Good day, ladies and gentlemen, and welcome to the Diamondback Energy first quarter earnings conference call. At this time, all participants are in listen-only mode. Later, we'll conduct a question and answer session, and instructions will follow at that time. If anyone should require assistance, please press star then zero on your touchtone telephone. 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'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 Gridiron 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 Cline Shale, also known as the Wolfcamp D, during the third quarter.
Switching now to the first quarter, 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 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 a horizontal inventory, and we're 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 two-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 2,757 BOE 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 first horizontal Wolfcamp B well produced a peak 24-hour IP rate of 541 BOE with a 92% oil cut from an 8,543-foot lateral on ESP. We plan to test the Cline Shale, also known as the Wolfcamp D, 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 1,049 BOE per day with a 92% oil cut from a 4,418-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 a horizontal Lower Spraberry in the Midland Basin. We have just successfully drilled our first three-well pad in Upton County, where three roughly 5,000-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 three-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 derivative 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 effect of 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 positions 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 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 31st, 2014. Our agent lender has approved a borrowing base increase of 100% to $450 million based on our current reserves. As of March 31st, 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'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 paths, and operating with low-cost structures. These combine to drive our peer-leading cash margins, and I believe we continue to deliver results in 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'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 you. Ladies and gentlemen, to ask a question, please press star then one on your touch-tone telephone. If your question has been answered and you wish to remove yourself from the queue, you may press the pound key. Our first question comes from Jason Wangler with Wunderlich Securities. Your line is open.
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 prospective across the entire position for the Spraberry as well?
Yeah, I think certainly, when you look at the Spraberry in general, it's one of the more continuously deposited shales across the Midland Basin. 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.
I think you mentioned it in your comments, the Cline Shale test or the first well, I should say, I guess, is that going to be up north in Dawson? Just maybe if that's right, just the thought process of putting it up that way.
Yes, exactly. It'll be in Dawson County, 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 drilled a vertical well up there and cut a whole core, while the Wolfcamp B, the geochemical work confirms that we're in the oil generation window, when you move about 600 feet deeper into the Cline Shale, you're actually moving even further into what we call the peak oil window. That's why we, in the next couple of weeks, will spud that Cline test in Dawson County.
I appreciate it. I'll turn it back.
Our next question comes from Jeff Grant with Northland Capital Markets. Your line is open. Jeff, your line is open. Please unmute.
Can you guys hear me?
Yep.
Yeah, we got you now, Jeff.
Sorry, I was on mute. Just 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 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?
Yeah, 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. As it pertains to the capital allocation, we always look forward to trying to accelerate as much as our inventory forward as we can. What that depends on strategically is continued de-risking 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. It's about a three-by-three decision matrix, when it comes to trying to accelerate. That's certainly high on our priority list, is to try to accelerate as much inventory forward as we can.
Okay, great. Then on that topic of de-risking, 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. 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. Again, when it gets back to capital allocation, we're going to put the drill bit where we can generate the greatest shareholder returns. I think what you're going to see is a continued mix with perhaps more emphasis in the Lower Spraberry. In our most developed areas and our core areas, we're going to focus on a Wolfcamp B and a Spraberry development. Then, as I mentioned in my prepared comments, we've drilled and completed or in, I think we're day 8 flowback on the first Lower Spraberry horizontal well in Upton County.
Certainly, stay tuned for that because if that play pans out in the Lower Spraberry, that'll 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 Cline Shale, not only is that supported by the geochemical work that we talked about just a second ago, it's also supported by some significant operator tests in northern Martin County and northeast Andrews County, which support the prospectivity of the Cline that far north. That's one of the reasons we're excited about this Cline test as well.
Okay, great. Thanks for that color. Then, 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-$7.4 million range in your guidance. Maybe if you guys just have any generic well cost targets that you're trying to get by year-end or anything on that front.
Yeah, Jeff, at this point, I think it's still fair to stay within our guidance. I mentioned a three-well pad that we drilled down in Upton County. We've not completed it yet, but that three-well pad will take off around $500,000 for that three-well set. 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 foot-along lateral in Midland County. It was right at $9 million, and that's going to pay out in 120 days. We've just drilled and got casing on bottom on its offset, and we'll soon spud a third well on that acreage block. That's a 2,500-acre block that's undrilled with horizontal wells.
We're excited to follow that up. I like where we're headed on our costs, 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. Then just clarification, that $500,000 savings on the three-well pad, is that $500,000 per well, or is that an aggregate savings for the whole pad?
Aggregate savings for the whole pad. Again, we've got over 60 wells drilled, and we're pretty far down on the efficiency, in learning curve side of the equation. 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 & Company. Your line is open.
Morning, guys.
Hey, Dave. How are you today?
Well, thank you. I had a question maybe a little bit higher level in terms of just understanding specifically in the Wolfcamp B Midland-Andrews area, what sort of recovery of resource in place do you think you're currently achieving?
Yeah, Dave, that's 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. If you're looking for a ballpark number for the Wolfcamp B, I think somewhere 8%-10%, 8%-12%, something like that. Again, it's highly dependent on how you want to calculate original oil in place.
Sure. No, I appreciate that. 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, et cetera. You talk about now being able to squeeze out nickels and dimes as opposed to quarters, et cetera. Are you now 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.
Dave, that's a good question. As 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 job is the best way to stimulate these shales. We're going to continue to stay with slickwater. Maybe in a more macro sense, I think the spacing question is yet to be defined by the industry. While in Midland County, where we've got the most information, we're drilling interlateral spacing at 660 feet.
I think we're very actively watching other industry tests that are out there that are even increasing that down spacing further. To the extent that the industry proves up spacing or down spacing, 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 question comes from Jeffrey Connolly with Mizuho Securities. Your line is open.
Hey, good morning, guys. In the prepared remarks, you mentioned higher LOEs on the northern acreage because of less infrastructure. Can you just give us an overview of how the LOEs change versus your operating areas?
Well, specifically, we acquired the East Cowden asset earlier this year, picked up 147 vertical wells. Typically, these vertical wells have a little higher LOE than a horizontal well both from an absolute dollar perspective and the volume perspective when you look at a dollar per barrel metric. I anticipate, as we continue to move north and drill more and more horizontal wells and horizontal production becomes a higher % of the total, that you'll start seeing some adjustments to the LOE. Just as we incorporate straight out 147 vertical wells, you see just a slight uptick in the LOE until we get our horizontal rigs back to work up there.
All right. Thanks. That was helpful. Then can you just give us a quick overview of what you're seeing in the M&A market and what kind of prices, acreage packages, stuff like that? Any update?
Yeah. 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&A activity. 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. 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. 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 bones have been mine. They did that because they lost the discipline and ultimately paid too much. One thing that you can count on Diamondback is we're going to maintain that discipline as we grow, both organically and inorganically. What that means, though, is that while there's deals out there and you still see deal flow, this strategy means that we're not going to win every competitive auction that's out there, and we haven't. 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.
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've got a winning combination in Diamondback, and I think that's one that shareholders ought to be proud to own.
All right. Thanks, guys. I'll hop back in the queue.
All right. Thanks, Jeff.
Our next question comes from Michael Kelly with Global Hunter Securities. Your line is open.
Hey, guys. Good morning.
Good morning, Mike.
I'm looking at slide four 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 that was 42 Wolfcamp B locations that we had in Dawson. 42 out of that 316.
Okay. All right. Great. Not that much. Thanks. Maybe just sticking on the theme of organic versus inorganic growth there, Travis, I think it'd 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-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.
Yeah. Mike, the inorganic or organic, it's not really an either/or. I believe it's really an and. We've got to be able to effectively do both. 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. Usually, not all of them will hit. 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. At the end of the day, it's typically EBITDA per share is what we're looking for. Also just from an operations metric, F&D cost is another good one that we look at being accretive on an F&D perspective.
Got it. 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 rights up eight 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 third quarter, early fourth quarter of last year, was a once in a lifetime opportunity. I think that's probably still a likely perspective to take, at least in terms of large producing minerals, like what we were able to acquire. Are there other opportunities to pick up smaller bits and pieces of royalties or minerals? Yeah. That's certainly what we're going to continue to look for. 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.
Morning, Richard.
Travis, just sticking with the M&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&A?
Well, that's a great question, Richard. That's one, as an executive team, we struggle with quite a bit because I fielded a question earlier on accretive, how I define accretive acquisitions. One of the things that's not a hard and fast metric that we look at, but it's one that we have to consider is, if we do an acquisition, can we ensure to our stockholders that acquisition is not going to dilute our current execution efficiency? While I look to Jeff White, our VP of Operations, and Mike Hollars, our 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 into new acquisitions.
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. As a planning number, somewhere around that 8-10 horizontal rigs would be our bandwidth, and we're at five right now. That's how we're building the organization out right now, is to try to handle an 8-10 horizontal rig capacity.
Thank you. That's helpful. Just lastly from 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 dug through some of the details in the S-1 that just hit last night, you'll see that we actually filed confidentially 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 we've refiled it now publicly with the SEC, and we're somewhat limited by how quickly they turn the document. Since we've already gone through one turn, if we're somewhere in that 30-60 day timeframe, I think that would be a reasonable expectation.
Okay. Thanks a bunch. Appreciate it.
Our next question comes from Ryan Oatman 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.
Yeah. 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 of horizontal rig activity here in the Permian in the second half of the year. 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 that side of the business specifically. I don't understand how to predict very clearly what the future's going to hold. 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. At the end of the day, two things can happen.
Either we've offset it and we maintain our guidance, or if we don't see an increase in the cost of goods and services, we've actually been able to take out 10% in our costs. That's the challenge that's out there in front of the organization right now.
Okay. That's helpful. 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. In the rest of Martin County, Adam, you know how many acres in Martin County?
We have 4,500 net in the original acquisition, and then we added the East Cowden stuff, which is another 4,500 and something.
That is Martin, maybe another 1,000 bulk on in addition to that.
About 10,000 for that county.
Yeah.
About, Ryan, in Northeast Andrews County, we got about 9,000 acres up there.
Okay, that's 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 drilled in Dawson County, Kent County School lands, we've drilled one and reported on it in our ops update about a month ago, the Mabee Breedlove, that we talked about, also the Nail Ranch. Both the Mabee Breedlove and the Nail Ranch are horizontal Wolfcamp B wells in Martin County.
Perfect.
Both exceeding our expectations.
Okay. Thank you.
You bet, Ryan.
Our next question comes from Gail Nicholson with KLR Group, LLC. Your line is open.
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're putting on ESP sooner?
Yeah, 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 seven, 800 pounds of flowing casing pressure. It's obviously got to be driven by a fundamental engineering principle. 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 Gridiron well that has flowed so long. Normally, we'll put these wells on a sub-pump within two to three weeks, probably at the outside.
Okay, great. 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're typically accustomed to seeing in Midland County. In terms of thickness, it's slightly thicker. Up in Dawson County, 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 Rowe with TPH. 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 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 constraints because you can't move the amount of volumes from these horizontal wells through a gathering system that was designed for vertical wells. We've got to work very closely, and have been, with our third-party processors to make sure we can get the gas to the plants. Two-thirds or more of my gas is dedicated to a plant that's North Midland called Coronado, and they've just recently completed a $100 million a day plant expansion. They've got the 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. You'll continue to see near-term, maybe quarter-over-quarter fluctuations of processing constraints.
Particularly in the first quarter of this year, you got a lot of plant turnarounds that have been negative on our volume profile. Those are more quarter-over-quarter events, not long-term events. It's one that we have to work very closely with our third-party business partners with to make sure we've got adequate processing capacity. 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. Just wanted to see, honestly, you had some great cost savings there in Upton County using 3 well pads. Just wondering if you all had plans to implement any more of these pads elsewhere on your acreage position.
Yeah, just looking at the drilling schedule right now, Michael, we've got two more in front of us to the three well pads, and then we've got a large series of two well pads in front of us as well too. We've got a five rig fleet right now, a horizontal rig fleet right now, and three of those rigs are capable of walking from well to well, and that's where some of those cost savings come in. We're looking to second half of this year for the majority of our wells to be drilled on two well and three well pads.
Great. Thank you.
Again, ladies and gentlemen, to ask a question, please press star then one on your touchtone telephone. Our next question comes from Joseph Rager with ROTH Capital Partners. Your line is open.
Good morning, guys. Congratulations on another solid quarter.
Thank you, Joe.
Looking at the current availability of funds, you have roughly, I guess, about $340 million 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?
Yeah, Joe, certainly from a liquidity perspective, we've got that capacity now with our increased revolver. Again, we make the 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've yet to decide whether that's a sixth incremental rig, will be an incremental rig, or will be a replacement for one of the existing rigs. That decision is still going to be dependent upon the strategic outcomes of some of the northern acreage tests. That's how we think about it, Joe.
On that sixth rig right now, would your guidance more reflect it as a replacement or as a incremental?
It's really a push either way. If the rig arrives in November, it'll probably get one well drilled. That doesn't have any impact on our guidance. You might get a, well, I wouldn't even say an exit buzz, because we probably wouldn't have it completed then. That rig's scheduled to arrive late October, sometime in November. It's more of a 2015 decision.
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, 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, and the more blocky it is, the more you could put one rig in each area. 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 southeast or southwest Martin County here earlier this year.
Kind of a cap of seven or so right now.
Yeah. Depending on if the Lower Spraberry works out in Upton County, that's another rig line down there, that could potentially be the eighth rig. Again, that decision to pick up additional rigs is we're going to be very disciplined in that process to make that decision. I want to make sure I'm not signaling that we're going to be ramping to eight rigs between now and the end of the year, because that's certainly not our expectations.
Okay. 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've convinced ourselves that's the case. So to the extent our acreage geometry allows us to do that, we're 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. 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. There are offsets on longer reach laterals, primarily on the 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, slightly potentially less effective stimulations out on the toe. 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. Then specifically to your question on interlateral spacing, we're currently testing 660 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&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 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. Everyone, have a great day.