Diamondback Energy Inc (FANG) 2014 Q3 法說會逐字稿

Good day, ladies and gentlemen and welcome to the Diamondback Energy and Viper Energy Partners joint third quarter earnings call. At this time, all participants are in a listen-only mode. (Operator Instructions). Today's conference is being recorded. I would now like to turn the call over to Mr. Adam Lawlis, Investor Relations. Sir, you may begin.

Thank you, Candace. Good morning. Welcome to Diamondback Energy and Viper Energy Partners joint third quarter conference call. During our call today we will reference an updated investor presentation which can be found on our website. Representing Diamondback is Travis Stice, CEO, Tracy Dick, CFO, as well as other members of our executive team.

During the conference call participants may make forward-looking statements related to the company's financial condition, results of operation, plans, objectives, future performance, and businesses. We caution you that actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company's filings with the SEC.

During this 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. 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 100 horizontal wells over the last two years, and I am 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 have experienced a marked decline in commodity prices.

Diamondback has never been about for 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 drill fewer wells in 2015 than initially anticipated. However, we intend 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 our 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 a 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 an 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 operation will a 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 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 spend dedicated to horizontal development. We continue to expect Diamondback to grow production by nearly 150% in 2014 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 is really encouraging from the testing we have done to date is that the Lower Spraberry appears to be out performing the Wolfcamp B across our acreage. We have always said the Spraberry is not only the most contiguously deposited, but that it also contains the most oil in place.

Slide seven shows a table of Diamondback's Lower Spraberry to date. In Midland County, the Spanish Trail Northwest 2507 Lower Spraberry recorded a peak 30-day rate of 1,405boe a day from a 5,257-foot lateral. This translates to 267boe a day per thousand 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. Thirty miles further north in Martin County, we completed the Mabee Breedlove 2301 Lower Spraberry with a peak 30-day rate with 779boe a day from a 6,454-foot lateral. We believe this well is the northernmost publicly reported test of the shale.

As reported last quarter, the Nino F Unit Number 6 Lower Spraberry in Upton County, the industry's first Lower Spraberry horizontal test in the county, had a peak 30-day rate of 743boe per day from a 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 eight, most of our current results are significantly out performing our 650,000 boe two stream Lower Spraberry curve, and we are optimistic that this success can be replicated across a larger portion of our acreage.

On slide nine we show how stratographically how the Lower Spraberry looks across our acreage position. Log and core analyses indicate fairly consistent reservoir quality in the Lower Spraberry shale from southwest Dawson County extending south on to our Upton County assets.

Slide ten shows other notable results from the quarter, including Diamondback's first operated stacked lateral test in the Wolfcamp B in the 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 3,000 boe a day from two laterals that just average just shy of 9,200 feet.

Briefly switching gears to Viper, development of Spanish Trail is a win-win for both entities, and Spanish trail is the most economic prospect in Diamondback's portfolio, and continued organic production growth is expected for both Diamondback and Viper. As a reminder, Viper's mineral barrel has no direct operating or capital expenses 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 lease operating expenses. We fully expect this trend to reverse as we optimize these wells consistent with our low-cost efficient practices. Slide six 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 over the year between $6 and $7 a barrel. Our low cost structure, combined with high oil cuts, continue to drive pure leading cash margins and you can see graphically on slide five performance relative to our peers and the positive historical trends.

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 gains of $14.9 million and netting out the related income tax affect, our adjusted net income was $34 million or $0.61 per diluted share.

Our production for the third quarter was approximately 20,636boe a day. These volumes generated revenues in the third quarter of $139 million. Volume was up almost 16% and revenues up over 9% from the prior quarter.

Our average realized price before the effect of hedges for the third quarter was $73.28 per boe and our averaged realized price including the effect of 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 acquisitions, LOE for the quarter would have been $6.19. We anticipate that our LOE for the year will be in the upper end of the guidance between $6 and $7.

Our general and administrative costs came in at $3.42 per boe for the third quarter. This includes noncash equity-based compensation. Excluding all of our equity compensation G&A costs are $2.33 per boe. The $1.09 spread includes noncash 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 positions in last night's earnings release. We currently have about 9,000 barrels a day hedged at approximately $95 for the remainder of 2014. We also have 10,000 barrels 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 leasehold 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 between $425 million and $475 million.

As of September 30 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 plenty of liquidity. We estimate our year-end debt to EBITDA will be less than two times.

I will now turn briefly to Viper Energy Partners which announced last night a cast distribution of $0.25 per unit for the period from June 23 through September 30, 2014. During the period, adjusted EBITDA was $21.4 million and production increased 39% quarter over quarter to 3400boe per day. Viper has no debt and an undrawn revolver of $110 million following its September 14 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, stacked pay potential here in the Permian basin by developing the Lower Spraberry. Early Lower Spraberry results appear to be better than the Wolfcamp B, which notably has driven the tremendous success Diamondback achieved in the past couple of years. We maintained 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 for our success. It has been an amazing ride since taking the company public in 2012 and I firmly believe our best is yet to come.

Operator, please open the call to questions.

Thank you. (Operator Instructions). Our first question comes from the line of Mark Lear of Credit Suisse. Your line is now open.

Good morning, guys. Great quarter.

Thanks, Mark.

I just wanted to touch on some of the comments in the press release from you guys on CapEx and in 2015. I know it is early and others have just made comments about well costs and looking for costs to come lower and clearly the outlook for oil is pretty uncertain -- but 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 hygrating and drilling a lot more Lower Spraberry wells in the lower price environment? Just color around that would be great.

Sure, mark. Let me kind of take those in reverse. Specifically to the Lower Spraberry, we have got half a dozen or so well results that are significantly out performing our Tide curve. And obviously, that outperformance drives better rates of returns for investors as well. So while we have not finalized our plans in 2015, it makes a lot of sense for us to emphasize development to the Lower Spraberry.

Specifically to rig count and cadence for next year, I know that is an important question on a lot of analysts' minds right now and I understand why you guys need to have an answer to that. Specifically to rigs, I want to remind our audience 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 is really about wells next year. We've got some optionality as we look into 2015, depending on market conditions on how many wells that we are going to drill. I tried to outline that as best we can understand it right now. But we have to see -- service costs need to be recalibrated in conjunction with commodity prices that declined $25 or $30 a barrel in the last hundred days. We have to get better clarity on what those two events are going to look like before we finalize our plans to 2015.

And then lastly, Mark, we have a board meeting early December where I will 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 particularly Lower Spraberry performance outperforming the tide curve. I know you also talked about Wolfcamp B performance similarly outperforming. How would you say at this stage Wolfcamp B wells are tracking versus tide curve as well?

Yes, I think if you go back in the investor presentation and in the appendix section we have got some updated performance curves in there. But I will say in a general sense, we are pleased in the outcome of the Wolfcamp B wells where they are at or above our current tide curve performance. Russell is going to sit down with Ryder Scott here at the end of the year and we will go through a technical exchange with the reserve auditors, and then following that reconciliation we will be able to update the tide curves for not only Wolfcamp B, but also perhaps more importantly the Lower Spraberry.

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

Yes, Mark, I think you have always heard us talk about being fast followers, and the industry is real good about putting forth publicly the results in different zones. I think that is certainly a prudent approach for our scientists 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 at Wolfcamp A. But as it stands right now, we really like the results we are seeing in the Lower Spraberry and Wolfcamp B.

That's great. Thanks a lot, Travis.

Thank you, Mark.

Thank you. Our next call comes from the line of David Amoss of Iberia Capital. Your line is now open.

Hi, good morning, guys.

Hi, David.

Hi, David.

Just one quick one from me. Travis, if you don't mind -- can you go into a little bit more detail on what the cost trends you are seeing from what are the services guys putting in front of you for 2015 today? At least order of magnitude? And what do you need to see before you get more bullish on the service costs and possibly consider going up again on the rig count again, even in a lower commodity environment?

Yes, David, that again is a pretty complicated question. I can tell you that probably year to date on the service side we have seen costs in some portions of our business as high as 20%. And I know that prior to the recent pull back, some of the service sector was even trying to push through another 10% increase on top of that effective the first of the year. So that would be on some aspects of our business a cost increase of almost 30%year-over-year while at the same time our commodity price is off $25 or $30 a barrel.

There is not a number I can really give you that says, "Hey it has got to come down to this and I will get back to work," because it is a function of not only well results like Mark was asking about, but it is also where the service costs are ultimately going to be recalibrated with this oil price. And understandably it goes up very, very fast, the cost of goods and services and understandably it comes down a little bit slower. And that's what we are seeing right now.

We are communicating with all of our business partners across the full spend spectrum to ask them and 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 is really a combination of a bunch of different factors that will dictate future plans for Diamondback.

And just one follow-up. I mean, are there components of the service costs where you are seeing a substantial more inflation than others? What are the biggest concerns going into next year?

Well, if you look at the pressure pumping side of the business and not to single out one aspect of our total spend because we look at the full spectrum, but pressure pumping through the years has probably been the single biggest spend increase. Closely behind that you see cost of rigs going up as well. When you look at pressure pumping and drilling rigs, those are two big, pretty large tickets on a well.

All right. Really appreciate it. Great quarter.

Thank you, David.

Thank you. And our next question comes from the line of Mike Kelly of Global Hunter Securities. Your line is now open.

Good morning.

Hi, good morning, Mike.

Hi Travis. You guys posted a great production number in Q3. It looks like it came out well ahead of the midpoint of your full year guidance of 17,000boe to 19,000boe a day. I was wondering if there is anything in Q4 that we should be aware of maybe that makes you reluctant to increase that range. I know you guys have been in the middle of the transition to more pad drilling, if that is it? Or you are just being conservative here. Thanks.

You bet, Mike. If you look -- specifically at the fourth quarter, we continue migrate most of our wells toward pad drilling. 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 we are drilling a lot of wells in sections where we already have existing wells. We have to be careful as we put guidance out there on an annual basis that we always are confident we will be able to deliver on our promises.

Fair enough. And this might be more hypothetical or academic in nature, but with your strong margins getting to the point of being free cash flow positive, can you talk about -- I don't know if you have done this exercise internally, but what type of growth rate do you think you will be able to run at if you were free cash flow positive?

Yes, and Mike, certainly -- I have not yet communicated that to my board yet. We have internal models, but again, if you look at what goes into a model whether it is cost of goods and services which I have already talked and haven't recalibrated, the price for commodity, which is 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 our leasehold position can be maintained with minimal drilling next year. That just gives us a lot of optionalities as we look at 2015. And again, I know you guys have a need for specificity, but at this point there is 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 have got better clarity on market conditions.

Understood. Thank you.

Thank you. Our next question comes from the line of Gordon Douthat of Wells Fargo. Your line is now open.

Thanks, good morning, everybody. Just one question from me. Given the stack laterals look like some pretty good results this quarter and also some reduced cluster spacing and tighter spacing on a couple of wells -- I was wondering how those two things would factor into your program going forward? I know it is a volatile environment on the commodity pricing side, but what did you take away from those two things and how might that factor in going forward?

Sure. Well, again, depending on how many wells we are going to drill in 2015 that would be influenced by how many stacked laterals we end up drilling. You see efficiencies, cost efficiencies, which you know we're all about. You see cost efficiencies when you're doing two- and three-well pads, primarily on the pressure pumping side, the stimulation side. We think that is the best way to maximize returns.

With that being said, though, we still have to look at Wolfcamp B development and timely in sections where we have two and three wells in there. It is a very fluid way we look at the business next year, because we have to make sure we are not fracking at the same time we are drilling a well in the section.

Switching to the second part of your question, the increased frack stages, if you look at the IP30 data we showed in the company presentation, I was little surprised we didn't see a more marked increase early on. I think like most tests, more data and more time certainly provide greater clarity. But I think 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 we have 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 did that influence why these two wells are so much better than their offset. It is a good problem to have, but it is one we will need more time before we can provide any clarity both internally and externally.

Thank you. Our next question comes from the line of Jeff Grampp from Northland Capital Markets. Your line is now open.

Hi, guys, thanks for taking my question. Travis, just to go back to the increased frack density test and obviously understanding it will be hard to draw definitive conclusions yet, do you 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 would wait for me to give you more specifics about which wells we may want to try that in. Certainly I think it is prudent based on the early two-well improved performance for us to try that again. But I don't want to give specifics yet on which wells we are trying it on. I do think it is reasonable that in the next couple quarters you will see more results from increased sand and fluid stimulation across our asset base. And again, that also ties back into how many wells are going to drill next year.

Okay. Fair enough. And then thinking about the recent acquisition that 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 will keep two horizontal rigs running in the Spanish trail on the Viper acreage. And depending on how many wells we ultimately end up next year, the more wells we drill the higher likelihood we will 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 the fewer wells on the newly acquired acreage. So again, it is a fluid situation based on a lot of different parameters that we are trying to dial in right now. Fortunately we don't have to make the decision on November 5. We look forward to providing more clarity early in 2015 on what that looks like.

Okay, if I can just ask one more maybe switching 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 prices coming down, do you anticipate being a bit more aggressive on the acquisition front?

We continue to be opportunistic on deals on the Viper side. But I will tell you most royalty checks haven't reflected yet the lower declining commodity price. I think there's going to be a little of time before royalty owners start seeing lower, $75 WTI prices and placed in their royalty check. I think that while I have been pleased with the opportunity set, I think between now and the upcoming months with the lower commodity prices, we hope to be seeing more opportunities come our way.

Okay. Sounds good. Great results, guys. That's it for me.

Thank you, and our next question comes from the line of Adam Michael of Miller Tabak. Your line is now open.

Hi, guys. I wanted to see if I could -- if we are trying to do a little bit of sensitivity analysis going forward, what kind of decline rate should we be looking at for the PDPs at both Viper and Diamondback for the next year or two?

I think, Adam somewhere in the 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 is a mid -- somewhere in those mid30s for decline rate.

That's helpful, and I saw that your lending syndicate approved a higher borrowing base and you elected to keep it kind of toned down a little bit. I am wondering if you can provide a little insight as to what the lenders are running through as far as price decks, and what kind of oil price they are assuming?

Well, I think the question would 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 tell you each lender has -- they all call it different things, but distressed price test and they also test your borrowing base against.

Russell, is it kind of the distress tests? Do you have specifics on that? It is a low price, Adam. I don't know what it is. Each bank has a different number. I know that they are each going through there and testing a low price as well, as they make their lending decisions.

And just one final follow-up question, it looked like Viper was dipping its toe in the water in the Delaware Basin based on the filings for the recent capital raise and acquired assets. It looked like a small position. Can you elaborate a little about the Delaware basin and what you are seeing there that might be attractive on the Viper side?

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 oil-weighted and are under active development, and targeting portions of that development with competent operators. And that Delaware basin acquisition that we talked about certainly fits into that. It continues to give us encouragement that there's opportunities out in the Delaware basin for additional work for Viper.

Great quarter, guys, thank you.

Thank you. Our next question comes from the line of Jeffrey Connolly of Mizuho Securities. Your line is now open.

Hi, guys. Thanks for taking the questions. I would like to take another stab at the deceleration one. If we assume that the current service cost environment remains, there a level for WTI where you will look to get a little more aggressive and start to accelerate again?

Yes, again, Jeff, I am not trying to get specific numbers out there and I know it 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 times are coming, or for more opportunistic times if things improve. We are in a spectacular position both from a strength of our balance sheet, but also if you look at we're at record revenues, are record production, record EBITDA. Our execution appears to be -- continues to be the best in the basin. Our experience structure is extremely low. That to me indicates a company that is extremely well positioned to handle things that are going to be difficult or maybe things that are going to improve in the future.

Again, I know you are trying to model specifically, but that's kind of the story we are sticking to.

That's good. I appreciate that. I know it is a little early too, and we will get some more in December. And then up 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 poor Cline well. That's the simplest way to say that. I won't drill another Cline well based on is those results. Now, I also drilled about eight miles to the south of it. I drilled a Lower Spraberry well in northern Martin County that looks extremely good. To that end we believe -- and we think there is more industry data out there in the Lower Spraberry that while the thermal maturity may not be as high as what is needed for peak oil generation it appears the permeability in the system and the velocity in the system are allowing for economic Spraberry wells. To that end we are testing a Lower Spraberry well on the acreage right now.

Thanks, guys. Appreciate the color.

You bet, Jeff, thanks.

Thank you. Our next question comes from the line of Jamaal Dardar of Tudor Pickering Holt & Company. Your line is now open.

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

Yes, well, Jamaal, first off I have not said we would be flat on rig count year-over-year. All that I have clearly stated is we will enter at five horizontal rigs and we will 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 of depth, but for all intents and purposes and for your planning purposes, I would use the same cost in the Lower Spraberry as I would 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 you would rather invest in M&A than drilling an incremental well?

Jamaal, I think what I said is we will be opportunistic. I think we are well positioned with the strength of our balance sheet and low cost operations and we are well positioned to take advantage of opportunities that come in the M&A world. I think they will. I remain optimistic that Diamondback is going to be in the best position to try to transact on these opportunities as they come our way. Again, can't give you specifically when I quit drilling and go to acquisitions because it depends on so many different market conditions that aren't clear right now. Again, we will talk more about 2015 in 2015.

Okay. That's all I got. Thank you.

Thank you, Jamaal.

Thank you. Our next question comes from the line of Ryan Oatman from SunTrust. Your line is now open. Please check to make sure your line is not mute.

I'm sorry, Candace. I just wanted to respond back to the prior question. If you go back and look at our history of acquisitions which we have been highly, highly acquisitive in the last two years, we have always done accretive deals. As we look at opportunities we have always done accretive deals. Always have and probably always will going forward.

And our next question comes from the line of Jason Wangler of Wunderlich Securities. Your line is now open.

Hey, good morning, Travis. I jumped on a little bit late so hope I am not rehashing anything. I am just curious on the five rigs, the kind of contract structure that you have, and also on the completion side what you are looking at as far as optionality as you get in 2015 and where you can go up and down.

Sure, we've got two rigs that are rolling off their existing contracts in early February, so that will be the first kind of gut check we are going to have to make as what decisions we will make on those rigs. Do we let them go or do we continue them on a well to well, or month to month, or six-month contract. We will make that decision with better clarity around market conditions.

On the pressure pumping side, we have got a really good relationship with our business partners on that side. But we don't have a specific contract on any of those guys. We are in communications right now to make sure that certain recalibration exists in concert with the declining commodity price.

That's great. I will turn it back. Thank you.

Thank you. (Operator Instructions). And our next question comes from the line of Joseph Reagor of ROTH Capital Partners. Your line is now open.

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

Yes, Joe, again, we are not providing that level of color because there is still a lot of unknowns. It depends on ultimately what happens to commodity price and ultimately where service cost gets recalibrated. We do have an internal model that generates the cash flow positive in the second half of the year. But again, that's not something I have communicated fully to my board yet, and it is something we think can occur under a set of oil price, commodity price service costs, 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 are seeing right now has a material impact on our cash flow position next year.

Maybe asked a different way -- if everything held constant to today, when do you think you would reach cash flow positive? Five rigs, today's oil and gas prices, today's costs.

I'm trying to think. I'm trying to think, Joe, the best way to answer that question. We just -- we have just not provided that level of clarity and I know, Joe, you have to put it in your spreadsheet, but I am not going to get backed into a corner on what things look like in 2015.

Okay. Move on to one other thing. With the two rigs due up in February, That's of the existing five rigs that you plan on entering the year, are there any rigs you have contracted that you are not yet in possession of that could be used as like replacements? So instead of renewing the two you have another two that you had already pre-set up to come in or anything like that?

Yes, we have three rigs, three new builds are coming into our fleet throughout 2015 into early 2016.

Okay.

We also believe that if market conditions materially degrade or perhaps persist at their current levels that you will see the availability of one more horizontal rig. We think we preserved optionality on both sides, on the accelerating inventory and decelerating inventory next year.

Okay. Thanks for the color, guys.

Thank you. And I am showing no further questions at this time. I would like to turn the conference over to Mr. Travis Stice, CEO, for any closing remarks.

Thank you, Candace. I know the guys on the phone based on the late release of several of your notes last night, several of you guys have been up all night. I know this is a busy time of the year for you, but I appreciate y'all's specific questions into Diamondback and continued coverage.

And I want to thank everyone who has participated in today's call. Certainly if you have any questions reach out to us using the contact information provided.

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program. You may all disconnect. Have a great day, everyone.