Diamondback Energy Inc (FANG) 2015 Q4 法說會逐字稿

Good day, ladies and gentlemen and welcome to the Diamondback Energy and Viper Energy Partners fourth-quarter 2015 earnings conference call.

(Operator Instructions)

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.

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 markets 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, 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 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 than12 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 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.

Drillbit 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 rate.

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 return 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 expected DD&A to range between $14 and $16 and gathering and transportation of $0.25 to $0.50 with production and ad valorem taxes of 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.

(Operator Instructions)

John Nelson, Goldman Sachs.

Good morning and thank you for taking my questions.

Good morning, John.

The press release made reference to opportunities for accretive growth.

Given you 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 assets -- 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 expect to add material value in an acquisition?

John, there's a lot of questions embedded in there.

Let me talk from it from a high level from Diamondback's perspective.

What I talked about January when we did our equity raise is that we've 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 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.

Then the bigger type C corp combinations, we continue to evaluate different opportunities there 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 are not increasing our efforts on the acquisition front.

We 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.

How the other elements that you are describing are trying to move around in the acquisition space, you're probably best to answer 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.

That's helpful.

Just moving to expenses on the quarter, aggregate LOE dropped despite the increase in volumes.

It was pretty impressive.

Your 2016 guidance seems to imply you give most of that back through.

Was there anything one time that aided 4Q results, or is there maybe some conservatism built into 2016 LOE guidance?

Yes, just on any guidance for 2016, we don't typically build in conservative guidance at all.

We try to put are best estimates forward and communicate that in a transparent fashion.

Now, specifically to what happened in the fourth quarter, Mike mentioned in some of his prepared remarks that when we acquired our properties in northwest Howard County 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 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 result, we overshot what we were thinking expenses were going to be up in the third quarter, and the fourth quarter was the beneficiary of those -- of that overshooting.

I wouldn't 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 $67 a barrel for 2016 is right down the middle of the fairway.

Perfect.

Congratulations on the quarter.

I will let somebody else hop on.

Thanks, John.

Michael Glick, JPMorgan.

Just on your flat $35 a barrel case, can you give us some color on what the Company would look like a couple years out?

Obviously Mike, we've got the Company modeled out there.

I am 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 is 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.

We're going to try to model the Company and give you updates, each quarterly update.

But I think in a general sense that one to two rigs 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 were at the lower end of our rig guage, that one, two rig cadence to get to that $35 comment that I made.

Got it.

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 would probably end up with 30 to 40 DUCs by the end of this year.

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.

Neal Dingmann, SunTrust.

Good morning, Travis.

Just add onto 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 obviously the very quick well you were able to drill up in Howard.

How should we think about the entire plan under that lower for longer scenario where if you were going to upsize things a bit?

Sure.

I will put the endpoints on it, Neal.

If we were to run two to four rigs, which would be towards the upper end of the guidance -- and 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 two to four rigs, we'd keep the two rigs in Spanish Trail and we'd have one rig in Glasscock, one rig in Howard.

And then if we moved a rig around, we'd probably catch a well or two in Northeast Andrews County where we've had some really nice results.

If you are at the lower end, 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 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.

Then you'd probably be bouncing a rig occasionally in and out of Spanish Trail, as well.

That's the way it looks, Neal, with the one rig all the way up to four rigs.

That clarifies.

Then lastly, you all have unique benefit, obviously, went through and Tracy went through with Viper to have that.

Obviously to me I think the shares certainly with oil prices have not rebounded maybe where they once could here.

Do you anticipate -- you mentioned with accretive acquisition, I was wondering is there a way to use Viper at all?

Or will you continue -- if this environment continues, you will continue how you've been with the higher interest with it, or is there anything else you can do with those?

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 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.

I cannot give you any deal specifics, Neal, but I do think there's a likelihood that some transaction that Diamondback gets involved in in the future would include Viper ownership.

Nice to have them.

Thanks, Travis.

Thank you, Neal.

Mike Kelly, Seaport Global.

Thanks, good morning.

Travis, you detailed out what we could expect on the deferred completions front really for 2016 and a couple different scenarios, but I'm just curious what you are doing right now and what the strategy is.

Are you really completing wells, what are you doing with oil teetering around $30?

Thank you, Mike.

With oil below $30 a barrel as I laid down in one of those slides, I think slide 5 or 6, 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 four to five DUCs a quarter to get to that number.

That's how we are 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.

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.

(Laughter)

Gordon Douthat, Wells Fargo.

Good morning, everybody.

Just 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 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 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 on under recovered oil price is working on those DUCs, and then the second ever would be stand up an additional rig.

So in a general sense, we've always talked about whatever the first number on oil price is about the number of rigs are going to run.

I think that's still holds in slide 6.

All right.

Thank you.

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 bids, or 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 is 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.

All right.

Thanks again.

Michael Hall, Heikkinen Energy.

Thanks, good morning.

One more on the M&A angle or A&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 is a decent premium to the current strip.

I was wondering if you could 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 price levels are maybe being implied as you look at these deals -- what 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 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 what the last amount's 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 will have to wait and see, Michael, until you see some transactions come across the board whether or not that gap is really closed.

Fair enough.

Figured it was worth a shot.

Also I'm just trying to think through -- capital efficiency is in the low case scenarios, not only for yourselves but across the industry.

How do we think about things like pad development and that might be the most efficient way and 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 -- the low end of the range that you provided is exhibiting those fixed costs flowing through and provides a range of capital efficiency in terms of how we think about moving forward, things will really ratchet higher from a capital efficiency standpoint?

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 are bring the completions in.

And it is a more efficient process when you can 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 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 -- you may only have the time to drill one well there and move the rig to another location so you give up some efficiency there.

That's in a macro sense.

I'd rather be more efficient running more rigs, but 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.

On the low-end there, we do have probably some efficiency loss there.

But to clarify what's going on, we have the guidance out there of 30 completions, but when we are running that low, we are actually going to be drilling more wells than we complete.

So there's capital being burnt there, and you are not really getting it in the well count when you are 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 -- there's some wells that you start in 2015 that you end up paying for in 2016.

So again, when you are dividing them just by 30 wells versus the upper end of 70, it shows a lower capital efficiency in the amount.

That's how our low-end is working.

Okay, that's helpful.

Makes sense.

Last one on my end is just around the Glasscock wells.

Do the completion designs on those wells vary between themselves, and then relative to how you complete wells further to the west?

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 are 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.

What we did when we moved into that area, we wanted to make sure that we try to get the best -- 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 did not talk about the two well pads -- that's a Wolfcamp a and Wolfcamp B -- 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 the two-well pad with the increased sand that we put there.

So we think we are doing it the smart way in terms of trying to assess the science of that.

When we kick into 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 expectations and the Lower Spraberry 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 in the 15-mile radius around there.

Really excited about the Lower Spraberry.

That Lower Spraberry well, has it peaked yet or is it exhibiting a similar profile to those in Midland County?

Yes, it is probably -- we put that well on sub pump about 3. 5 weeks ago, so it is probably at its peak rate.

Okay.

Great.

Appreciate the color.

Kashy Harrison, Simmons & Company.

Good morning and thanks for taking my question.

When we think about the $250 million to $375 million CapEx range, how should we think about the commodity price assumptions that are embedded into that guidance?

Is that a $25 to $35 range?

I think the $25 to $35 range, that's the one to two rigs, and that's going to put you at the lower end of that CapEx range.

If you are in the $35 to $45 WTI range, that's two to three rigs and that's going to push you towards the upper end of that CapEx range.

We tied that back cash into also the production range that we did, so we are intellectually honest between rigs, CapEx spend and production guidance.

Okay.

Thanks for that.

When we look beyond 2016, do you see the Company eventually transitioning to a two-mile lateral program?

I know you are running 7500 on average, but could that go to 10,000 beyond 2016?

In a general sense, Kashy, we try to drill as long as we can that lease geometry allows us, so we 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 were so excited about Howard county is that over half of those wells as we develop there are going to be of the 10,000-foot variety.

I'm not looking into 2017 to drill longer.

I'm looking into next month to drill these wells longer, but it is somewhat limited by lease 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, they're under quite a bit of a distress right now.

And I know that as long as they have idle 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 tell you 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 if oil prices continue to soften, you could see a little bit of downward pressure.

But we believe the costs are in right now.

All right.

That's it for me.

Thanks for your time.

Really appreciate it

Thanks.

Jason Wangler, Wunderlich Securities.

Morning, Travis.

Just dovetailing on one, you mentioned the plans you have either a one-rig program or three.

With you dropping the third rig or looking to next month, with two rigs would one be a basically Spanish Trail and the other floating or just how you see that in the two scenario?

I think we were trying to spell that 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 -- park one rig mostly in Spanish Trail, and then probably half to three quarters quarter of that rig will be moving around even in Glasscock or Howard County.

But you 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.

Okay, thank you for that.

As you look at that holding the leases on Howard, is that a couple of years you would have to do that?

Would that be primarily done by the end of this year, where you see that falling in the lower scenario?

Yes, it is probably a fair statement for the next 12 to 24 months.

Of course, we are doing things also.

If we were in a protracted low oil price, we 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 the next we will keep a rig up there in Howard County, which we haven't been able to demonstrate it to yet until we complete these wells, but we think that will be good economic proposition, as well.

Then also now with the really outstanding well test we had in Glasscock County, now we've got real competitive returns down there, as well, too So we've got some abilities to make our capital more fungible as we look at returns to our shareholders.

I appreciate it, thank you.

Jeff Grampp, Northland Capital Markets.

Hello.

Wanted to go back to the table you have regarding the economic locations of the various price decks.

And looking back to your past decks, it looks like you about doubled your breakeven inventory in that $40-ish price deck.

So just 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 you are adding there?

Certainly we are more confident, and every day we get well tests, and 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 million per well for 7500-foot lateral, the last time we used this in our last quarterly call, down to $5.25 million.

Makes a big difference in the number of locations that are economic.

Okay, thanks for that.

Then shifting to looking at the back end of your deck here, the updated well performance from the Lower Spraberry downspacing tests.

Maybe if you can get a little bit more color about that five-well multi-pad where you had some watering out issues it looks like, is that something that you had expected?

Are these wells performing in line?

Just wondering how you are looking at these wells relative to the really staunch out performance we saw from some of those earlier wider spaced wells?

I'm going to let Russell -- he's in the room today.

I'm going to let Russell answer that question.

Yes Jeff.

I know we have a lot of different curves on that slide.

It's going to make it a little bit confusing.

But we show one of the curves for the 500-foot spaced wells without the five-well pad, and you can see it pretty much mimics the result of the wider spacing.

Specifically to the five-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 five-well pad.

Two of those wells are light time, so that is affecting the end of the curve.

One of those wells of our five 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 had started to recover and are essentially 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 recovered, 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.

Super helpful color, Russell.

Then last one for me on the completion thoughts, seeing some other operators getting some encouraging results on some different completion optimization and you talked yourselves about some increased proppant in Glasscock.

Just wondering how you are looking at progressing throughout the year, different tests you might have on the dock or concepts you are looking at internally on the completion front?

Jeff, we spend a lot of time not only analyzing our 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 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's 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 is that we have always been even since 2012, we've always been a slick water shop, and we intend to continue doing slick water fracs.

Great, thanks for the color.

Bob Bakanauskas, GMP Securities.

Hello, good morning.

Thanks for taking my question.

Just hopping back to the 2016 guidance range of 32,000 to 38,000 BOE per day, given it was a strong fourth quarter at about 37,000 and change.

I know you don't give guidance on a quarterly basis, but can you just directionally walk me through maybe the low price scenario if you do end up going to one rig in a second quarter, how volumes progress throughout the year?

I think again Bob there is a reason we don't give quarterly guidance, because there's so much fluctuation when you can bring on, like we did in Glasscock County, you bring a three-well pad on that's doing almost 4000 barrels a day, that can materially impact one quarter.

It is really difficult for me to try to tell you-- I can't tell you exactly what quarter over quarter production is going to do.

Generally, Bob, if you've got one to two rigs running, you are going to have flat to declining production.

If you're running two or more rigs, your production is going to build.

And that statement holds regardless of whether it is now or two years from now.

That's how we view production changing.

Okay.

Understood.

Switching over to Howard County, looking forward to getting the results the middle of the year.

Can you contrast the Midland acreage in terms of what intervals are most prospective and maybe talk generally about how the geology changes as you head east in Howard?

Sure.

Bob, I'm going to let Russell answer that question.

Bob, 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 has not been a lot of Wolfcamp B results, but generally the B thickens as you move to the west more 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 probably going to be better than what you've seen out of the industry because most of their wells are closer to the shelf or the B fence.

Got it.

Very helpful, thanks.

Joel Musante, Euro Pacific Capital.

Thanks.

All of my questions have been answered, thanks.

Appreciate it.

Ben Wyatt, Stephens.

Good morning 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 are starting to see some degradation with crews?

And just would love your thoughts if that's going to be challenge when prices rebound and maybe if you even have a price of where maybe that does become a concern and these service companies do start get maybe 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 and demand good service for a fair price, and the service companies our business partners respond accordingly.

When recovery occurs, when activity starts to ramp up, there probably will be some things exposed that you cannot see right now under a much slower development activity.

But we think 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's sure a lot of surplus equipment around both on the pressure pumping and on the drilling rig side.

That works.

I appreciate that.

That was it for me, thanks, guys.

Dan McSpirit, BMO Capital.

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 to get a better sense of how quickly you can capture a steeper contango in the oil curve if that were to materialize.

Dan, the first thing is you place a call into the pressure pumping provider and you find out what their availability is and what their cost is, and right now costs are low and availability is high.

In theory you can go to work on the DUCs right away.

There are some things we have to do on the front end of that like accumulation, stimulation fluid, making sure the locations are prepped for the completion.

But those are things that we do on a day in and day out basis.

So really when it is time to mash on the accelerator as I pointed out earlier, we will start on the DUCs.

And with a fully dedicated crew, we can get about -- how many, Mike, months can we get with a dedicated crew?

You can probably get four or five wells.

You can get four to five wells a month per dedicated crew.

You can start to eat into -- in a quarter, you can start to eat into your drilled but uncompleted backlog pretty quick.

Okay, great.

Helpful.

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, and I don't think you'd see us moving east from our position.

Very good.

Thank you.

Have a great day.

Thanks, Dan.

(Operator Instructions)

Sam Burwell, Canaccord Genuity.

Good morning.

I was wondering if you can quantify a little bit the share of completions this year that would be 10,000-foot laterals, then if that share or that percentage would change meaningfully depending on the activity scenarios you end up with?

Probably about 40% or 50% would be 10,000-foot laterals, and through time I think that percentage is probably going to increase.

As we trade acreage, core up more of our acreage, you will see those lateral links continue to increase over time.

Okay great.

Appreciate the color.

And to sneak one more in, hedging.

You are still unhedged.

I was wondering what would the curve have to look like especially in say 2017 for you guys to consider laying on some hedges?

That's a good question, Sam.

It is one we still struggle with every day.

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, probably so.

But that being said, we also now -- we believe we are going to be able to participate in the 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 lead us maybe to start thinking about hedges somewhere north of where it is right now.

I think I saw a quote this morning that next year's hedges are around $40 a barrel, so we probably need something north of that.

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 is 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 you pointed out cash on the balance sheet from our equity raise that is in the way looks like a hedge, as well, so I think we are in pretty good shape.

All right, makes sense.

Thanks.

(Operator Instructions)

David Meats, Morningstar.

Hello.

Thanks.

Most of my questions have been answered, but one last one on the table on slide 6. Looking in the $65 to $75 scenario, you have got 2600 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 upgrade those 200 locations and make them work at the $55 to $65 level?

Is there something you can do or some circumstances that would make that happen?

Yes, I think those wells are generally short lateral wells that take a higher price to make economic.

And as I indicated before, oil companies are working on data traits to core up their acreage just to drill longer laterals.

So that's really what it is 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.

At this time, I would like to turn the call back over to Travis Stice 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.

Good day.