Adam Lawlis - IR Travis Stice - CEO Tracy Dick - CFO, SVP, Assistant Secretary

Mark Lear - Credit Suisse David Amoss - Iberia Capital Mike Kelly - Global Hunter Securities Gordon Douthat - Wells Fargo Jeff Grampp - Northland Capital Markets Adam Michael - Miller Tabak Jeffrey Connolly - Mizuho Securities Jamaal Dardar - Tudor, Pickering, Holt & Company Jason Wangler - Wunderlich Securities Joseph Reagor - ROTH Capital Partners

Thank you, Candice. Good morning and welcome to Diamondback Energy and Viper Energy Partners joined third quarter conference call.

During our call today, we will reference an updated investor presentation which can be found on our website. Representing Diamondback today Travis Stice, CEO; Tracy Dick, CFO; as well as other members of our executive team.

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 we found in the company's filings with the SEC. During our call today, we will reference certain non-GAAP financial measures, which we believe provide useful information for investors.

We include reconciliations of those measures to GAAP in our earnings release. I will now turn the call over to Travis Stice.

Thank you, Adam. Welcome everyone and thank you all for listening to Diamondback's and Viper Energy Partners' third quarter 2014 conference call.

The horizontal shale revolution has resulted in tremendous growth in oil production especially here in the Permian Basin. Diamondback has drilled over a 100 horizontal wells in the last two years and I'm proud of the role Diamondback has played in the Midland basin.

As we have experienced in the past, the service sector has responded to this production growth and increased activity with increasing costs while at the same time, we've experienced a marked declined in commodity prices. Diamondback has never been about growth for growth sake rather, we have always sought to align our stockholders with our strategy of returns and cash flow growth.

Our stockholders have been rewarded by investing in a company that consistently delivers the highest cash flow margin with the lowest cost and expense structure, best execution and capital discipline. We will enter 2015 running five horizontal rigs consistent with previously stated plans.

But, if commodity prices haven't improved or service costs have not declined Diamondback will respond by drilling fewer wells in 2015 than initially anticipated. However, we intended to continue to run two horizontal rigs on our Spanish Trail acreage consistent with guidance from Viper Energy Partners.

Our decision to maintain or possibly reduce our current rig count rather than increase it as previously contemplated which I call are deferred acceleration plan will be based on our goal of maximizing return on capital and minimizing debt until we can get a more attractive rate of return on our assets for our stockholders. I want to emphasize that the quality of our inventory is the best it has ever been in our history.

In 2014, we added nearly 600 gross horizontal locations in prime positions in the North Central Midland basin. We are able to maintain our leases with the one or two rig program.

Under this deferred acceleration plan Diamondback expects to become cash flow positive during the second half of 2015 further strengthening on already strong balance sheet with minimal leverage. If we choose to defer acceleration, we will be preserving high rate of return horizontal wells for better market conditions and Diamondback will be in a better position to flex its strong balance sheet to make accretive acquisitions or to resume inventory acceleration when better market conditions return, which we believe they will.

Since Diamondback owns roughly 88% of Viper Energy Partners, we also have the unique ability to use Viper as a liquidity vehicle if needed. Dating back to before its IPO, Diamondback has had a consistent strategy of managing the Company by exercising capital discipline and allocation of resources.

Now, I will focus on specific operational details from the quarter, I will be referring to the updated company presentation found on our website. During the third quarter, Diamondback continued its production growth by growing volumes of 178% as compared to the third quarter of last year and up 16% from the prior quarter.

This significant ramp in production year-over-year would not have been possible without approximately 90% of our CapEx expand dedicated to horizontal development. We continue to expect Diamondback to grow production by nearly 150% in 2014 as compared to last year.

This would mark the second consecutive year of nearly 150% production growth. As reported last month, Viper realized an increase in production of 39% from the prior quarter.

A large component of Diamondback's success is attributed to drilling the Wolfcamp B shale. Of the approximately 105 horizontal wells drilled since we began almost 90 have targeted the Wolfcamp B.

What's really encouraging from the testing we have done to-date is that the Lower Spraberry appears to be outperforming the Wolfcamp B across our acreage. We have always said that the Spraberry is not only the most continuously deposited but that it also contains the most oil in place.

Slide 7 shows a table of Diamondback's Lower Spraberry wells to-date. In Midland County, the Spanish Trail Northwest 2507 Lower Spraberry recorded a peak 30-day rate of 1405 boe's a day from 5257 foot lateral.

This translates into 267 boe's a day per 1000 foot of completed lateral, which rivals the Gridiron Wolfcamp B well we discussed last quarter as one of the best wells in the Midland basin. 30 miles further north in Martin County, we completed the Mabee Breedlove 2301 Lower Spraberry with the peak 30-day rate of 779 boe's a day from a 6454 foot lateral.

We believe this well is the northern most publicly reported test of the shale. As reported last quarter, the Neal F unit number 6 Lower Spraberry well in Upton County, the industry's first Lower Spraberry horizontal test in the county had a peak 30-day rate of 743 boe's per day from 6,800 foot lateral.

This well is over 50 miles south of the Spanish Trail acreage. The distance from our acreage in Northern Martin County to Upton County is over 80 miles illustrating the tremendous potential of this Lower Spraberry deposition.

When you refer to Slide 8, most of our current results are significantly outperforming our 650,000 boe two stream Lower Spraberry type curve and we are optimistic that this success can be replicated across a larger portion of our acreage. On Slide 9, we show stratigraphically how the Lower Spraberry looks across our acreage position.

Login core analyzes indicate fairly consistent reservoir quality in the Lower Spraberry shale from Southwest Dawson County extending South onto our Upton County assets. Slide 10 shows other notable results from the quarter including Diamondback's first operated stacked lateral test in the Wolfcamp B in Lower Spraberry in Midland County from the Gridiron number one and the Gridiron number two Lower Spraberry.

The Wolfcamp B well is still flowing naturally while the Lower Spraberry well is on ESP. The two wells have a combined rate to-date of nearly 3000 boe's a day from two laterals that average just shy of 9200 feet.

Briefly switching gears to Viper, development of Spanish Trail is a win-win for both entities as Spanish Trail is the most economic prospect in Diamondback's portfolio. A continued organic production growth is expected for both Diamondback and Viper.

As a reminder, Viper's mineral barrel has no direct operating or capital expenditures associated with it. Slide 14 illustrates the difference between mineral interest and working interest operating margins.

We continue to have best-in-class low operating expenses among our peers in the Permian basin. But, with nearly 300 gross vertical wells acquired this year, we have seen an upward migration in least operating expenses.

We fully expect this trend to reverse as we optimize these wells consistent with our low cost efficient practices. Slide 6 shows that while our LOE per barrel of oil equivalent was $7.27 during the quarter, it would have been $6.19 after excluding the effect of the acquired properties.

We are reiterating our LOE guidance for the year between $6 and $7 a barrel. Our low cost structure combined with high oil cuts continued to drive peer leading cash margins and you can see graphically on Slide 5 performance relative to our peers and the positive historical trend.

With these comments complete, allow me to turn the call over to Tracy.

Thank you, Travis. Diamondback had a nice quarter.

Our net income for the quarter was $43.7 million or $0.79 per diluted share. After adjusting our third quarter earnings for net commodity derivative gain $14.9 million and netting out the related income tax effect, our adjusted net income was $34 million or $0.61 per diluted share.

Our production for the third quarter was approximately 20,636 boe a day. These volumes generated revenues in the third quarter of $139 million.

Volumes up almost 16% and revenues up over 9% from the prior quarter. Our average realized price before the effective hedges for the third quarter was $73.28 per boe and our average realized price including the effective hedges for the third quarter was $72.48.

Diamondback's adjusted EBITDA for the quarter was $111.1 million, that is up about 8% from the prior quarter. Turning to cost, our LOE was $7.27 per boe in the third quarter.

As Travis mentioned excluding the effect of recent acquisition LOE for the quarter would have been $6.19. We do anticipate that our LOE for the year will be in the upper end of our guidance of between $6 and $7.

Our general and administrative cost came in at $3.42 per boe for the third quarter. This includes non-cash equity based compensation excluding all of our equity compensation G&A costs are $2.33 per boe.

The [dollar nine] [ph] spread includes non-cash equity issuances from Viper Energy Partners of $0.47 with the remainder attributable to Diamondback. We also have laid out our details of our current hedge position in last night's earnings release.

We currently have about 9000 barrels a day hedged at approximately $95 for the remainder of 2014. We also have over 10,000 per day hedged in 2015 for approximately $88.

In the third quarter of 2014, we generated $92.3 million of operating cash flow and $97.1 million of discretionary cash flow or $1.66 and $1.75 per diluted share respectively. During the third quarter of 2014, we spent $103.3 million for drilling completion and infrastructure.

Additionally, we spent approximately $528 million on lease-hold acquisition, which we primarily funded with the equity offering closed back in July. As we look ahead to the end of the year we expect our calendar year drilling and development capital to fall at the upper end of our guidance of between $425 million and $475 million.

As of September 30th, we had drawn $140 million on our secured revolving credit facility. Our agent lender approved a borrowing base increase of 114% to $750 million.

We have elected to limit this commitment to $500 million which provides us a plenty of liquidity. We estimate our year end debt to EBITDA will be less than 2x.

I will turn briefly to Viper Energy Partners, which announced last night a cash distribution of $0.25 per unit for the period from June 23 through September 30, 2014. During this period, adjusted EBITDA was $21.4 million and production increased 39% quarter-over-quarter to 3400 boe per day.

Viper has no debt and an undrawing revolver of $110 million following the September 2014 public offering. With my comments complete, I will turn it back over to Travis for his closing remarks.

Thank you, Tracy. To summarize, we have continued validating the enormous stack to pay potential here in the Permian basin by developing the Lower Spraberry.

Early Lower Spraberry results appeared to be even better than the Wolfcamp B which notably has driven the tremendous success Diamondback has achieved during the past couple of years. We maintain our laser like focus on well cost and expenses and continue to deliver cash margins per barrel and low expenses at the top of our peer group.

We will monitor market conditions closely as we enter into 2015 and are prepared to implement our plan to defer acceleration if warranted consistent with our practice of capital discipline becoming cash flow positive next year under a deferral plan with a strong balance sheet would put Diamondback in a very favorable position to capitalize on opportunities or to resume inventory acceleration under better market conditions. I believe we continue to deliver results and stockholder returns that are among the best in the industry.

Before I call for questions, I want to acknowledge our employees for all they have accomplished so far this year and especially welcome those employees that are new to Diamondback. We crossed our two year anniversary as a public company in October and I want to thank each of the almost 100 employees of Diamondback for their contribution to our success.

It has been an amazing ride since taken the company public in 2012 and I firmly believe our best is yet to come. Operator, please open the call to questions.

Just wanted to just touch on some of the comments in the press release from you guys on CapEx in 2015. I know it's early and others have just made comments about well cost and looking for cost to come lower and clearly the outlook for oil is pretty uncertain.

But just, any commentary you can give around rig assumptions, what you might be doing, clearly some great results in the Lower Spraberry, would you likely be high-grade again drilling a lot more Lower Spraberry wells in a lower price environment, just a color around that would be great.

Sure, Mark. Let me take those in reverse.

Specifically to the Lower Spraberry, we got a half a dozen or so well results that are significantly outperforming our type curve and obviously, that outperformance drives better rates of returns for our investors as well. So while we've not finalized our plans in 2015, it makes a lot of sense for us to try to emphasize development of Lower Spraberry.

Specifically the rig count and cadence for next year, I know that that's an important question a lot of analysts' minds right now and understand why you guys need to have an answer to that. But specifically to rigs, I want to remind our audience that that rigs are part of the equation but because we drill so many more wells on an annual basis than most of our competitors, it's really about wells next year.

And we've got some optionality as we look into 2015 to pin in our market conditions on how many wells that we are going to drill. And I've tried to outline that as best we understand it right now.

But, we got to see service cost need to be recalibrated in conjunction with commodity products has declined $25 or $30 a barrel in the last 100 days. So we've got to get better clarity on what those two events are going to look like before we finalize our plans into 2015.

And then lastly Mark, we've got a Board meeting early December where I'll be outlining specifically all of these different options that are still in front of us in 2015.

That's great. Really helpful.

I guess when you are looking at particularly Lower Spraberry performance outperforming the type curve, I know you have also talked about Wolfcamp B performance similarly outperforming, how would you say at this stage Wolfcamp B wells are tracking versus type curve as well?

Yes. I think if you go back in investor presentation in the appendix section, we've got some updated performance curves in there.

But, I will say in general sense, we are pleased in the outcome of the Wolfcamp B wells whether at or above our current type curve performance. Russell is going to sit down with Ryder Scott here at the end of the year and we will go through the technical exchange with the reserve auditors and then following that reconciliation we will be able to update type curve not only the lower – not only the Wolfcamp B but also and perhaps even more importantly the Lower Spraberry.

It's great. And just to looking back up to 2015 as -- just thinking about how you try and delineate some of the other layers next year, are you still looking to the peers to do a lot of that work for you or do you expect to do some more client drilling other zones as well?

Yes, Mark. I think you've always heard us talk about being fast followers and the industry is real good about putting forth publicly the results in different zones.

So I think that's certainly a prudent approach for our signs as to let the other -- let our peers do a lot of drilling in these other zones. I think certainly under the deferred acceleration plan that I referenced that would be really focused on Lower Spraberry and Wolfcamp B.

If we were to accelerate our inventory at the other end of the spectrum, you might see us in the second half of the year perhaps testing the Wolfcamp A. But as it stands right now Mark, we really like the results we are seeing in the Lower Spraberry and the Wolfcamp B.

Just one quick from me, Travis, if you don't mind can you go into a little bit more detail on what the cost trends you're seeing from -- what are the services guys putting in front of you for '15 today at lease order of magnitude? And then what do you need to see before you get more bullish on the service cost and possibly consider going up on the rig count again even in a lower commodity environment?

Yes, David. That again is a pretty complicated question.

I can you tell that probably year-to-date on the service side, we are seeing cost in some portions of our business up as high as 20%. I know that prior to this recent pull back some of the service sector was even trying to push through on another 10% increase on top of that effect first of the year.

So that would be on some aspects of our business, the cost increase of almost 30% year-over-year while at the same time our commodity prices off $25 or $30 a barrel. So there is not a number that I can really give you that says hey, it's got to come down to this.

And then I'll get back to work because it's really a function of not only well results like Mark was asking about, but it's also where the service costs are ultimately going to be recalibrated with this oil price. And understandably it goes up very, very fast, cost of goods and services and understandably it comes down a little bit slower and that's what we are seeing around now.

So we are communicating with all of our business partners across the full spectrum to ask them to make sure that they are looking at their side of the business as well as ours in response to a low commodity price. So it's really a combination of a bunch of different factors that will dictate future plans for Diamondback.

Okay and just one follow-up, I mean, are there components of that service cost where you are seeing the substantial amount more inflation than others, what are the I guess the biggest concerns going into next year?

Well, if you look at the pressure pumping side of the business and certainly not just to single out one aspect of our total spend because we look at the full spectrum. But pressure pumping through the years probably been the single most -- single biggest spend increase.

But closely behind that you are seeing cost of rigs grow up as well. So when you look at pressure pumping and drilling rigs those are pretty -- too big pretty large tickets on a well.

Yes, Travis. You guys posted a great production number in Q3, looks like you are now well ahead of the midpoint of your full year guidance, so that 17,000 to 19,000 a day.

So wondering if there is anything in Q4 that we should be aware of maybe makes you reluctant to increase that range. I know you guys have been in no other transition to more pad drilling if that's it or are you guys just being conservative here?

Thanks.

You bet, Mike. If you look specifically into fourth quarter, we continue to migrate most of our wells towards that -- towards pad drilling.

And we always like we communicated during the third quarter, we are going to see interference when we do these pad wells in areas where we have got multiple wells already in the section. So while I feel confident about the fourth quarter, the reality is that we are drilling a lot of wells in sections where we already have existing wells.

And we just got to be careful as put guidance out there on an annual basis that we always confident that we will be able to deliver on our promises.

All right. Fair enough.

And this might be more hypothetical or academic in nature, but with the strong margins get into the point of being free cash flow positive. Can you talk about -- I don't know if you have done this exercise internally, what's up with growth rate?

Do you think it actually being able to run at if you were free cash flow positive?

Yes. And Mike certainly I've not even communicated that to my Board yet.

So we do have internal models, but again, if you look at the -- you look at what goes into a model whether its cost of goods and services, which I have already talked, haven't yet recalibrated, the price for commodity which is very difficult to predict in our business and then the success of the wells, all three of those things have very significant impacts on our ability to be cash flow positive next year. What I do like about it is that our lease hold position can be maintained with minimal drilling next year.

So that just gives us a lot of optionality as we look into 2015 and again, I know you guys have a need for specificity. But at this point there is just too many parameters out there that we are not comfortable rolling out 2015 guidance until probably early in the first quarter of next year when we got better clarity on market conditions.

Thanks. Good morning everybody.

Just one question from me. Given that the stack laterals looks like pretty good results here this quarter and then also some reduced cluster spacing or some tighter stage spacing on a couple of wells there.

Just wondering how those two things would factor into your program going forward. I know it’s a volatile environment on the commodity pricing side.

But, what do you take away from those two things and how might that factor in going forward.

True. Well, again, depending on how many wells we are going to drill in 2015 that would be influenced by how many stack laterals we end up drilling.

I think you see efficiencies, cost efficiencies which you know we are all about, you see cost efficiencies when you are doing two and three well pads primarily on the pressure pumping side, the stimulation side. We think that's the best way to maximize returns.

With that being said though, we still got look at Wolfcamp B development timely in sections where we already have two and three wells in there. So again, it's a very fluid way that we look at the business next year because we got to make sure we are not fracing at the same time, we are drilling well in the section.

Switching to the second part of your question the increase frac stages, I guess if you look at the IP30 data that we've showed in the company presentation, I was a little surprised that we didn't see a more marked increase early on. I think it's like most tests, more data, more time certainly helps to provide greater clarity.

But I think or even to further complicate in a good way that response is that if you look at those two wells they are among the best two Wolfcamp B wells that we drilled. And so now we are trying to figure out the fact that we put 4 million pounds of sand, more pounds of sand and more stimulation fluid in that little section, so that perhaps influenced why these two wells are so much better than their offset.

So it's a good problem to have but it's one that we are going to need more time to before we can provide any clarity both internally and externally.

Hey, guys. Thanks for taking my question.

Travis just to go back on that increased rack density test and obviously understanding it's a little bit hard to draw any definitive conclusions yet. Do you guys have anything currently planned or drilling to test that in the near future or how should we think about integrating those types of projects in the near term here?

Yes. Jeff, I think you wait for me to give you some more specifics about which wells we are going to able to try that again.

Certainly I think its prudent based on the early two well improved performance for us to try that again. But I don't want to give a specific shed on which wells that we're trying on but I think it's reasonable that in the next couple of quarters you will see some more results from increased sand and fluid stimulation across our asset base.

And again, that also ties back into how many wells we are going to drill next year.

Okay. Fair enough.

And then just thinking about the recent acquisition you guys did with the Glasscock and Reagan county acreage. How should we think about you guys integrating those assets given that the rig count is probably not going to be ramping as aggressively into 2015?

Well, again, I'm trying to stay away specifically from counting rigs into 2015. But in a general sense as I previously communicated we'll keep two horizontal rigs running in the Spanish Trial on the Viper acreage.

And then depending on how many wells we ultimately end up next year, the more wells we drill, the higher likelihood we'll have additional wells drilled in Glasscock and Midland County on that newly acquired acreage. The less number of wells we drill would probably also correspond to fewer wells drilled on the newly acquired acreage.

So again, it's a fluid situation based on a lot of different parameters that we are trying to dial-in right now. And fortunately we don't have to make the decision on November 5 that we look forward to provide more clarity early in 2015 and what it looks like.

Okay. And then if I can just ask one more maybe switching over to the Viper side, can you guys comment at all on recent deal flow and maybe what you guys are seeing there and maybe if things are loosening up with obviously oil price is coming down, do you guys anticipate maybe being a bit more aggressive on the acquisition front?

We continue to be very opportunistic on deals on the Viper side. But, I will tell you that the most of the royalty checks haven't reflected yet the lower declining commodity price.

I think there is going to be a little bit of time before royalty owner start seeing lower $75 WTI prices placed in the royalty check. So I think while I've been pleased with the opportunity set, I think between now and the upcoming months with lower commodity prices, we hope to be seeing more opportunities come our way.

Hi, guys. I wanted to see if I could -- if we're trying to do a little bit of sensitivity analysis going forward.

What decline rates that we be looking at for the PDPs at both Viper and Diamondback like for the next year or two?

Yes. I think Adam somewhere in that mid-30s range on PDP decline.

Again, we haven't gone through our reserve audit yet at the end of the year. But, I think that's mid -- somewhere in the mid-30s for a decline rate.

Okay. That's helpful.

And I saw that your lending [indicative] [ph] proved a higher borrowing basin and you guys elected to keep it toned down a little bit. I'm just wondering if you could provide a little insight as to what the lenders out there are running through their models as far as price deck and what oil price they are assuming.

Well, I think the question be best directed to the banking community that runs those. But, I can tell you in a general sense that they have always run more conservative pricing based on lending decks.

But, I will also tell you that each lender has like they call it different things but distressed price test but they also test your borrowing base against and I don't know Russell, is it the distressed test do you have any specifics on it just a low price I don't know what it is because probably each bank as a different number. But, I do know that they are each going through there and testing a really low price as well as they make their lending decisions.

Okay. And just one final follow-up question it look like the Viper was dipping its toe in the water in the Delaware basin based on the filings for the recent capital raise and you acquired some assets.

It looks like a small position. I was wondering can you elaborate a little bit about the Delaware basin and what you see in there that might be attractive to on the Viper side.

Well, I think the Delaware basin acquisition that we highlighted on the Viper -- on the most recent Viper releases points to our consistent strategy of looking at basins that are all weighted that are under active development in targeting portions of that development with confident operators in that Delaware basin acquisition that we talked about certainly fits in there. And I think continues to give us encouragement that there is opportunities out in the Delaware basin for additional work for Viper.

I would like to take another stab at the deceleration one, if we assume that the current service cost environment remains, is there a level for WTI where you look to get a little more aggressive and start to accelerate again?

Yes. Again, Jeff, I'm trying not to get specific numbers out there, I know that makes you difficult, I mean I know that that makes your business difficult.

But, let me just step back for a lot of these modeling questions that you guys are asking me. Look we are -- Diamondback is extremely well positioned both for difficult times, if more difficult more times are coming, or for more opportunistic times if things improve.

We are in a spectacular position both from the strength of our balance sheet, but, also if you look at where record revenues, record production, record EBITDA, our execution appears to be among the best -- continues to be among the best in the basin. Our expense structure is extremely low.

So that to me indicates a company that's extremely well-positioned to handle things that are going to be difficult or maybe things that are going to improve in the future. So again, I know you guys are trying to model specifically but that's the story, we're sticking too.

That's good. I appreciate that.

I know it's a little early too and we'll get some more in December. And then hop in Dawson County, can you give us some color there and any change in your thoughts on that acreage in terms of what zones you might want to target next?

Yes. The Dawson County I drilled a four Cline well, it's the simplest way to say that and I won't drill another Cline well based on those results.

Now I also drilled about 8 miles to the south of it I drilled a Lower Spraberry well in Northern Martin County that looks extremely good. And so to that end, we believe and there is also some -- we think there's some more industry data out there in the Lower Spraberry that while the thermal maturity may not be as high as is what's needed for peak oil generation, it appears that the permeability in the system and the processing of system are allowing for some economic Spraberry wells.

So to that end, we're testing a Lower Spraberry well on that acreage right now.

Good morning guys. Just had a few questions with the rig count being flat year-over-year, would that imply flat year-over-year CapEx, not sure if the shallower Lower Spraberry wells were materially cheaper than Wolfcamp B or not?

Yes. Jamaal, first off, I've not said that we're going to be flat on a rig count year-over-year.

All I clearly stated was that we'll enter the year at five horizontal rigs and we'll make adjustments based on market conditions early on in 2015. Specifically to your question on Lower Spraberry and Wolfcamp B cost, there is notionally a little cheaper in the Lower Spraberry because they have -- for all intents and purposes and for your planning purposes, I'd use the same costs on the Lower Spraberry out here in the Wolfcamp B.

Okay, that makes sense. Thanks.

And just given your balance sheet strength and low cost operations, at what point would you get to think that you would rather invest in M&A rather than drilling an incremental well?

Yes. Jamaal, I think what I said is that we're going to be opportunistic.

I think we're well-positioned with the strength of our balance sheet and low cost operations and we're well positioned to take advantage of opportunities that come in the M&A world and I think they will, I remain optimistic that Diamondback is going to be in the best position to try to transact on these opportunities that come our way. So again, I can't give you specifically when I quit drilling and go to acquisitions because it depends on some many different market conditions that aren't clear right now.

So again, we'll talk more about 2015 in 2015.

I'm sorry Candice. I just want to respond back to the prior question.

If you go back and look at our history of acquisitions, which we've been highly acquisitive in the last two years, we've always done accretive deals. So again, as we look at opportunities, we've always done accretive deals, always have and we'll probably always will be going forward.

Hey, good morning Travis. I jumped on a little bit late so I hope I not rehash anything but just curious about those five rigs the contract structures you have and also maybe on the completion side just what you're looking at as far as optionality as you get into 2015 and then where you can go up or down?

Sure. We've got two rigs that are rolling off their existing contracts in early February so that will be the first get checked, we're going to have to make is what decisions we'll make on those rigs, do we let them go or do we continue on a well to well, month to month or six months contract.

So again, we'll make that decision with better clarity around market conditions. On the pressure pumping side, we've got really good relationship with our business partners on that side, but we don't have a specific contract on any of those guys.

So, we're in communications right now to make sure that certain recalibration existing in concert with the decline in commodity price.

Most of the stuff I was interested already was touched on, but you guys talked about cash flow 2015 back half being positive. Can you give us a little insight to what numbers you ran that analysis on like what oil price you used and what assumption as far as rig count at that time?

Yes. Joe, again, we're not providing that level of color because there is still a lot of unknowns, it depends on ultimately what happens from a commodity price and ultimately where service cost gets recalibrated.

We do have an internal model that generates that cash flow positive in the second half of the year. But again that's not something that I've communicated fully to the -- to my Board yet and it's something that we think and occur under set of oil price, commodity price, service cost and activity levels for next year.

And again, a big hinge point on that would be how successful these Lower Spraberry wells are going to be in 2015 because outperformance like we're seeing right now has a material impact on our cash flow position next year.

Okay. Maybe ask it a different way, if everything held constant to today, when do you think it reached cash flow positive, so five rigs today's oil and gas prices, today's cost?

I'm trying to think Joe on how the best way to answer that question. We've just not provided that level of clarity and I know Joe you got to put it in your spreadsheet, but I'm just not going to get back in the corner on exactly what things look like in 2015.

Okay. I'll move on to the one other thing.

With the two rigs due up in Spraberry, that's of the existing five rigs that you plan on entering the year. Are there any rigs that you've contracted that you are not yet in possession of that could be used as like replacement, so instead of renewing those two you have another two that you've already placed that up to come in or anything like that?

Yes. We've got three rigs, three new builds that are coming into our fleet throughout 2015, and into early 2016.

Okay.

And we also believe that if market conditions materially degrade or perhaps persist at their current levels that you're going to see the availability of one more horizontal rig. So we think we preserved optionality on both sides, the accelerated inventory as well as decelerating that inventory next year.

Thank you, Candice. I know that the guys on the phone based on the late release of several of [you missed] [ph] last night, several of you guys have been up all night.

So I know this is a busy time of the year for you, but I appreciate your specific questions into Diamondback and continued coverage. And I also want to thank everyone that's participated in today's call.

Certainly, if you have any questions, reach out to us using the contact information provided.