Diamondback Energy Inc (FANG) 2014 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Diamondback Energy first-quarter earnings conference call. (Operator Instructions). As a reminder this conference is being recorded.

I will now turn the call over to your host, Adam Lawlis, Investor Relations. Please go ahead.

Thank you, Stephanie. Good morning and welcome to Diamondback Energy's first-quarter conference call. Representing Diamondback today are Travis Stice, CEO; Tracy Dick, CFO; and Russell Pantermuehl, VP of Reservoir Engineering.

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 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 first-quarter 2014 conference call.

Since our last call, we have issued an operations update that highlighted our continued growth in production volumes, our first two successful Martin County Wolfcamp B tests, as well as continued positive developments in Midland and Upton Counties. Our Gridiron well in Midland County is the best well we have drilled to date and also appears to be one of the top horizontal wells in the Midland Basin.

As we have said before, we have increased our development focused on the lower Spraberry with wells now drilled in both Midland and Upton Counties. Lastly our first Wolfcamp B well in Dawson County has confirmed economic viability in our northernmost acreage and we plan to follow up with a test in the Cline Shale also known as the Wolfcamp B during the third quarter.

Switching now to the first quarter, I am proud of the quarterly results as we again demonstrated our ability to grow production volumes by 30% from the prior quarter while keeping operating expenses low. With LOE at less than $6.50 a barrel we are in line with our guidance even as we continue to move further north where our cost reduction infrastructure projects are still being implemented.

Our low-cost operating metrics combined with higher percentage of oil production drives our peer-leading cash margins with the first quarter coming in at nearly $67 a BOE which is up from $64 a BOE in the fourth quarter of 2013. We continue to be an aggressive developer of our horizontal inventory and we are operating five horizontal rigs as previously planned. We expect to grow production by more than 125% this year.

We are currently running three horizontal rigs on our acreage in Midland County, one in Upton County and one in Martin County. As a reminder, we report all of our well results on a 2-stream basis. In Midland County, we are excited about our most recent Wolfcamp B test, the Gridiron 1H, our highest 24-hour IP rate to date at 2757 barrels of oil equivalent per day with a 91% oil cut that was drilled with an 8785 foot lateral and is still flowing back.

In Dawson County, our first horizontal Wolfcamp B well produced a peak 24-hour IP rate of 541 barrels of oil equivalent with a 92% oil cut from an 8543 foot lateral on ESP. We plan to test the Cline Shale also known as the Wolfcamp B on this acreage during the third quarter.

As exciting as the horizontal Wolfcamp B has been and continues to be, early indications from the lower Spraberry continue to be competitive with our existing Wolfcamp B program with respect to both rate of return and the EURs. Our first operated horizontal lower Spraberry well in Midland County produced a peak 24-hour IP rate of 1049 barrels of oil equivalent per day with a 92% oil cut from a 4418 foot lateral thus far on ESP.

Additionally, we are currently flowing back our first lower Spraberry well in Upton County that we believe is the southernmost test of the horizontal lower Spraberry in the Midland Basin.

We've just successfully drilled our first 3-well pad in Upton County where three roughly 5000 foot laterals in the Wolfcamp B were drilled in less than 40 days. While these wells are not yet completed, we have reduced total drilling costs by almost $500,000 for the 3-well pad and significantly improved our cycle time.

When you review our results in each of our development areas, we are consistently at or above our type curve projections and within our cost guidance. I think this is significant in that we have now drilled over 60 horizontal wells since our IPO less than 18 months ago. That is really a tribute to our organization and gives confidence to our stockholders Diamondback will continue to deliver on the multi-rig horizontal program with extreme focus on execution and efficiencies and reconfirming our full-year guidance as previously reported.

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

Thank you, Travis. Our net income for the first quarter was $23.6 million or $0.48 per diluted share. Net income for the period included a non-cash loss on commodity derivatives of $3.3 million. Excluding the non-cash loss and the related income tax effect, our adjusted net income was $25.7 million or $0.53 per diluted share.

As previously reported, our production for the first quarter was approximately 13,600 BOE per day and 79% of this production was oil. These volumes generated revenues in the first quarter of $98 million and EBITDA of $81.3 million. Our average realized price before the effective hedges for the first quarter was $80.35 per BOE. Our average realized price including the effect of hedges was $79.48 per BOE.

Turning over to costs, our lease operating expense was $6.49 per BOE in the first quarter. Our general and administrative costs came in at $3.74 per BOE, which includes non-cash stock-based compensation of $2.2 million. Excluding stock-based compensation, G&A costs are $1.94 per BOE. Interest expense on our income statement for the quarter was $6.5 million. We capitalized $2.9 million of interest to our full cost pool.

Our current hedge position through 2015 have been laid out in our earnings release. We currently have 50% of our estimated crude oil production hedged at an average price of $99 a barrel for the remainder of 2014. We continually assess our hedging opportunities and we will continue to layer on additional hedges as our production grows.

In the first quarter of 2014, we generated $71 million of operating cash flow and $80 million of discretionary cash flow or $1.46 and $1.64 per diluted share respectively.

During the first quarter of 2014, we spent $86.4 million for drilling, completion and infrastructure. Additionally we spent approximately $312.2 million on leasehold acquisitions.

Our liquidity position remains strong with approximately $25 million of cash on hand at March 31, 2014. Our agent lender has approved a borrowing base increase of 100% to $450 million based on our current reserves. As of March 31, 2014, the revolver has $147 million drawn against it.

In summary, our focus continues to be on cost efficiencies. We maintain a strong balance sheet and we have sufficient liquidity to fund our operations and drilling program.

I will turn the call back over to Travis for his closing remarks.

Thank you, Tracy. To summarize, I am proud of our continued success in driving production growth, continued improvement executing on these complex well pads, and operating with low-cost structures. These combined to drive our peer-leading cash margins and I believe we continue to deliver results and stockholder returns that are among the best in the Midland Basin.

As mentioned in our earnings release, Diamondback's wholly-owned subsidiary, Viper Energy Partners LP, filed a registration statement on Form S-1 with the Securities and Exchange Commission in connection with its proposed initial public offering of limited partnership interest. Because the S-1 is on file, I am not in a position to make any further comment regarding the offering.

On behalf of the Board and employees of Diamondback Energy, I would like to thank you for your participation today. This concludes our prepared comments. Operator, please open the call to questions.

(Operator Instructions). Jason Wangler, Wunderlich Securities.

Good morning, guys. Just curious, obviously results have been really solid in the Spraberry. Do you see that being pretty uniform across your acreage at least, much like the B in that you are going to be pretty prospective across the entire position for the Spraberry as well?

Yes, I think certainly when you look at the Spraberry in general, it is one of the more continuously deposited shales across the Midland Basin and certainly when you look at our position with probably the exception of the far northernmost acreage, all of our acreage has prospectivity on the Spraberry.

Okay. That is great. Then I think you mentioned it in your comments but the Cline Shale test or the first well I should say I guess, is that going to be up north in Dawson? Maybe if that is right, just the thought process of putting it up that way?

Yes, exactly. It will be in Dawson County and really what we are doing is we are capitalizing on some additional work that we have got since we drilled that first well, the Kent County School Lanes, we cut a hole core when we drilled the vertical well up there and cut a hole core and while the Wolfcamp B, the geochemical work confirms that we were in the oil generation window, when you move about 600 feet deeper into the Cline Shale, you are actually moving even further into what we call the peak oil window. So that is why we in the next couple of weeks we will spud that Cline test in Dawson County.

I appreciate it. I will turn it back.

Jeff Grampp, Northland Capital Markets.

Just kind of a strategic question for you guys. If and when this Viper offering goes through obviously your liquidity position would improve significantly, giving you guys a lot more flexibility to accelerate. I was wondering what obviously other than just the capital constraint or any other potential constraints in regards to ramping up the rig count whether that be services or infrastructure or anything else on that front?

Jeff, without the specific comments on the Viper transaction, that is one of the things that I consider at the CEO level my most important job is allocation of resources, both human and capital. And as it pertains to the capital allocation, we always look forward to try and accelerate as much of our inventory forward as we can. What that depends on strategically is continued de-risking of some of the northern blocks which we are starting to feel pretty comfortable on as well as infrastructure issues like access accumulation and disposal of stimulation water.

So it is about a 3 x 3 decision matrix when it comes to trying to accelerate but that is certainly high on our priority list is to try to accelerate as much inventory forward as we can.

Okay, great. And then kind of on that topic of de-risking, has any of the recent activity either by yourselves or the industry really changed your thoughts on rig allocation or maybe development of other formations obviously focused mostly on the B bench and again good results on the Spraberry. But have you guys really changed your thoughts recently on where you are going to focus the majority of either your rig count or on a well account basis?

Certainly the lower Spraberry continues to significantly exceed our expectations and significantly exceed the type curves that we adopted from Ryder Scott at the end of last year. And again when it gets back to capital allocation, we are going to put the drillbit where we can generate the greatest shareholder returns. And I think what you are going to see is a continued mix perhaps more emphasis in the lower Spraberry.

But in our most developed areas and our core areas, we are going to focus on a Wolfcamp B and a Spraberry development. And then as I mentioned in my prepared comments, we've drilled and completed -- are in -- I think we are day 8 flow back on the first lower Spraberry horizontal well in Upton County and certainly stay tuned for that because if that play pans out in the lower Spraberry, that will give us a significant development uptick down there in Upton County.

And then lastly just the northern acreage specifically up in Dawson County. I mentioned our next test is in the Cline Shale and not only is that supported by the geochemical work that we talked about just a second ago but it is also supported by some significant operator tests in northern Martin County and Northeast Andrews County which support the prospectivity of the Cline. That is in the North. That is one of the reasons we are excited about this Cline test as well.

Okay, great. Thanks for that color. And then the last one for me just hoping to get an update on maybe what recent well costs have been for you guys and maybe relating that to that $6.9 million to $7.4 million range in your guidance or maybe if you guys just have any kind of generic well cost targets that you are trying to get by year-end or anything on that front?

Jeff, at this point I think it is still fair to stay within our guidance. I mentioned a 3-well pad that we drilled down in Upton County we have not completed it yet but that 3-well pad will take off around $500,000 for that 3-well set. So to the extent we can drill more wells on pads, we are going to be biased at the low end of our range. To the extent we are still drilling single wells, we will be probably at the midpoint of that range.

I gave you a data point on that long lateral in Midland County. It was right at $9 million and it is going to pay out in 120 days and we have just drilled and got casing on bottom on its offset and we will soon spud a third well on that acreage block. And that is a 2500 acre block that is undrilled with horizontal wells. So we are excited to follow that up.

But I like where we are headed on our costs and we will just have to maintain the discipline and focus on execution and make sure our costs are bias towards the low end.

Okay, great. Thanks for that color. Just kind of clarification, that $500,000 savings on the 3-well pad, is that $500,000 per well or is that an aggregate savings for the whole pad?

Aggregate savings for the whole pad and again, we have got over 60 wells drilled and we are pretty far down on the efficiency and learning curve side of the equation so we are picking up pennies and nickels at this point every day.

Okay, that is it for me. Thanks, guys. Good quarter.

You bet. Thanks, Jeff.

Dave Kistler, Simmons & Company.

Good morning, guys. I had a question maybe a little bit higher level in terms of just understanding specifically in the Wolfcamp B, kind of Midland Andrews area, what sort of recovery of resource in place do you think you are currently achieving?

Dave, that is a hard number for the industry to try to come up with and it all depends on how you want to calculate oil in place. But if you are looking for kind of a ballpark number for the Wolfcamp B, I think somewhere 8% to 10%, 8% to 12% something like that. But again it is highly dependent on how you want to calculate original in place.

Sure, no. I appreciate that. Kind of the gist of where I'm taking the question is you guys have certainly been leading the way in terms of driving down well costs and delivering on efficiency gains, etc. and you have talked about now being able to squeeze out nickels and dimes as opposed to quarters, etc. But are you now kind of at a point where you want to maybe mess around a little bit more with changing well design or completion techniques or things like that to potentially increase that recoverable resource level? I am just curious to get your thought process on that.

Dave, that is a good question as we as engineers, we always like the engineers and geoscientists, we always like to try to tweak things and I think you will see that in some of our completion designs, the tweaks but they are not major overhauls. We have been and have proven to ourselves that a slick water shop is the best way to stimulate these shales so we are going to continue to stay with slick water.

But maybe in a more macro sense, I think the spacing question is yet to be defined by the industry and while in Midland County where we have got the most information we are drilling inter-lateral spacing at 660 feet. I think we are very actively watching other industry tests that are out there that are even increasing that down spacing further. And to the extent that the industry proves up tighter down spacing, we will like we always do, we will be a fast follower to that decision point.

Perfect. I really appreciate that color. Thanks so much, guys.

You bet, Dave. Thanks.

Jeffrey Connolly, Mizuho Securities.

Good morning, guys. In the prepared remarks, you mentioned higher LOEs on the northern acreage because of less infrastructure. Can you kind of just give us an overview of how the LOE has changed versus your operating areas?

Specifically we acquired the East [Kaden] asset earlier this year, picked up 147 vertical wells and typically these vertical wells have a little higher LOE than a horizontal well from both from an absolute dollar perspective and a volume perspective when you look at a dollar per barrel metric.

So I anticipate as we continue to move North and drill more and more horizontal wells and horizontal production becomes a higher percent of the total that you will start seeing some adjustments to the LOE. But just as we incorporate straight out 147 vertical wells, you see just a slight uptick in LOE until we get our horizontal rigs back to work up there.

Thanks. That was helpful. Can you just give us a quick overview of what you are seeing in the M&A market and what kind of prices, acreage packages, stuff like that? Any update?

Yes, Jeff, there is no doubt that the Permian Basin has been one of the hottest basins in our whole industry when it comes to M&A activity and what that means when times are hot, that means that acreage prices or entry costs are going up. That being said, we still believe that we have got opportunities in front of us to grow both inorganically and organically but with that we've got to be opportunistic and we've got to be disciplined.

When I talk about being opportunistic, sometimes that means price expectations and sometimes that means strategically. But I want to be clear that as we look at these deals we are only going to do deals that are accretive to our shareholders and that is where that discipline comes into play. Our industry is littered with the bones of companies that have been trying to grow inorganically through acquisitions and perhaps in my past some of those bones have been mine. And they did that because they lost the discipline and they ultimately paid too much.

So one thing that you can count on Diamondback is we are going to maintain that discipline as we grow both organically and inorganically.

Now what that means though is that while there are deals out there and you still see deal flow, this strategy means that we are not going to win every competitive auction that is out there and we haven't. But we firmly believe that as you look long-term, that our greatest shareholder value creation is through that consistent approach of being opportunistic and being disciplined. And when you couple that kind of inorganic growth story that I just outlined there with our best-in-class organic growth story, I think you've got a winning combination in Diamondback and I think that is one that shareholders ought to be proud to own.

All right, thanks guys. I will hop back in the queue.

Thanks, Jeff.

Mike Kelly, Global Hunter Securities.

Good morning. I am looking at slide four of your most recent slide deck here and just looking at your inventory count by area and by zone. And if I look at the Wolfcamp B, you have got 316 net locations laid out. And I was just curious how many of those locations come from the Southwest Dawson County acreage? Thanks.

I think there was 42 Wolfcamp B locations that we had in Dawson, so 42 out of that -- you know, 316.

Okay, great. So not that much. Thanks. Maybe just sticking on the theme of organic versus inorganic growth there, Travis and maybe I think it would be helpful for me to hear what you deem as accretive here and just that balance between -- do we add inventory at the end of a 10+ year inventory life right now versus really just breaking out production growth on a net adjusted per-share basis today? How you think about that, what really is accretive for shareholders? Thanks.

You know, Mike, it is not really the inorganic or organic, it is not really an either/or but it is really an and. We have got to be able to effectively do both and when we look at accretive acquisitions or we look at metrics that describe an accretive acquisition, it is things like EBITDA per share, production reserves, those type parameters and usually not all of them will hit so it becomes our strategic judgment that I work with the Board on exactly which of these typically migrate to the top which make these acquisitions accretive. But at the end of the day, it is typically EBITDA per share is what we are looking for.

Also just from an operations metric, F&D costs is another good one that we look at being accretive on an F&D perspective.

Got it. And I know you can't talk too much about Viper here if at all but just wonder if you look across the basin right now, do you see other opportunities to pick up mineral rights and maybe do something similar that you have done here after picking these mineral rights up eight months ago? Thanks.

Mike, I think I have been on the record several times at least from my perspective that the mineral acquisitions like the one we did in the late third quarter, early fourth quarter of last year was a once in a lifetime opportunity. So I think that is probably still a likely perspective to take at least in terms of large producing minerals like what we were able to acquire.

But are there other opportunities to pick up smaller bits and pieces of royalties and minerals? That is certainly what we are going to continue to look for. We have added bits and pieces along the way even since we did the original minerals acquisition. We are going to continue to try to be acquisitive on that front as well as just the more traditional producing property acquisitions.

Got it. Thank you.

Richard Tullis, Capital One.

Thanks. Good morning, everyone.

Good morning, Richard.

Travis, just sticking with the M&A theme, you guys have made a lot of progress lowering well costs, operating costs as you move forward. What do you think the capacity is right now for the organization to how many more rigs could you operate and still maintain your current efficiencies if you were to continue with M&A?

That is a great question, Richard, and that is one as an executive team we struggle with quite a bit because I feel that a question earlier on accretive -- how I define accretive acquisitions. And one of the things that is not a hard and fast metric that we look at but it is one that we have to consider is if we do an acquisition, can we ensure to our stockholders that that acquisition is not going to dilute our current execution efficiencies.

So while I look to Jeff White, our VP of Operations, and Mike Hollis, our VP of Drilling, specifically to make sure that as we talk about acquisition acquisitions that they can continue to execute on a best in class fashion with rolling in the new acquisitions. And so what we have charged each other with is that we need to build an organization that is scalable and that means that we can maintain the current best in class execution and at the same time pick up additional rigs.

Kind of as a planning number somewhere around that eight to 10 horizontal rigs would be sort of our bandwidth and we are at five right now. So that is how we are building the organization out right now is to try to handle an eight to 10 horizontal rig capacity.

Thank you. That is helpful. Just lastly from me, I don't want to get into the details of your proposed transaction as you have mentioned, but could you talk a little bit about expected timing, when you think the transaction could be finalized?

Sure, Richard. If you kind of dug through some of the details in the S-1 which I just did last night, you will see that we actually filed confidentially a month and a half or so and we have actually gone through one cycle with the SEC and that is where we are at right now. We are in a quiet period because we have refiled it now publicly with the SEC and we are somewhat limited by how quickly they turn the document but since we have already gone through one turn, we are somewhere in that 30- to 60-day time frame. I think that would be a reasonable expectation.

Okay, thanks a bunch. Appreciate it.

Ryan Oatman, SunTrust.

Good morning. A large Permian operator was discussing the potential for cost inflation of about 10% seemingly across the board whether it be for labor, rigs or completions. I just wanted to see if you guys were seeing that same type of upward pressure and if you could comment on the broader service environment?

Yes, I think in the macro sense, you are going to see a tightening of services if everyone actually delivers on their increase in the horizontal rigs that they are talking about, you are going to see a massive infusion of horizontal rig activity here in the Permian in the second half of the year. So when you see that, even though there's still idled hydraulic horsepower being moved into the Permian, I think you are going to see a tightening on that side of the business specifically.

I don't understand how to predict very clearly what the future is going to hold but what I have challenged the organization with is that any increases in the cost of goods and services that could potentially materialize in the second half of the year, let's plan on offsetting those costs with continued efficiency gains.

So at the end of the day, two things can happen -- either we have offset it and we maintain our guidance or if we don't see an increase in the cost of goods and services, we have actually been able to take out 10% of our costs. So that is the challenge that is out there in front of the organization right now.

Okay, that is helpful. And then just a detail oriented question here. Can you remind us your acreage position in Dawson County and the northern part of Martin County as well?

Yes, in Dawson County, we've got 6500 net acres and in the rest of Martin County -- Adam, do you know how many acres in Martin County?

We have 4500 net in the original acquisition and then we added the East Kaden stuff, which is another 4500 in Southeast Martin maybe another 1000 bolt on in addition to that.

So about 10,000 in Martin County. And about, Ryan, in the Northeast Andrews County, we've got about 9000 acres up there.

Okay. That is helpful. Can you remind me, is this the first well that you drilled on either Dawson or Northern Martin County or were some of those other Martin County wells that you mentioned up in that block up there?

This is the first well that we have drilled in Dawson County, the Kent County School Lands but we have drilled one and reported on it in our offset data about a month ago, the Maybee Breedlove, that we talked about. And then also the Nail Ranch, both the Maybee Breedlove and the Nail Ranch are horizontal Wolfcamp B wells in Martin County. Both exceeding our expectations.

Okay, thank you.

Gail Nicholson, KLR Group.

Good morning, gentlemen. Can you talk about the differences or any differences that you might be seeing in wells that are flowing naturally longer versus the wells that you are putting on ESP sooner?

Yes, Gail, it is a good problem to have and it is really on the Gridiron well is the first well that we have really experienced having where we are over 30 days now and it is still flowing with 700 or 800 pounds of flowing casing pressure. So it has obviously got to be driven by a fundamental engineering principle so we've got better permeability, better pressure, better access to the wellbore as you flow the well back.

In a general sense, we don't plan on these wells flowing that long but we are certainly proud of that Gridiron well that has flowed so long. Normally we will put these wells on a sub pump within two to three weeks probably at the outside.

Okay, great. And then just looking at the Wolfcamp B reservoir thickness in Dawson County, how thick is that compared to the thickness of the Wolfcamp B down in the Spanish Trail area?

It is a little bit thicker in Dawson County. It's got a few more carbonate stringers in it than what we are typically accustomed to seeing like in Midland County but in terms of thickness, it is slightly thicker. But up in Dawson County it is not really as I mentioned earlier, it is not really a thickness issue as much as it appears to be a thermal maturity issue.

Okay, great. Thank you.

Michael Rowe, TPH.

Good morning. Thanks for taking my question. I was just wondering -- you talked about I guess just cost inflation earlier on the service side. I was wondering if you could comment on your thoughts regarding gas processing in the basin and just sort of any constraints that you all foresee on the processing side as you all begin to accelerate in the basin?

Michael, I think as we move into areas and develop areas horizontally that were originally developed vertically, you've got infrastructure near-term constraints because you can't move the amount of volumes from these horizontal wells through a gathering system that was designed for vertical wells. So we have got to work very closely and have been with our third-party processors to make sure we can get the gas through the plant. Two-thirds or more of my gas is dedicated to a plant that is North Midland called Coronado and they have just recently completed a 100 million a day plant expansion so they've got capacity now. We are just trying to make sure we've got the infrastructure in place to move the gas to the mouth of that plant so that we can get everything processed.

So you will continue to see near-term maybe quarter-over-quarter fluctuations of processing constraints. Particularly in the first quarter this year, you've got a lot of plant turnarounds that have been negative on our volume profile but those are more quarter-over-quarter events, not long-term events.

So it is one that we have to work very closely with our third-party business partners with to make sure we've got adequate processing capacity and the way we do that is share our plans and volume profiles with them so they can make their plans accordingly.

Okay, that is helpful. Just wanted to see honestly -- you had some great cost savings there in Upton County using the 3-well pad so just wondering if you all had plans to implement any more of these pads elsewhere on your acreage position?

Just looking at the drilling schedule right now, Michael, we've got two more in front of us that are 3-well pads and then we've got a large series of 2-well pads in front of us as well too. So we have got a five rig fleet right now, horizontal rig fleet right now and three of those rigs are capable of walking from well to well and that is where some of those cost savings come in.

So we look in the second half of this year for the majority of our wells to be drilled on 2-well and 3-well pads.

Okay, thank you.

(Operator Instructions). Joseph Reagor, ROTH Capital Partners.

Good morning, guys. Congratulations on a solid quarter. Looking at the current availability of funds, you have roughly I guess about $340 million between cash and the upgraded revolver. What is your thoughts as far as toward the end of the year possibly having room to add additional rigs on the existing acreage?

Joe, certainly from a liquidity perspective, we've got that capacity now with our increased revolver. Again, it gets more back to we make a decision not so much based on how much revolver we have but based more strategically on how our inventory looks and how quickly we can get it developed.

We actually have a sixth rig coming in the fourth quarter but we have yet to decide whether that is a sixth incremental rig -- will be an incremental rig or will be a replacement for one of the existing rigs and that decision is still going to be dependent upon the strategic outcomes of some of the northern acreage tests. So that is kind of how we think about it, Joe.

On that sixth rig right now would your guidance more reflect it as a replacement or as an incremental?

It is really a push either way. If the rig arrives in November, it will probably get one well drilled so that doesn't have any impact on our guidance. You might get a -- well I won't even say an exit buzz because we probably wouldn't have it completed then. So that rig is scheduled to arrive late in October, sometime in November so it is more of a 2015 decision.

And then on your existing acreage, what do you guys think the cap is for number of total rigs running? I know you said eight to 10 through additional acquisitions but if you didn't make additional acquisitions this year, what do you think the cap is there?

The way that our acreage is laid out, it is pretty blocky in each specific area and the more blocky it is, the more you could put one rig in each area so in the grand scheme of things, we could keep one rig busy in Martin County, one rig busy in Dawson County, one rig busy in Northeast Andrews County, one to two rigs busy in Midland County and then maybe two rigs busy in our new Martin County acquisition that we did in Southwest Martin County here earlier this year.

So that is kind of a cap of seven or so right now?

Yes, and depending on if the lower Spraberry works out in Upton County, that is another rig line down there so that could potentially be the eighth rig.

But again, that decision to pick up additional rigs is we are going to be very disciplined in that process to make that decision so I want to make sure I'm not signaling that we are going to be ramping to eight rigs between now and the end of the year because that is certainly not our expectations.

Okay. And then more of a conceptual question, how are you guys balancing the impact of newer technology on longer reach laterals with well spacing and the dynamics of how those costs are impacted?

Well, certainly, Joe, as you look at longer horizontals when you look at the cost efficiency, the capital efficiency, longer horizontals are more cost-effective. I think we have convinced ourselves that is the case and so to the extent our acreage geometry allows us to do that, we are going to drill out to 10,000 feet. The Gridiron well because we had an offset location I think the total measured depth of that well is like 24,000 feet so it is a really long total horizontal well. And we do that because of the lease geometry and we think that is the most capital efficient way.

But there are offsets on longer reach laterals primarily on the completion side. You are taking risks as you try to complete from 7500 feet to 10,000 feet and beyond as you pump floods down and you try to perforate -- and higher friction losses on the stimulation so slightly potentially less effective stimulations out on the toe. So these are all things that we watch our own results and we communicate with industry experts as well about kind of what is the leading edge thinking on that.

And then specifically to your question on inter-lateral spacing, we are currently testing 660 foot inter-lateral spacing right now and actively watching industry as they test even tighter spacing than that.

Okay. Thanks a lot, guys.

Thank you, Joe.

Thank you. That does conclude the Q&A session. I will now turn the call back over to Travis Stice, CEO, for closing remarks.

Thank you, Stephanie. Thanks again everyone for participating on today's call. If you have any questions, please reach out to us using the contact information provided. Thanks, everyone.

Thank you, ladies and gentlemen. That does conclude today's conference. You may all disconnect and everyone have a great day.