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. Later, we will conduct a question and answer session. Instructions will follow at that time. If anyone should require assistance, please press star then zero on your touchtone telephone. As a reminder, today's conference is being recorded. I would now like to turn the conference 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'll reference an updated investor presentation, which can be found on our website. Representing Diamondback today are Travis Stice, CEO, Teresa 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 be found in the company's filings with the SEC. During our call today, we'll 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'll 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 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 decline in commodity prices. Diamondback has never been about growth for growth's 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. 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 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'll focus on specific operational details from the quarter. I'll 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 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've done to date is that the Lower Spraberry appears to be outperforming the Wolfcamp B across our acreage. We've always said that the Spraberry is not only the most continuously deposited, but that it also contains the most oil in place. Slide seven 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 1,405 BOEs a day from a 5,257-foot lateral.
This translates to 267 BOEs a day per 1,000-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 BOEs a day from a 6,454-foot lateral. We believe this well is the northernmost publicly reported test of this 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 BOEs 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 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 nine, we show stratigraphically 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 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 1 and the Gridiron number 2 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 BOEs a day from two laterals that average just shy of 9,200 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, 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've been $6.19 after excluding the effect of the acquired properties. We're reiterating our LOE guidance for the year between $6 and $7 a barrel. Our low-cost structure, combined with high oil cuts, continue to drive peer-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 Teresa.
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 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 costs, 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've 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 costs 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 $1.9 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 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 over 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 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 plenty of liquidity. We estimate our year-end debt to EBITDA will be less than two times. I'll now turn briefly to Viper Energy Partners, which announced last night a cash distribution of $0.25 per unit for the period from June 23rd through September 30th, 2014. During that period, adjusted EBITDA was $21.4 million and production increased 39% quarter-over-quarter to 3,400 BOE per day. Viper has no debt and an undrawn revolver of $110 million following its September 2014 public offering. With my comments complete, I'll turn it back over to Travis for his closing remarks.
Thank you, Teresa. 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 even better than the Wolfcamp B, which notably has driven the tremendous success Diamondback has achieved during the past couple of years. We've 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 in stockholder returns that are among the best in the industry. Before I call for questions, I want to acknowledge our employees for all they've 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 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. Ladies and gentlemen, if you would like to ask a question at this time, please press star and then the number one key on your touchtone telephone. If your question has been answered or you wish to remove yourself from the queue, please press the pound key. Once again, if you do like to ask a question, please press star one. Our first question comes from the line of Mark Lear of Credit Suisse. Your line is now open.
Hey, good morning, guys. Great quarter.
Thanks, Mark.
Just wanted to 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 costs and looking for costs to come lower and clearly the outlook for oil is pretty uncertain. 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-grading and drilling a lot more Lower Spraberry wells in a lower price environment? Just color around that would be great.
Sure, Mark. Let me take those in reverse. Specifically to the Lower Spraberry, yeah, we've 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. While we've not finalized our plans in 2015, it makes a lot of sense for us to try to emphasize development of the Lower Spraberry. Specifically to rig count and cadence for next year, I know that that's 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's 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're going to drill. I've tried to outline that as best we understand it right now. We've got to see service costs need to be recalibrated in conjunction with commodity price that's declined $25 or $30 a barrel in the last 100 days. We've got to get better clarity on what those two events are going to look like before we finalize our plans into 2015. Then lastly, Mark, we've got a board meeting early December where I'll be outlining specifically all these different options that are still in front of us in 2015.
That's great. Really helpful. I guess when you're looking at particularly Lower Spraberry performance outperforming the type curve, I know you've 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?
Yeah, I think if you go back in the investor presentation, in the appendix section, we've got some updated performance curves in there. I'll say in general sense, we're pleased in the outcome of the Wolfcamp B wells where they're at or above our current type curve performance. Russell's going to sit down with Ryder Scott here at the end of the year, we'll go through a technical exchange with the reserve auditors, then following that reconciliation, we'll be able to update type curves for not only the Wolfcamp B, but also, perhaps even more importantly, the Lower Spraberry.
That's great. 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 that work for you, or do you expect to do some more appraisal drilling other zones as well?
Yeah, Mark, I think you've always heard us talk about being fast followers, the industry's real good about putting forth publicly the results in different zones. I think that's certainly a prudent approach for our sciences to 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. As it stands right now, Mark, we really like the results we're seeing in the Lower Spraberry and the Wolfcamp B.
That's great. Thanks a lot, Travis.
Thank you, Mark.
Thank you. Our next question comes from the line of David Amos of Iberia Capital. Your line is now open.
Hey, good morning, guys.
Hey, morning, 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're seeing from what are the services guys putting in front of you for 2015 today, at least order of magnitude? What do you need to see before you get more bullish on the service costs and possibly consider going up on the rig count again, even in a lower commodity environment?
Yeah, David, that again, is a pretty complicated question. I can tell you that probably year-to-date on the service side, we've seen costs in some portions of our business up as high as 20%. I know that prior to this recent pullback, some of the service sector was even trying to push through another 10% increase on top of that effect of the first of the year. 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's 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 me about, but it's also where the service costs are ultimately going to be recalibrated with this oil price. Understandably, it goes up very fast, cost of goods and services, understandably, it comes down a little bit slower, that's what we're seeing right now. We're communicating with all of our business partners across the full spend spectrum to ask them to make sure that they're looking at their side of the business as well as ours in response to a low commodity price. It's really a combination of a bunch of different factors that will dictate future plans for Diamondback.
Okay, just one follow-up. Are there components of that service cost where you're seeing a substantial amount more inflation than others? What are the biggest concerns going into next year?
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 biggest spend increase. Closely behind that, you've seen cost of rigs go up as well. When you look at pressure pumping and drilling rigs, those are two big, pretty large tickets on a well AFE.
All right. Really appreciate it. Great quarter, guys. Thanks.
Thank you, David.
Thank you. Our next question comes from the line of Mike Kelly of Global Hunter Securities. Your line is now open.
Good morning.
Hey, good morning, Mike.
Hey, Travis. You guys posted a great production number in Q3. It looks like you're now well ahead of the midpoint of your full year guidance of that 17,000-19,000 a day. I'm just wondering if there's anything in Q4 that we should be aware of that maybe makes you reluctant to increase that range. I know you guys have been in the middle of a transition to more pad drilling, if that's it, or you guys are just being conservative here. Thanks.
You bet, Mike. If you look specifically at the fourth quarter, we continue to migrate most of our wells towards pad drilling, and we always, like we communicated during the third quarter, we're going to see interference when we do these pad wells in areas where we've got multiple wells already in the section. While I feel confident about the fourth quarter, the reality is that we're drilling a lot of wells in sections where we already have existing wells, and we've just got to be careful as we put guidance out there on an annual basis that we always are confident that we'll be able to deliver on our promises.
All right. Fair enough. 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've done this exercise internally, what type of growth rate do you think you'd actually be able to run at if you were free cash flow positive?
Yeah. Mike, certainly, I've not even communicated that to my board yet. We do have internal models, but again, if you look at what goes into a model, whether it's cost of goods and services, which I've already talked to, 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 leasehold position can be maintained with minimal drilling next year. That just gives us a lot of optionality as we look into 2015.
Again, I know you guys have a need for specificity, but at this point, there's just too many parameters out there that we're not comfortable rolling out a 2015 guidance until probably early in the first quarter of next year when we've got better clarity on market conditions.
Got it. 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 that the stack laterals look like some pretty good results there this quarter, also some reduced cluster spacing or some tighter stage spacing on a couple 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?
Sure. Well, again, depending on how many wells we're 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'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's the best way to maximize returns. With that being said, though, we still got to look at Wolfcamp B development timely in sections where we already have two and three wells in there. Again, it's a very fluid way that we look at the business next year because we got to make sure we're not fracking at the same time we're drilling a well in the section. Switching to the second part of your question, the increased frack stages.
If you look at the IP 30 data that we showed in the company presentation, I was a little surprised that we didn't see a more marked increase early on. I think, like most tests, more data, more time certainly helps provide greater clarity. I think even to further complicate, in a good way, that response is that if you look at those two wells, they're among the best two Wolfcamp B wells that we've drilled. Now we're 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 perhaps influence why these two wells are so much better than their offsets?
It's a good problem to have, but it's one that we're going to 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 of Northland Capital Markets. Your line is now open.
Hey, guys. Thanks for taking my question. Travis, just to go back on that increased frack density test, 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?
Yeah. Jeff, I think you'd wait for me to give you some more specifics about which wells we may want to try that in. Certainly, I think it's prudent based on the early 2 well improved performance for us to try that again. I don't want to give specifics yet on which wells that we're trying it on. I do think it's reasonable that in the next couple of quarters, you'll see some more results from increased sand and fluid stimulation across our asset base. Again, that also ties back into how many wells we're going to drill next year.
Okay, fair enough. 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's probably not going to be ramping as aggressively into 2015?
Well again, I'm trying to stay away specifically from counting rigs into 2015. In a general sense, as I've previously communicated, we'll keep 2 horizontal rigs running in the Spanish Trail on the Viper acreage. 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. Again, it's a kind of a fluid situation based on a lot of different parameters that we're trying to dial in right now. Fortunately, we don't have to make the decision on November 5th, but 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 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 prices 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. I'll tell you that most royalty checks haven't reflected yet the lower declining commodity price. I think there's going to be a little bit of time before royalty owners start seeing lower $75 WTI prices placed in their royalty check. I think while I've been pleased at 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.
Okay. Sounds good. Great results, guys. That's it for me.
Thank you. Our next question comes from the line of Adam Michael of Miller Tabak. Is now open.
Hey, guys. I wanted to see if we're trying to do a little bit of sensitivity analysis going forward, what kind of decline rates should we be looking at for the PDPs at both Viper and Diamondback, like, for the next year or two?
Yeah, 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 somewhere in those mid-30s for decline rate.
Okay, that's helpful. I saw that your lending syndicate approved a higher borrowing base, 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 kind of oil price they're assuming.
Well, I think the question would be best directed to the banking community that runs those. I can tell you in a general sense that they've always run more conservative pricing based on lending decks. I'll also tell you that each lender has a, they all call it different things, but distressed price test, but they also test your borrowing base against. I don't know, Russell, the week is it kind of a distressed test? Do you have any specifics on that? It's just a low price, Adam. I don't know what it is because probably each bank has a different number. I do know that they're each going through there and testing a really low price as well as they make their lending decisions.
Okay. Just one final follow-up question. It looked like that 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, and it looked like a small position. I was wondering, can you elaborate a little bit about the Delaware Basin and what you're seeing there that might be attractive on the Viper side?
Well, I think the Delaware Basin acquisition that we highlighted on the most recent Viper releases points to our consistent strategy of looking at basins that are oil-weighted, that are under active development, and targeting portions of that development with competent operators. That Delaware Basin acquisition that we talked about certainly fits into that, and I think continues to give us encouragement that there's opportunities out in the Delaware Basin for additional work for Viper.
Okay. Great quarter, guys. Thank you.
Thank you. Our next question comes from the line of Jeffrey Connelly of Mizuho Securities. Your line is now open.
Hi, guys. Thanks for taking the questions. I'd 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?
Yeah, again, Jeff, I'm trying not to get specific numbers out there. I know that makes your business difficult. Let me just step back for a lot of these modeling questions that you guys are asking me. Look, Diamondback is extremely well-positioned, both for difficult times, if more difficult times are coming, or for more opportunistic times if things improve. We're in a spectacular position both from a strength of our balance sheet. Also if you look at, we're at record revenues, record production, record EBITDA. Our execution continues to be among the best in the Basin. Our expense structure is extremely low. 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.
Again, I know you guys are trying to model specifically, but that's kind of the story we're sticking to.
That's good. I appreciate that. I know it's still a little early too. We'll get some more in December. 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?
Yeah, 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 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's some more industry data out there in the Lower Spraberry, that while the thermal maturity may not be as high as what's needed for peak oil generation, it appears the permeability in the system and the porosity in the system are allowing for some economic Spraberry wells. To that end, we're testing a Lower Spraberry well on that acreage right now.
Great. 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 & Co.. Your line is now open.
Good morning, guys. 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? Not sure if the shallower Lower Spraberry wells were materially cheaper than Wolfcamp B or not.
Yeah. Well, Jamaal, first off, I've not said that we're going to be flat on rig count year-over-year. All I've 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, they're nominally a little cheaper in the Lower Spraberry because of depth. For all intents and purposes and for your planning purposes, I'd use the same costs in the Lower Spraberry as I do in the Wolfcamp B.
Okay. That makes sense. Thanks. 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?
Yeah, Jamal, I think what I've 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, 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 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'll talk more about 2015 in 2015.
Okay, that's all I got. Thank you.
Thank you, JeDon.
Thank you. Our next question comes from the line of Ryan Oatman of SunTrust. Your line is now open. Please check to make sure your line is not mute.
Hey, I'm sorry Candace, 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. Again, as we look at opportunities, we've always done accretive deals. Always have, and we probably always will going forward.
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 I hope I'm not rehashing anything. Just curious about those five rigs, the kind of the contract structures you have, and almost also maybe on the completion side, just what you're looking at as far as optionality as you get into 2015 and where you can go up or down.
Sure. We've got two rigs that are rolling off their existing contracts in early February. That'll be the first gut check 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 them on a well-to-well, month-to-month or six-month contract? 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. We're in communications right now to make sure that a certain recalibration exists in concert with the decline in commodity price.
That's great. I'll turn it back. Thank you.
Thank you. Once again, ladies and gentlemen, if you do have a question at this time, please press star and then the number one key. 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, 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?
Yeah, Joe, again, we're not providing that level of color because there's 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 that cash flow positive in the second half of the year. Again, that's not something that I've communicated fully to my board yet, and it's something that we think can occur under a set of oil price, commodity price, service cost, and activity levels for next year. 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 asked a different way. If everything held constant to today, when do you think you'd reach cash flow positive? Five rigs, today's oil and gas prices, today's costs.
I'm trying to think, Joe, on how the best way to answer that question. We've just not provided that level of clarity. I know, Joe, you've got to put it in your spreadsheet, but I'm just not going to get backed in the corner on exactly what things look like in 2015.
Okay. I'll move on to the one other thing. With the 2 rigs due up in February, that's of the existing 5 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 replacement? Instead of renewing those 2, you have another 2 that you'd already pre-set up to come in or anything like that?
Yeah, we've got 3 rigs, 3 new builds that are coming into our fleet throughout 2015 into early 2016.
Okay.
Again, 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. We think we've preserved optionality on both sides, the accelerating inventory as well as decelerating that inventory next year.
Okay. Thanks for the color, guys.
Thank you. I'm showing no further questions at this time. I would like to turn the conference back over to Mr. Travis Stice, CEO, for any closing remarks.
Thank you, Candace. I know that 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. 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.
Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program, and you may all disconnect. Have a great day, everyone.