Day, ladies and gentlemen, and welcome to the Diamondback Energy First Quarter Earnings Conference Call. At this time, all participants are in a listen only mode. Later, we'll conduct a question and answer session and instructions will follow at that time. 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 Q1 conference call. Representing Diamondback today are Travis Stice, CEO Tracy Dick, CFO and Russell Panemol, 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 Q1 2014 conference call. Since our last call, we've 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 grid iron well in Midland County is the best well we've drilled to date and also appears to be one of the top horizontal wells in the Midland Basin.
As we've said before, we've increased our development focus on the Lower Spraberry with wells now drilled in both Midland and Upton County. 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 Klein Shale also known as the Wolfcamp D during the Q3. Switching now to the Q1. I'm 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're 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 Q1 coming in at nearly $67 a BOE, which is up from $64 a BOE in the Q4 of 2013. We continue to be an aggressive developer of our horizontal inventory and we're operating 5 horizontal rigs as previously planned. We expect to grow production by more than 125% this year. We are currently running 3 horizontal rigs on our acreage in Midland County, 1 in Upton County and 1 in Martin County. As a reminder, we report all of our well results on a 2 stream basis.
In Midland County, we're excited about our most recent Wolfcamp B test, the Gridiron 1H, our highest 24 hour IP rate to date at 2,757 barrels of oil equivalent per day with a 91% oil cut that was drilled with an 8,785 foot lateral and is still flowing back. In Dawson County, our 1st horizontal Wolfcamp B well produced a peak 24 hour IP rate of 5.41 barrels of oil equivalent with a 92% oil cut from an 8,543 foot lateral on ESP. We plan to test the Kline Shale also known as the Wolfcamp B on this acreage during the Q3. 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 spray very well in Midland County produced a peak 24 hour IP rate of 10.49 barrels of oil equivalent per day with a 92% oil cut from a 4,418 foot lateral thus far on ESP.
Additionally, we're currently flowing back our 1st Lower Spraberry well in Upton County that we believe is the southernmost test of a horizontal Lower Spraberry in the Midland Basin. We've just successfully drilled our first three well pad in Upton County where 3 roughly 5000 foot laterals in the Wolfcamp B were drilled in less than 40 days. While these wells are not yet completed, we've 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're consistently at or above our type curve projections and within our cost guidance. I think this is significant in that we've now drilled over 60 horizontal wells since our IPO less than 18 months ago.
That's 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 Q1 was $23,600,000 or $0.48 per diluted share. Net income for the period included a non cash loss on commodity derivatives of $3,300,000 Excluding the non cash loss and the related income tax effect, our adjusted net income was 25,700,000 dollars or $0.53 per diluted share. As previously reported, our production for the Q1 was approximately 13,600 BOE per day and 79% of this production was oil. These volumes generated revenues in the Q1 of $98,000,000 and EBITDA of 81,300,000 dollars Our average realized price before the effective hedges for the Q1 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 Q1. Our general and administrative costs came in at $3.74 per BOE, which includes non cash stock based compensation of $2,200,000 Excluding stock based compensation, G and A costs are $1.94 per BOE. Interest expense on our income statement for the quarter was $6,500,000 We capitalized 2 $9,000,000 of interest to our full cost pool. Our current hedge positions through 2015 have been laid out in our earnings release.
We currently have 50 percent 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'll continue to layer on additional hedges as our production grows. In the Q1 of 2014, we generated $71,000,000 of operating cash flow $80,000,000 of discretionary cash flow or $1.46 $1.64 per diluted share respectively. During the Q1 of 2014, we spent $86,400,000 for drilling, completion and infrastructure. Additionally, we spent approximately $312,200,000 on leasehold acquisitions.
Our liquidity position remains strong with approximately $25,000,000 of cash on hand at March 31, 2014. Our agent lender has approved a borrowing base increase of 100 percent to $450,000,000 based on our current reserves. As of March 31, 2014, the revolver has $147,000,000 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'll turn the call back over to Travis for his closing remarks.
Thank you, Tracy. To summarize, I'm 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-one with the Securities and Exchange Commission in connection with its proposed initial public offering of limited partnership interest. Because the S-one is on file, I'm 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.
Thank Our first question comes from Jason Wangler with Wunderlich Securities. Your line is open.
Good morning, guys. Hey, Jason.
Just curious, obviously, the 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're going to be pretty perspective across the entire position for the Spraberry as well?
Yes. I think certainly when you look at the Spraberry in general, it's 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's great. And then just I think you mentioned it in your comments, but the Klein shale test or the first well I should say I guess is that going to be up north in Dawson? And just maybe if that's right just the thought process of putting it up that way?
Yes, exactly. It will be in Dawson County. And really what we're doing is we're capitalizing on some additional work that we've got since we drilled that first well, the Kent County School Lands. We cut a whole core on the we drilled a vertical well up there and cut a whole core. And while the Wolfcamp B, the geochemical work confirms that we're in the oil generation window.
When you move about 600 feet deeper in the Klein Shale, you're actually moving even further into what we call the peak oil window. So that's why we in the next actually the next couple of weeks we'll spud that client test in Dawson County.
I appreciate it. I'll turn it back.
Our next question your line is open. Please unmute.
Can you
guys hear me? Yes. Yes,
we got you now, Jeff.
Sorry, I was on mute. Just kind of a strategic question for you guys. If and when this Viper offering goes through, obviously, you guys your liquidity position would improve significantly, giving you guys a lot more flexibility to accelerate. I was wondering what obviously, other than just a 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?
Yes. Jeff without any specific comments on the Viper transaction that's 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 trying to accelerate as much as our inventory forward as we can. And what that depends on strategically is continued derisking of some of the northern blocks, which we're starting to feel pretty comfortable on, as well as infrastructure issues like access accumulation and disposal of stimulation water. So it's really it's about a 3 by 3 decision matrix when it comes to trying to accelerate.
But that's 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 derisking, has any of the recent activity either by yourselves or industry really changed your thoughts on rig allocation or maybe development of other formations? Obviously, you focus mostly on the B bench and you're getting good results in the Spraberry. But have you guys really changed your thoughts recently on where you're going to focus the majority of either your rig count or on a well count basis?
Well, 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're going to put the drill bit where we can generate the greatest shareholder returns. And I think what you're going to see is a continued mix with perhaps more emphasis in the Lower Spraberry. But in our most developed areas and our core areas, we're 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 our end, I think we're day 8 flowback on the 1st 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. Then lastly, just the northern acreage, specifically up in Dawson County. I mentioned our next test is in the Klein Shale. And not only does that is that supported by the geochemical work that we talked about just a second ago, but it's also supported by some significant operator test in Northern Martin County and Northeast Andrews County, which support the prospectivity of the client that far north. So that's one of the reasons we're excited about this climb test as well.
Okay, great. Thanks for that color. And then last one for me just kind of hoping to get an update on maybe what recent well costs have been for you guys and maybe relating that to that $6,900,000 to $7,400,000 range in your guidance or maybe if you guys just have any generic well cost targets that you're trying to by year end or anything on that front?
Yes. Jeff, at this point, I think it's still fair to stay within our guidance. I mentioned a 3 well pad that we drill down in Upton County. We've 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're going to be biased at the low end of our range. To the extent we're still drilling single wells, we'll be probably at the midpoint of that range. I gave you a data point on that portal long lateral in Midland County. It was right at $9,000,000 and that's going to pay out in 100 and 20 days. And we've just drilled and got casing on bottom on its offset and we'll soon spud a third well on that acreage block.
And that's a 2,500 acre block that's undrilled with horizontal wells. So we're excited to follow that up. But I like where we're headed on our and we'll just have to maintain the discipline and focus on execution to make sure our costs are biased towards the low end.
Okay, great. Thanks for that color. And then just kind of clarification that $500,000 savings on the 3 well pad, is that $500,000 per well or is that kind of an aggregate savings for the whole pad?
Aggregate savings for the whole pad. And again, we've got this is we've got over 60 wells drilled and we're pretty far down on the efficiency and learning curve side of the equation. So we're picking up pennies and nickels at this point every day.
Okay. That's it for me. Thanks guys. Good quarter.
You bet. Thanks, Jeff.
Our next question comes from Dave Kistler with Simmons and Company. Your line is open.
Good morning, guys. Hey, Dave. How are you today?
Well, thank you. I had a question maybe a little bit high 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're currently achieving?
Yes. Dave, that's a hard number for the industry to try to come up with and it all depends how you want to calculate oil in place. But if you're 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's highly dependent on how you want to calculate original oil in place.
Sure. No, I appreciate that.
And kind of just to where I've
taken the question is, you guys have certainly been leading the way in terms of driving down well costs and delivering on efficiency gains etcetera. And you talked about now being able to kind of squeeze out nickels and dimes as opposed to quarters etcetera. 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'm just curious to get your thought process on that.
Yes, Dave that's a good question. We as engineers we always like the engineers and geoscientists we always like to try to tweak things. And I think you'll see that in some of our completion designs, they're tweaks, but they're not major overhauls. We've been and have proven to ourselves that a slickwater shop is the best way to stimulate these shells. So we're going to continue to stay with the slickwater.
But maybe on a more macro sense, I think the spacing question is yet to be defined by the industry. And while in Midland County where we've got the most information, we're drilling inter lateral spacing at 6 60 feet. I think we're 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 uptight or downspacing, we'll like we always do, we'll be a fast follower to that decision point.
Perfect. I really appreciate that color. Thanks so much guys.
You bet, Dave. Thanks.
Our next
on the northern acreage because of less infrastructure. Can you kind of just give us an overview of how the LOEs change versus your operating areas?
Well, specifically on the we acquired the East Calhoun asset earlier this year picked up 147 vertical wells. And typically these vertical wells have a little higher LOE than a horizontal well from a both from an absolute dollar perspective and the 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'll 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 kind of get our horizontal mix back to work up there.
Thanks. That was helpful. And then can you just give us a quick overview of what you're seeing in the M and A market and what kind of prices acreage packages stuff like that? Any update?
Yes. Jeff, there's no doubt that the Permian Basin has been one of the hottest basins in our whole industry when it comes to M and 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've 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're only going to do deals that are accretive to our shareholders. And that's 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 loans have been mine.
And they did that because they lost the discipline and ultimately paid too much. So one thing that you can count on Diamondback is we're going to maintain that discipline as we grow both organically and inorganically. Now what that means though is that while there's deals out there and there's still you still see deal flow, this strategy means that we're not going to win every competitive auction 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 as I just outlined there with our best in class organic growth story, I think you got a winning combination in Diamondback and I think that's one that shareholders ought to be proud to
own. Thanks guys. I'll hop back in the queue.
All right. Thanks, Jeff.
Our next question comes from Mike Kelly with Global Headquarter Securities. Your line is open.
Hey, guys. Good morning. Good morning, Mike.
I'm looking at slide 4 of your most recent slide deck here and just looking at your inventory count by area and by zone. If I look at the Wolfcamp B, you've 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 it was 42 Wolfcamp V locations that we had in Dawson. So 42 out of
that 316. Okay. All right. Great. So not that much.
Thanks. And then maybe just sticking on the theme of kind of organic versus inorganic growth there Travis. Maybe I think it would be helpful for me to hear kind of what you deem as accretive here and just that balance between we add inventory at the end of kind of a 10 plus year inventory life right now versus really just breaking out production growth on a debt adjusted per share basis today? How you think about that? What really is accretive for shareholders?
Thanks.
Yes. Mike, it's not really the inorganic or organic, it's not really an either or. I believe really an and we've got to be able to effectively do both. And when we look at accretive acquisitions or we look at metrics that describe an accretive acquisitions, it's things like EBITDA per share, production reserves, those type parameters. And usually not all of them will hit.
So it becomes a 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's typically EBITDA per share is what we're looking for. And then also just from operations metrics, F and D cost is another good one that we kind of look at being accretive on an F and D perspective.
Got it. And I know
you can't talk too much about Viper here if at all, but just wondering 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've done here after picking these mineral lights up 8 months ago? Thanks.
You bet. Mike, I think I've been on the record several times at least from my perspective that mineral acquisitions like the one we did in the late Q3, early Q4 of last year was a once in a lifetime opportunity. So I think that's probably still a likely perspective to take at least in terms of large producing minerals like what we're able to acquire. But are there other opportunities to pick up smaller bits and pieces of royalties or minerals? Certainly what we're going to continue to look for.
So we've added bits and pieces along the way even since we did the original Minerals acquisition and we're 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.
Our next question comes from Richard Tullis with Capital One. Your line is open.
Thanks. Good morning, everyone. Good morning, Richard. Travis, just sticking with the M and A theme. You guys have made a lot of progress lowering well cost, operating cost.
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 and A?
Well, that's a great question, Richard. That's 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 it's not hard and fast metric that we look at, but one that it's 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 efficiency? So I look to Jeff White, VP of Operations and Mike Hollister, VP of Drilling specifically to make sure that as we talk about acquisitions that they can continue to execute on the best in class fashion with rolling in the new acquisitions. And so what we've charged each other with is that we need to build an organization that's scalable.
And that means that we can maintain the current best in class execution at the same time pick up additional rigs. Kind of as a planning number somewhere around that 8 to 10 horizontal rigs would be sort of our bandwidth and we're at 5 right now. So that's how we're building the organization out right now is to try to handle an 8 to 10 horizontal rig capacity.
Thank you. That's helpful. And just lastly for me, I don't want to get into the details of your proposed transaction as you mentioned, but can 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-one that I just hit last night, you'll see we actually filed confidentially a month and a half ago a month and a half or so. And we've actually gone through one cycle with the SEC and that's where we're at right now. We're in a quiet period because it's we've refiled it now publicly with the SEC and we're somewhat limited by their how quickly they turn the document. But since we've already gone through one turn, if we're somewhere in that 30 to 60 day timeframe, I think that would be a reasonable expectation.
Okay. Thanks a bunch. Appreciate it.
Our next question comes from Ryan Ozan with SunTrust. Your line is open.
Hi, good morning.
Hey, good morning, Ryan.
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 a macro sense you're going to see a tightening of services if everyone actually delivers on their increase in horizontal rigs that they're talking about you're going to see a massive infusion horizontal rig activity here in the Permian in the second half of the year. So when you see that, even though there's still idle hydraulic horsepower being moved into the Permian, I think you're going to see a tightening on tightening in that side of the business specifically. I don't I can't get into 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.
And so at the end of the day, 2 things can happen. Either we've offset it, we maintain our guidance or if you don't see an increase in the cost of goods and services we've actually been able to take out 10% of our cost. So that's the challenge that's out in front of the organization right now.
Okay. That's helpful. And then just detail oriented question here. Can you remind us your acreage position in Dawson County and then the northern part of Martin County as well?
Yes. In Dawson County, we've got 6,500 net acres. And in the rest of Martin County, Adam, you know what the acres in Martin County?
We have 4,500 net in the original acquisition and then we added the East Cowen stuff, is another 4,500 in Southeast, Martin, maybe another 1,000 bolt on in addition to that. So less than 1,000 in
that camp.
And about Ryan in Northeast Andrews County we get about 9,000 acres up there.
Okay. That's helpful. And can you remind me is this the first well that you drilled on either Dawson or Northern Martin County or some of those other Martin County wells that you mentioned up in that block up there?
This is the first well that we drilled in Dawson County, Kent County School lands, but we've drilled 1 and reported on it in our offset data about a month ago, the Navy Breedlove that we talked about and then also the Nail Ranch. Both the Navy Breedlove and the Nail Ranch are horizontal Wolfcamp B wells in Martin County. Perfect. Both exceeding our expectations.
Okay. Thank you.
Ryan.
Our next question comes from Gail Nicholson with KLR Group. Your line is open. Good morning, talk about the differences or any differences that you might be seeing in wells that are flowing naturally longer versus the wells that you're putting on ESP sooner?
Yes. Gail, it's a good problem to have and it's really on the gridiron well is the first well that we've really experienced having where we're over 30 days now and it's still flowing with 700 to 800 pounds of flowing casing pressure. So it's obviously got to be driven by fundamental engineering principles. 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're certainly proud of that grid on well that has flowed so long.
Normally, we'll put these wells on a sub pump within 2 to 3 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's a little bit thicker in Dawson County. It's got a few more carbonate stringers in it than what we typically accustomed to seeing in like in Midland County. But in terms of thickness, it's slightly thicker. But up in Dawson County, it's not really as I mentioned earlier, it's not really a thickness issue as much as it appears to be a thermal maturity issue.
Okay, great. Thank you. Our next question comes from Michael Vo with TCH. Your line is open.
Hi, 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 continue to accelerate in the basin?
Well, Michael, I think as we move into areas and develop areas horizontally that were originally developed vertically, you've got infrastructure near term for vertical wells. So we've got to work very closely and have been with our 3rd party processors to make sure we can get the gas to the plants. 2 thirds or more of my gas is dedicated to a plant that's North Midland called Coronado. And they just recently completed 100,000,000 a day plant expansion. So they've got capacity now.
We're 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'll continue to see near term maybe quarter over quarter fluctuations of processing constraints, particularly in the Q1 of this year. We get 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's one that we have to work very closely with our 3rd 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's helpful. And just wanted to see, honestly, some you had some great cost savings there on the in Upton County using pre rolled pads. So just wondering if you had plans to implement any more of these pads elsewhere on your acreage position? And then you
have Yes. Just looking at the drilling schedule right now, Michael, we've got 2 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've got a 5 rig fleet right now, horizontal rig fleet right now and 3 of those rigs are capable of walking from well to well and that's where some of those cost savings come in. So we look into second half of this year for the majority of our wells to be drilled on 2 well and 3 well pads.
Great. Thank you.
Our next question comes from Joseph Reagor with ROTH Capital Partners. Your line is open.
Good morning, guys. Congratulations on another solid quarter. Looking at the current availability of funds, you have roughly I guess about $340,000,000 between cash and the upgraded revolver. What's your thoughts as far as towards the end of the year possibly having room to add additional rigs on the existing acreage?
Yes. 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 6th rig coming in the Q4, but it's but we've yet to decide whether that's a 6th incremental rig, will be an incremental rig or will be a replacement for 1 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's kind of how we think about it, Joe.
On that $6,000,000 right now, would your guidance more reflect it as a replacement or as a incremental?
Well, it's really a push either way. If the rig arrives in November, it'll probably get one well drilled. So that doesn't have any impact on our guidance. You might get a well, I wouldn't even say an exit bus because we probably wouldn't have it completed again. So that really scheduled to arrive late October sometime in November.
So it's 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 8 to 10 through additional acquisitions, but if you didn't make additional acquisitions this year, what do you think the cap is there?
Well, the way that our acreage is laid out, it's pretty blocky in each specific area. The more block it is, the more you could put 1 rig in each area. So in the grand scheme of things, we could keep 1 rig busy in Martin County, 1 rig busy in Dawson County, 1 rig busy in Northeast Andrews County, 1 to 2 rigs busy in Midland County and then maybe 2 rigs busy in our new Martin County acquisition that we did in Southeast or Southwest Martin County here earlier this year.
So kind of a cap of 7 or so right now?
Yes. And depending on if the Lower Spraberry works out in Upton County, that's another rig line down there. So that could potentially be the 8th rig. But again, we just want to that decision to pick up additional rigs is we're going to be very disciplined in that process to make that decision. So, we'll make sure I'm not signaling that we're going to be ramping the 8 rigs between now and the end of the year because that's certainly not our expectations.
Okay. And then more of
a conceptual question. How are you
guys balancing the impact of like 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've convinced ourselves that's the case. And so to the extent our acreage geometry allows us to do that, we're going to drill out to 10,000 feet. The Good Iron well, because we had an offset location, I think the total measured depth of that well is like 24,000 feet. So it's a lot it's a really long total horizontal well.
And we do that because of the lease geometry and we think that's the most capital efficient way. But there are offsets on longer reach laterals primarily on completion side. I mean you are taking risks as you try to complete from 7,500 feet to 10,000 feet and beyond as you pump plugs down and you try to perforate higher friction losses on your 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 interlateral spacing, we're currently testing 6 60 foot interlateral spacing right now and actively watching industry as they test even tighter spacing than that.
Okay. Thanks a
lot guys. Thanks, Joe.
Thank you. That does conclude the Q and A session. I will now turn the call back over Travis Stice, CEO for closing remarks.
Thank you, Stephanie. Thanks again everyone for participating in 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.