wells that some are discussing.

I know we have got a lot of different curves on that slide. We show one of the curves for the 500 wells without the five well pad, and you can see putting much mimics the result of the wider spacing. Specifically to the five well pad we were a little surprised. The operator came in and drilled some wells that watered out really watered out several of our wells on our five-well pad. Two of those wells are lead times eventually affecting the end of the curve. One of those wells we drilled lighter 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 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 had started to recover on are recently back to the rates that we projected. I know you just look at it overall and it looks a little concerning but when you actually step back and look at the individual wells and how they were covered I would say the results looked pretty encouraging at this point. On the wells that we're drilling now we are continuing to use the 500-foot spacing in Spanish Trail.

Then last one for me on the completion side; see some other operators getting some encouraging results on some different completion optimizations. Can you elaborate on some increases in Glasscock? Just wondering how you guys are looking at progressing throughout the year with different testing on the doc. or concepts you guys are looking at internally on the completion front?

Jeff, we spend a lot of time only analyzing results but also analyzing what said publicly from other operators and we try to incorporate these practices and learnings from other operators quickly into our business so I think you are 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. Certainly now when costs are as low as they are on pressure pumping now is a good time to experiment with that. There's a few things though that we're pretty confident we won't be trying and that is that we've always been, even since 2012, a slick water shop and we intend to continue there on slick water fracs.

Just hoping back to the 2016 guidance range of 32,000 to 38,000 per day. Given it was a strong fourth quarter at about 37 and change. I know you don't give guidance on a quarterly basis but could you just directionally walk me through maybe in the low price scenario if you do end up going to one rig in a second quarter just how long it's progressed throughout the year?

There is a reason we don't provide quarterly guidance due to the significant fluctuations that can occur. For instance, bringing on a three-well pad like we did in Glasscock County, which is producing nearly 4000 barrels a day, can greatly affect a single quarter. Therefore, it's quite challenging for me to accurately predict quarter-over-quarter production. Generally, if you have one to two rigs operating, you can expect flat to declining production. However, if you have two or more rigs, your production will likely increase, and this remains true regardless of whether it's now or in two years. That's how we perceive changes in production.

And then switching over to Howard County looking forward to getting the results in the middle of the year. Could you just contrast what the Midland acreage in terms of which intervals are most prospective and maybe talk to how the geology changes as you head east of Howard?

Bob, based on other operators results in the area that 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 lot of Wolfcamp B results but generally the B thickens as you move to the West more basin work, 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 see out of the industry because most of their wells are closer to the shelf or the B.

But has there been deep enough cut on the services side to where you are starting to see some degradation with crews and just would love your thoughts if that's going to be a challenge when prices rebound and maybe if you even if you guys have a price of where maybe that does become a concern, any service companies do start getting some pricing power. Would just love your thoughts on that.

Yes, Ben, our business partners on the service side as I pointed out earlier, they are under quite a bit of distress right now and they are very smart individuals and running their business and they know the importance of keeping good crews and good equipment. Regardless of our pace of activity we expect to end 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 cannot see right 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 recovery oil price that we will 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 right now there is sure a lot of surplus equipment around both on the pressure pumping and on the drilling rig site.

Can you speak further to how quickly a DUC can be converted to a well that's producing? Questions just asking to get a better sense of how quickly you can capture a steeper recovery on the oil curve if that were to materialize.

The first step is to contact your pressure pumping provider to check their availability and pricing. Currently, costs are low and availability is high, which means you can start working on the DUCs immediately. There are preliminary tasks to handle, such as accumulating stimulation fluid and preparing the site for completion, but those are routine for us. When we are ready to proceed, as I mentioned earlier, we will begin with the DUCs. With a fully dedicated crew, we can manage about four to five wells per month for each dedicated group. This allows us to quickly address the backlog of uncompleted wells within a quarter.

And then lastly, how much further east off your Glasscock County lease line would you go to acquire more acreage assuming such acreage is available?

We like where our acreage is right now; I don’t think moving east from our position.

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.