Aug 5, 2017
Executives
Mark Brewer - Director, IR Joe Gatto - President and CEO Gary Newberry - COO Correne Loeffler - Treasurer and CFO
Analysts
Chris Stevens - KeyBanc Neal Dingmann - SunTrust Gabe Daoud - JP Morgan Will Green - Stephens Dan McSpirit - BMO Capital Markets Ron Mills - Johnson Rice & Company Jeb Bachmann - Scotia Howard Weil Mike Kelly - Seaport Global
Operator
Good morning, and welcome to the Callon Petroleum Company’s Second Quarter Financial and Operating Results Conference Call. All participants will be in a listen-only mode.
[Operator Instructions] After today’s presentation, there will be an opportunity to ask questions. [Operator Instructions] Please note this event is being recorded.
A replay of this event will be available on the Company’s website for one year. I would now like to turn the conference over to Mr.
Mark Brewer, Director of Investor Relations, for opening remarks. Please go ahead, sir.
Mark Brewer
Thank you, Operator. Good morning, and thank you, everyone, for taking the time to join our conference call.
With me this morning are Joe Gatto, President and Chief Executive Officer; Gary Newberry, our Chief Operating Officer; and Correne Loeffler, our Treasurer and Chief Financial Officer. During our prepared remarks, we’ll be referencing the earnings results presentation we posted yesterday afternoon to our website, so I encourage everyone to download the presentation if you haven’t already.
You can find the slides on our Events & Presentations page located within the Investor Relations section of our website at www.callon.com. Before we begin, I would like to remind everyone to review our cautionary statements and important disclosures included on Slides 2 and 3 of today’s presentation.
We will make some forward-looking statements during today’s call that refer to estimates and plans. Actual results could differ materially due to the factors noted on these slides and in our periodic SEC filings.
We will also refer to some non-GAAP financial measures today, which we believe help to facilitate comparisons across periods and with our peers. For any non-GAAP measures we reference, we provide a reconciliation to the nearest corresponding GAAP measure.
You may find these reconciliations in the appendix to the presentation slides and in our earnings press release, both of which are available on the website. Following our prepared remarks, we will open the call for Q&A.
With that, I’d like to turn the call over to Joe, and direct the audience to Slide 4 of the earnings presentation.
Joe Gatto
Thanks, Mark, and thanks, everyone for joining us this morning. Before I start, I wanted to welcome Mark to his first earnings call with Callon.
As you may know, Mark is a recent addition to our team, and will be leading our Investor Relations effort and our ongoing dialogue with investors and research analysts in the future. Unfortunately, this is also our first earnings call without our former Chairman, Fred Callon.
He will be greatly missed on this and future calls, but will always remain a big part of our organization and our accomplishments going forward. Turning to the presentation slides and second quarter results.
We delivered another solid quarter of production growth, coupled with steadily improving cost efficiency across our asset base. Given the oil production mix of almost 80%, and a 15% sequential reduction in LOE per BOE, our cash margins continue to rival those of our peer group.
We are also pleased to report several data points from our drilling program as positive implications for our inventory and resource optimization efforts. In WildHorse, our Wolfcamp A development program has been successfully delineated across our entire Howard County position, most recently to the Southeast portion of our footprint.
In Spur, the 2 wells we inherited from our initial acquisition into the Delaware basin continue to perform well, providing a strong base line for us to further enhance with refine completion techniques and landing zones in upcoming wells. And in Monarch, after 3 down-spacing tests began in 2015, we are increasing our well density to 13 wells in the Lower Spraberry on the heels of sustained well performance coupled with encouraging pressure data.
We are currently running 4 operated rigs, including the addition of a dedicated Delaware basin rig last month. As we’ve discussed, we remain focused on a measured increase in activity over time, including the addition of our fifth operated rig in early 2018.
When we laid out this plan earlier this year, we had a place called up for this rig to be in the Midland Basin, since we had just closed our Delaware acquisition at that time. After taking the time to refine our longer-term development scheme for Spur, we now expect the fifth rig to be dedicated to that area, and have 2 rigs running in the Delaware in 2018.
An update on our near-term milestones for 2017 are laid out on Slide 5, including the arrival of our second dedicated frack fleet a few weeks ago, and visibility for the completion of our infrastructure initiatives in the WildHorse area that will greatly improve capital and production efficiencies. As we continue to execute on our plans, we currently forecast over 40% production growth over the course of 2017 with the fourth quarter exit rate approaching 30,000 BOE per day.
All portion of this strong sequential growth in the year end is a function of debottlenecking in the WildHorse area. Our production expectations are underpinned by deep inventory of core drilling locations across the entire drilling program.
The bottom right hand chart highlights just how many -- just how competitive our cumulative well production volumes on a total company basis are relative to a broad set of well respected offset operators in the Permian. Moving to slide 6 and a longer-term outlook for the business, we’ve outlined our key guide post for our future plans.
Above all, we are committed to responsible growth plan, meaning; one, before we add incremental rigs, we need to have a visible near term path to free cash flow neutrality, ensuring that our cash inflows and outflows are never too far apart in order to navigate commodity price volatility; and two, corporate level returns on capital matter to us. We made some transformative acquisitions since early 2016 and we focused on delivering returns on the capital we deployed to finance these attractive asset bases.
So with those points in mind, we provide an outlook that stays true to these points. This baseline scenario assumes moving to five rigs in early 2018 and then held flat.
Under our activity assumption, we would expect compounded annual production growth of approximately 35% through 2019. Importantly, as you can see in the top right hand chart, we would also expect to have visibility to free cash neutrality by the first half of 2019 and meaningful cash flow generation later that year, providing the opportunity for incremental rig activity by mid 2018.
And in terms of returns on capital employed, we’ve float the chart from a recent research report that demonstrates how competitive our forecast metrics are relative to the peer group, as we unlock the potential of our expanded Permian footprint. In sum, we firmly believe the philosophy related to growth positions us to deliver meaningful production gains without sacrificing returns, and also enables us to outline credible activity plans for our service providers and should be biased upward and not downward overtime.
I will now turn the call over to Gary Newberry, our Chief Operating Officer to provide an update on the operational front.
Gary Newberry
Thanks Joe and good morning to everyone listening in today. Let me begin with slide 7, and highlight the continued progress we have made in reducing our operating cost during the second quarter.
The infrastructure investments that we’ve made in the first half of this year on the properties that we acquired last year have already started to bear fruit. By putting the Callon imprint on these assets, especially at our WildHorse area in Howard County, we have been able to get much more efficient, which has translated into a step change improvement in our per unit lease operating expenses year-to-date.
As we have guided to previously, these projects in Howard are still ongoing and we expect to have our core footprint at WildHorse all set up from an infrastructure standpoint by the end of the third quarter. Therefore, while we do expect that our LOE could move around slightly from quarter-to-quarter for the remainder of the year, a second consecutive strong quarter has us on target to beat our original guidance for the full year.
We completed roughly 10 net wells in the second quarter with the bulk of that activity concentrated at WildHorse, where we ran two continuous rigs. I will provide some detail around our recent results there in upcoming slides.
Early last month, we initiated our operated development program at our Spur assets in the Delaware basin with the arrival of our fourth rig, and first dedicated Delaware rig in Ward County. Along with the 3 rigs that we continue to operate in the Midland Basin, the addition of the fourth rig will allow our net completions per quarter to continue to trend up throughout the remainder of the year.
We also took delivery of our second dedicated frack fleet from ProPetro last month to stay squarely on pace to complete a total of 42 net wells in 2017. Our second half 2017 activity will be well balanced across our 4 operating areas, as our ongoing development of Monarch and WildHorse are supplemented by our first operated wells at Ranger since 2015, and we kicked off our development in the Delaware basin.
Our Spur program will start with 2 single-well pads in the Lower Wolfcamp A, as we get our feet wet before transitioning to our typical multi-well pad development during the fourth quarter. Moving to Slide 8, as I’ve previously mentioned, we basically had 2 dedicated rigs running at WildHorse since we picked up our third rig back in January.
The second quarter in Howard County was highlighted by our successful step out to the furthest Southern and Eastern extents of our acreage. With the stellar early-time results from the Colonial and Wyndham wells, which are currently tracking at or above 1 million barrel oil equivalent type curve.
We’ve successfully delineated the strength of the Wolfcamp A across our Howard County position. Our other key focus at WildHorse during the second quarter was the progression of our infrastructure initiatives, which are instrumental in the development of this new operating area, and play a major part in our efforts to get as efficient as we are on our legacy properties at Monarch and Ranger.
As you can see, we have made great strides in getting this asset properly set up for development mode, and we expect to wrap that work up in the third quarter. Since our first quarter call, we’ve gotten a number of questions on the Lower Spraberry at WildHorse.
On Slide 9, you can that our Lower Spraberry wells have tracked our acquisition type curve of 850,000 barrels of oil equivalent. The 8 wells that make up this body of work is what constitutes the established base referenced in the title of this slide.
As you can see in the plot on the lower left-hand side of the slide, the Lower Spraberry in Howard County exhibits a similar flat-decline profile as what we have seen in its Midland County counterpart at Monarch. However, some of our recent wells have come on a bit slower and taken a bit longer to clean up, causing them to lag the type curve early time before eventually converging with the curve.
We attribute this to a change that we made in frack design during some of our early operated completions. Prior to completing our first operated Lower Spraberry well at WildHorse, we have seen a step-change improvement in performance in both the Wolfcamp A and Howard County, and then the Lower Spraberry in Midland County, about moving through a higher intensity stimulation, including more sand and fluid pumped to with tighter stages.
However, we did not see the same kind of beneficial impact from shifting to a similar design in Howard County on the Lower Spraberry. We have a couple of initiatives planned for the second half to help accelerate the clean-up phase of these wells, and get them to ramp to peak rates sooner.
First we are optimizing our stimulation design to control frack tight, and focus the completion near to the wellbore by throttling back on sand and fluid loading and employing diverters. Additionally, we believe that our infrastructure build will play a meaningful role here.
By increasing our peak-produced fluid capacity, we will be able to dewater these wells more quickly, and improve the early-time ramp of the Lower Spraberry’s oil cut. So while we are happy with how this information -- this formation has played out thus far, we believe that we have a visible path to additional upside.
Shifting gears to the Delaware basin. Slide 10 is an overview of the initial Wolfcamp results at Spur, and a first look at some of our plans for our recently initiated operated development program.
It is important to note for context, the 2 wells highlighted in the bar chart at the top left of the slide were drilled by our predecessor operator, we also selected the landing zone for those wells and designed the completions. The Corbets wells -- well was completed between signing and closing of the acquisition, so we did not have any say in the recipe for the first test of the Wolfcamp A.
While we did have an opportunity to change the frack on the Saratoga well before it was completed in the Wolfcamp B, we elected to proceed with the stimulation as it was designed to give us the best apples-to-apples comparison between the two zones. The bar chart at the top left of the slide provides a side-by-side comparison of how the 2 wells are trending against our acquisition type curve on a lateral-foot basis.
We provided an early look at the Corbets well last quarter, and that well continues to perform very nicely, and stacks up well against our robust 1.6 million barrel oil equivalent lower Wolfcamp A expected EUR. On the Saratoga well, the prior operator ran into some issues with the well cements job, and as a result, we were only able to complete 5,900 feet of the 10,000 feet drilled lateral.
However, when normalized through a -- on a pro-lateral foot basis, this well is tracking our 900,000 barrel oil equivalent type curve for the B. Long story short, these wells are performing in line with our expectations, and we see ample upside to this performance through the optimization of both the completion design detailed in the bottom left, and the targeted landing zones illustrated on the right-side of the slide.
As previously mentioned, our first Delaware dedicated drilling rig kicked off this operated program last month, and is currently drilling our first Wolfcamp A well at Spur. Lastly, as you may have seen highlighted in our earnings press release, we now expect to allocate our fifth overall rig to Spur, when it arrives during the first quarter of 2018, and run 2 dedicated rigs in the Delaware basin for the balance of the year versus prior plans and guidance of running just 1 rig in the Delaware basin and 4 rigs in the Midland Basin.
This change comes directly from the strong early results, and our excitement over putting our imprint on how these wells get drilled and completed. Moving on to the first of our 2 legacy operating areas on Slide 11.
You can see that the second quarter 2017 was highlighted by clear confirmation of 13 wells per section spacing in the Lower Spraberry at Monarch. The plots on the right-hand side of the page highlight the results from 2 different pilot programs covering both upper and lower flow units that together gave us the confidence that a 13 well stacked and staggered pattern across 2 flow units within the Lower Spraberry is the best way to develop the formation.
Each pilot included a series of test pads, and the pilot reflected on the upper right-hand side of the page we developed an entire section for an individual flow unit over time on analogous spacing through the 13 wells stacked and staggered pattern. With each successive pad, the average well performance materially improved, with the infill wells outperforming the parent wells, despite the parent wells having been on for some time.
We feel comfortable that there is ample resource in place to be shared among the seven wells in the Lower Spraberry in our 13 well pattern. The bottom right graphic on the page shows our two most recent pads that tested co-development of the upper Lower Spraberry and the lower Lower Spraberry on implied 13 wells spacing.
With the upper wells outperforming the already very strong based on at the lower wells, we similarly have confidence that there is sufficient resource and sufficient spacing to support co-development of the two flow units at 13 wells stacked and staggered development. As a result of these successful tests over several quarters, we are making the definitive decision to carry 13 wells per section in the Lower Spraberry here versus the 11 that we have been carrying up to this point, which increases our Lower Spraberry location count at Monarch by 15%.
These added locations sit in the top quartile of our portfolio, and push our inventory life in just this zone in the Monarch operating area to over 10 years -- 10 rig years at current cycle times. As I mentioned back on slide 7, we returned to our Ranger operating area and up in the Reagan County for the first time since 2015, and drilled two lower Wolfcamp B wells during the second quarter.
These wells were completed in July and are currently flowing back. While it is very early days and they are still ramping, we are very encouraged by the results thus far.
This part of the basin has seen a resurgence in the industry focus in 2017, as the application of modern vintage completion designs by offset operators have delivered materially higher early time rates in both the Wolfcamp A and Wolfcamp B. Moreover, the emergence of the Wolfcamp C is an exciting development for this area as recent offset operators results have demonstrated tremendous upside potential in that zone.
We believe that C is highly prospective on our Ranger footprint and we are excited to be currently drilling our first Wolfcamp C delineation well as part of a three well pad, including two lower Wolfcamp B wells. I will remind everyone that Ranger was one of our first areas of operations, and now serves as yet another example of how technological advances within the Permian continue to unlock additional upside.
We’re excited about demonstrating the added value potential in Ranger in quarters to come. I will now turn the call over to Correne, our CFO, for the financial discussion.
Correne Loeffler
Thanks, Gary. I will pick up at the financial discussion on Slide 13.
For the quarter ended June 30, Callon reported adjusted net income of $0.09 per fully diluted share, which excludes the after-tax effects of certain non-recurring and non-valuation adjustments. The adjusted income figure also includes a theoretical tax provision of $0.06 per diluted share for the quarter as if the valuation did not exist for the deferred tax assets that were established in 2017.
We also reported adjusted EBITDA of $60 million, a sequential increase of 5% despite the challenging price environment. You can find the reconciliation of these non-GAAP measures in our press release, and in the appendix of our quarterly earnings slide deck.
During the quarter, we produced approximately 1.6 million barrels of oil, which represents an 11% increase quarter-over-quarter in oil volume. Our growth in oil volumes, coupled with our continued focus on reducing LOE, has allowed us to maintain a strong operating margin in excess of $30 per BOE, and deliver yet another quarter of adjusted EBITDA margins in excess of 70%.
On Slide 14, you can see that we entered the third quarter with the strong liquidity position of $639 million, which include $139 million of cash balances as a result of our recent $200 million add-on offering through our senior notes. In addition, during the quarter, we entered into an amended and extended credit facility, whereby our borrowing base increased to $650 million.
And we elected to set the commitment level at $500 million. Our leverage position remains amongst the strongest in a small to mid-cap [indiscernible] with the net debt to a second quarter annualized adjusted EBITDA of 1.9 times.
You will find a detailed hedging schedule in the appendix of our quarterly earnings slide deck on pages 17 and 18. Throughout the quarter, we’ve continued to add to our hedge position.
As of today, we have approximately 50% of our remaining 2017 oil volume hedged to WTI at a weighted average floor price $47.25. In addition, we are approximately 40% hedged in 2018 at a weighted average floor price of $49.14.
To sum things up, even with the potential for continued price volatility, our balance sheet and hedges have us very well positioned to execute our development program moving forward. Our full year 2017 guidance presented on Slide 15 has been updated for the year.
From a top line production perspective, we are forecasting another quarter of strong sequential production growth that you see accelerating into year-end. We also expect our oil mix for the year will be approximately 2% higher than originally forecasted, given the strong demonstrated oil-production profile across all 4 of our operating areas.
Importantly, we are also reducing our full year 2017 LOE guidance to $5.75 to $6.25 per BOE, given how it demonstrated year-to-date LOE performance and expectation that our investment in critical water infrastructure will continue to deliver benefits as the year progresses. Overall, we remain well positioned to deliver solid production results, combined with best-in-class operating margins in 2017 on an acreage position that has tripled in size within the last 18 months.
As we look ahead, we are on track to add our fifth rig in the Delaware basin by early 2018. And have a visible path to adding additional activity next year, while honoring the guides as discussed earlier.
In particular, we are excited to accelerate our activity, and we recently expanded Spur area, and now finalizing a development plan that will position us to hit the ground running in early 2018, including a potential acceleration of completion activity in late 2017, and strategic partnerships to advance our longer-term oil, gas and water infrastructure plan. We will be providing an update on these plans in the coming months.
Now I would like to turn the call back to Joe.
Joe Gatto
Thanks, Correne. And as you could see it, another solid quarter for us that we’re really pleased with and the teams progress.
I think it’s another quarter where we’ve seen early signs of unlocking the potential of the acquired assets we made a lot of strides on the last year. But importantly, and it’s probably evident that we’ve spend a lot of time on infrastructure and building out these assets in a right way, we think that’s going to provide a lot of benefits going forward.
With that, we’ll open up the call for questions.
Operator
We will now begin the Question-and-Answer Session. [Operator Instructions].
Our first question comes from Chris Stevens of KeyBanc. Please go ahead.
Chris Stevens
Hey, good morning guys. Can you just maybe give a little bit of color on how you inject your produced water and [light-on] extract really be impacted by some of the drilling issues that others are experiencing?
Gary Newberry
Yes, Chris, this is Gary. We’ve been fully aware of those types of challenges for a number of years, and we have been working hard to get well ahead of them with the infrastructure that we’ve put in place.
Many operators running this challenges with shallow development or shallow disposal in the Midland Basin, it’s been going on for many years. It’s now starting to be accelerated, of course, with the increased pace of drilling.
And that’s why we’ve been very focused on developing technology -- utilizing our technology to actually identify and drill deeper Alan Berger disposal wells in the Midland Basin. We think that’s the right way to go.
The Midland Basin is really geologically and tectonically quiet. So we are not overly concerned too much about seismicity and things like that, that come in some other basins that we hear about throughout the United States.
But the Midland Basin sets up very well for deep disposal. And we use our 3D seismic along our footprint to identify Alan Berger locations.
We have drilled several ourselves, and we’ve appointed third-party water suppliers to drill what we believed to be high potential, good disposal location’s need. And that’s all on an effort to avoid what others are starting to talk about today.
But we have seen some of that. I won’t say we are not -- we’re totally immune to it, we’ve seen some of it.
Even at our -- a good example of what we have done, and give out a little bit more color on this, because I know there is a lot of interest in it, and even at our Carpe Diem field, we used shallow development as a bridge to get to deeper development -- deeper disposal. And we worked hard identifying that location, we’ve got the location already drilled.
Third-party provider is very happy with that result. We have shifted now water that we had going to our own shallow disposal to that well, and we have curtailed any disposal into that shallow well, we think that’s the right direction to go.
We’ve also done the same thing at our Pecan Acres field. And we’re doing the same thing in many areas that we work.
Some of the infrastructure that we’re spending this year are 2 deep Alan Berger wells in Howard County, once being completed as we speak, the other one is being drilled as we speak, both fully identified with 3D seismic. We have offered to share, and several companies have come in and looked at how we use that seismic for identifying those bumps to give a higher probability of success for that deep disposal.
So frankly, in the Midland Basin, we’re getting very close to having about 80% of our disposal going deep, and we are working it very hard. It’s something that we have been keenly aware of and concerned with all along, and have worked hard to avoid some of the challenges that others are seeing.
Again, another key component, I got to tell you because this an industry issue, this is truly an industry issue that we got to work jointly together to solve. At our Maverick area in Howard, a small footprint, but we do see higher pressures and we haven’t -- we found other ways besides a fourth casing string that worked through that.
And those other ways are really getting ahead of the three third-party disposal companies that are close to us, disposing a good, a large volume shallow. We called them, and we said look this is where we are, this is what we’re doing, curtail everything you have for the next four, five days while we get through this system, this section of a hole.
And we used a little bit of a different mud system to help with some of that, and it’s been working just fine. So I think it’s a cooperative effort that the third -- midstream providers for shallow disposal have to work with the industry, and the industry has to collaborate with them going forward, and we can work through it overtime.
But in general, we have to find a different way to manage the volumes of water than putting them in the shallow zones. So we’re well ahead of that.
The -- we’ve recently been working with a couple of third-party providers to actually help us with some of our peak loading going forward so that we don’t have to put in all the investment ourselves, to where one of the criteria is that we target deep intervals and we focus on significant recycle. Recycle could be a large part of the solution to the industry as we ramp activity.
I know it’s a long answer, but I know there’s been a lot of interest in it. And I just wanted to let you know that we’ve been quite a bit ahead of it, and thinking more proactively instead of just trying to find on a cheaper way to do it.
I know the board keeps beating me up on infrastructure cost, but this is the right way to go.
Chris Stevens
I really appreciate the detailed color here. It sounds like you guys have been a little bit more forward looking and trying to get ahead of this issue.
Maybe if I can just move over to another one. Your oil mix has been pretty strong, and you raised the oil mix guidance.
Can you just maybe talk a little bit about that? And whether you think you might be less impacted by an increasing GOR profile just given a little bit more stable oil mix seen in wells in Howard County in the Delaware?
Gary Newberry
Alright. Yes, again, this is another industry issue, but it’s specific to us.
In some of our legacy assets such as Bloxom, our first horizontal wells, we have seen an increasing GOR but we have not seen any fall off of oil rig, none. And so we are very happy that over time you may well see an upward mobility or movement toward gas.
Frankly, as you are bringing on a lot of new wells and all that new well activity, all of that is really highly oil concentrated. And that will stay that way for several years before it really gets to its steady state flow, and then you start having more and more gas breakout in the formation.
What we are very confident about is the oil type curve itself. But we don’t -- we are not surprised by over time a slowing increase in GOR.
It just does not impact the oil rig. So our mix right now being highly oil dependent, highly oil concentrated.
We got a lot of new wells coming on right now because of the increased level of activity that we had compared to our base production. And that’s really the answer to that whole issue.
We’re happy that the high oil rates there in Howard, and certainly the high oil rate that we are adding. The place we are in Ward county is very encouraging early on.
Because we don’t see that oil rig dropping off even in the near term at all for the Corbets well that’s come on here recently. We’ve got an extended time on it.
Now we are feeling really good about it.
Operator
[Operator Instructions] And we will now take the next question from Neal Dingmann of SunTrust. Please go ahead sir.
Neal Dingmann
Good morning guys, it will be tough, but I also had to follow the rules. Could you talk to or I guess actually -- Gary, could you talk a little just on the Spur?
You sounded like peers are going to be having a lot of activity there. Could you talk about maybe a little bit in terms of cadence?
Or geographically how you are going to tag that? I guess I was looking at when you might too get to that Southern area in that play?
Gary Newberry
Yes, we’ll get there soon. We’ve got the one rig operated still in a Wolfcamp A well, it will move to another Wolfcamp A well, kind of North of a highway, by where the bigger development spend.
But then we are going to jump to the South Side. We’re going to the South Side pretty quick.
And so that’s again why we’re spending infrastructure money over there as well to build all that out, to be able to, again, ramp those wells like we want to. We are happy with -- we’re happy with what we are seeing.
But frankly, until we get this infrastructure in place, we still have kind of a natural chock on the wells due to the amount of water that we move both in Howard County and in Ward County. So we’re still not seeing the full potential of the wells that we are confident is there.
And we’ll start seeing that more and more in the fourth quarter in Howard, in WildHorse. And we’re getting prepared for that as Spur today.
But we’ll be in the South Side real quick. And again, we’re bringing that second rig in -- second rig for the Delaware basin in January of 2018.
So we’ll be moving pretty quick. We are already ahead of the drilling curve on the first well, so we’re happy with that, and we would expect it -- the pace will accelerate.
Neal Dingmann
Okay. And then, Gary, just one last one if I could over in WildHorse.
Just -- if you could just tell just in general terms, what you look at well spacing now there today or I guess through the end of the year? And then I’m just wondering, what you can get that down to?
Gary Newberry
Yes, Neal. We’ve got a test coming up here, up in Sidewinder.
It’s actually offsetting the Silver City well, coming up here pretty soon and then we’ll start talking about appropriate spacing for the Wolfcamp A. But don’t let me get ahead of myself, you know how I am, it takes me a little while, made me -- take me a little bit longer than some.
Operator
Our next question comes from Gabe Daoud of JP Morgan.
Gabe Daoud
And sorry if this was covered, but just at Spur you mentioned, I guess, pulling back a little bit in terms of completion intensity. Could you just talk a little bit about what that does to cost moving forward, and I guess, even productivity?
And then also, if you could just remind us what those costs are today on the 1.5-mile and 2-mile laterals?
Gary Newberry
Yes, as far as the frack intensity, Gabe, that’s a good question. Frankly, we know with certainty that the Corbets well and the Saratoga well were probably too big.
And the way we know that is simply because we saw an impact in the Bone Spring 3 about this. Now -- so we think we can actually have more effective higher productive wells, if we actually pull back on that size, do a better job, doing the high density near-wellbore fracture stimulation, using more clusters and more diverter agents throughout that whole section, and kind of isolate that within zone and not lose that pressure out of zone, and the wells will be better than they are today.
So that’s where we are coming from, so we’re likely going to go from, again, we -- I think we’ve mentioned that both of those wells are fracture stimulated at 2,800 pounds per foot of sand. And we’re going to pull down that load all the way back to 2,000 pounds per foot of sand on the next one.
And we’ll do some experimentation on the next one to potentially even pull back a little bit further, to reassure ourselves that that’s the right direction to go. But we’ve looked at other operators in the area, we’ve collaborated and again, part of the way we learn is reaching out, building trusting relationships with other operators.
And we think as we learn from what we do and share that with them, and they learn from what they’re currently doing and share it with us, we think we’re all heading in into right direction by getting closer to lower sand content, higher clusters, more diverter agents, therefore, focusing that fracture stimulation closer to the wellbore instead of reaching further out. Harnessing that energy as effective fracture within zone and you’re going to be able to increase the productivity of the well.
Joe Gatto
Sorry, Gabe, on the cost side, just to address that. For planning purposes, we are running around $9 million for 2-mile well, that’s what we are drilling.
That’s part of our program, so we don’t have any shorter laterals on the dock just yet. But we are running around $9 million, in hope that will come down with the lower proppant loading, and hopefully with the cycle times.
Gary mentioned, we’re doing better than our original plan, it was in that $9 million. So we’ll provide some updates when we get some real data outside of the AFPs.
But I think there’s going to be downside from that $9 million for a 2-mile lateral.
Gabe Daoud
Thanks, guys. And I will just -- as my follow-up, I guess, maybe we’ll shift to 35% CAGR, you talked about through ‘19 on a 5-year program with -- also with hopefully some free cash on a $50 to $55 kind of deck.
How do you -- just thinking about that, how do you balance, I guess, free cash with accelerating further? And ultimately, maybe, what I’m just trying to ask is timing on additional rig additions, as you mentioned, rig activity is biased higher and not lower, so just trying to think about the timing on that?
Joe Gatto
If we -- if everything plays out in a straight line in terms of commodity prices, and our progress out here probably sets us for the pace we have been on. It’s really been adding a rig every two quarters; that fits with our financial philosophy, it fits with giving us time to build out infrastructure in the right way.
The good thing, being so focused on infrastructure in the last several quarters, as we get into ‘18, we should be largely in a position to go as fast we want, where we want, when we want. And that’s where we wanted to be.
So if we look at just the guidepost we set out, we’re looking at mid ‘18. We should be in a position to add an additional rig, given the visibility on cash flow generation, the parameters we look at.
It also gives us an opportunity to look at incremental bolt-on acquisitions in terms of cash flow, availability and improving balance sheet as we deliver these types of returns. So there is optionality what we do with that cash generation.
But right now, I think it holds together $50 oil and not a lot of downside to that. I think we will be well positioned by mid ‘18 to be thinking about that six rig.
Operator
Our next question comes from Will Green of Stephens. Please go ahead.
Will Green
Thanks and good morning. I wanted to follow-on on that last point.
Because you guys have product yourself as being an efficient operator, I know that this was kind of a year of integration after the M&A last year. You kind of mentioned that a lot of that infrastructure plan at least in the Midland side has been late.
Does this also give you the opportunity to kind of increase the typical pad size? And can you update us on how -- what the typical pad looks like this year and whether or not you’ve actually looked at increasing that or if it just doesn’t make sense from an efficiency standpoint to go from say a three well pad to a four or five, or just how are you in that evolution?
Gary Newberry
Well, that’s a very good question. We spend a lot of time with our team talking about now that we are getting this infrastructure in place, what’s the best way to efficiently bring that value forward.
And we’re paying attention to what others are doing with tank, I think, they call it tank developments and things like that, and cube developments, and we’re paying attention to all of that and trying to get to the right answer on pad size. And not only pad size and the number of wells we drill each time but then the time that we then have in order to come back to effectively stimulate the next pad.
So we spend a lot of time with that. We’re learning a lot from our interaction with other companies as well along that way.
But currently right now, we are drilling two well pads in Howard County, once we get this infrastructure in place, and we then finish our overall evaluation of how we bring value forward whether will we do it vertically across areas or whether we do certain zones together, because there is a communication associated with them, or how we go about a single level of development like we focused on our Lower Spraberry in Monarch. But we are working that, but the infrastructure will allow us to ramp up to I guess what I would say is our probably max pad size will probably be four wells.
That allows us to efficiently bring value forward in a way that we feel very comfortable with. And then it also allows us not to overbuild the infrastructure necessary to manage a larger pad or section development.
And given that we have a lot of experience with that today, especially in Monarch, even when we come back to the next offset pad and impact the existing production with fluid because we know that happens, the infrastructure itself will allow us to bring that fluid back off those existing wells faster and restore that production sooner. All of that, of course, is going to be an efficiencies that we gain as we finish this infrastructure build-out.
Will Green
Great, I appreciate the color there. And then I guess similar line of questioning on the Delaware side.
I know you mentioned kind of 2 one-offs early on, is the infrastructure to a point there to where once you guys hit the ground running with that second rig in January, you are going to be able to pad development over there or is that mostly going to be one-off wells next year while you kind of catch up on infrastructure, just where do you sit kind of today on that front? And how do you see that development playing out through ‘18 on single well one-offs versus pads?
And if you are going pads, how -- what is the typical pad look like in your mind out there?
Gary Newberry
Yes, we are starting with 2 single wells, just like we said, just to get our feet wet, and things are going well. I’ll have to restrain our drillers from wanting to jump to multi-well pad sooner, I want to make sure we get a couple of them under our belt.
And we kind of learn generally about this different way of stimulating wells. But then we’re going to jump right into pad development.
And Will, I think that’s our ammo, that’s what we like to do. We got to be efficient soon.
And so we’ll start with 2 well pads, and as we continue to build out infrastructure, we are getting ahead of the infrastructure this year, it came with the few wells, we’ve upgraded those systems, we are interconnecting those wells. We’ll drill a few more wells this year and next year, and then it will all be interconnected, and this is an area that we have a keen focus on recycle, which helps on both sides of the sourcing and the production side.
And this is an area that we are working on. Again, that -- I kind of generally referenced earlier with the third-party, to help us manage all of that fluid that were coming back into Delaware.
But we’ll get to 2 well pads very quickly, and we ultimately hope to get to a minimum of 3 well pads in the Delaware very soon.
Operator
Our next question comes from Dan McSpirit of BMO Capital Markets.
Dan McSpirit
To be sure, GOR, I guess, gas oil ratio is a hot topic these days. And what I haven’t heard yet from other operators is a good explanation as to why gas and NGL production is maybe coming in stronger than estimated by those same producers.
I’m hoping you can provide a clearer explanation may be in addition to address any risks to the oil stream that may be present if any.
Gary Newberry
Well, Dennis, it’s kind of all part of the way reservoirs work. As you get further along the life of the well, and you have pressure decline out into the formation, you have more gas simply break out of the oil stream.
Now in high API oil reservoirs, gas kind of stay top reservoirs, you can have liquids drop out in those reservoirs and potentially lose some liquids. In the reservoirs that we have, we don’t see that phenomena occurring at all.
There’s still plenty of energy left in the oil, a lot of gas still entrained in the oil, it’s still moving toward the wellbore. And importantly, with our focus on the near-wellbore fracture intensity, that pressure decline doesn’t have to get too far, and we can get a lot of the recovery close to the wellbore very early time.
So I see the natural phenomenon of just natural pressure reduction in an oil and gas reservoir as being the reason you’re going to see minor increases in gas production. But I see with the type of crew that we have in the Midland Basin, and certainly in the Delaware basin, I should have said the Permian Basin, I guess that encompasses the whole thing, that the oil should be fine.
And that’s what we’re seeing in the early-time decline for us today.
Dan McSpirit
Well, I appreciate the clear explanation. Very helpful.
And as a follow-up, the focus on returns at the corporate level that you stated in your prepared remarks is certainly refreshing to hear, and I think maybe a folks through remainder of the industry may be forced to take. Are there any internal goals around that measure?
And maybe if you could discuss how you best manage to those goals while balancing the need of further drill eliminate the lease sold and grow production at the same time?
Joe Gatto
Appreciate the question, and appreciate letting us borrow some of your work on that topic. It is a good question.
I think it all starts with the portfolio of assets that we have and returns that are available on a half-cycle basis. It’s a good starting point, right?
It all starts with a good rocket at the end of the day, and a strong portfolio of assets. But we do have to manage the rest of the equation in terms of corporate costs, and how everything generates corporate type of returns.
And last year, we raised about $1.5 billion of equity against going $1.6 billion of acquisitions. So we did put a lot of capital out there and it was very important for us as we are doing that to put out relatively expensive equity capital that people are going to demand a return on that we had to pass to get there, and last year wasn’t as capital efficient as we’d liked to be on a ROIC basis.
This year, we’re making strides and as the chart points out, we are getting closer to 10% in 2018 based on those numbers here, which I think are in line with our expectations. We do not have formal goals on that, but in terms of the target where we’d like to get to is sort of a mid-teens type of basis on that number on a sustained basis that we can coupled with 20%, 25% growth on a sustained basis.
We think that’s a great model. As we’ve talked about, we do things on a measured way, which helps with that returns on capital.
So we’ve tripled the size of our acreage position. But it’s not like we went from 2 rigs to 8.
I think we’re going to do it in the right way, responsible that we’re able to generate meaningful growth. But we’re doing it in a way that we’re able to be friendly to the returns on capital and not getting too far away from the goal of covering our overall cost of capital on that metric.
Operator
Our next question comes from Ron Mills of Johnson Rice & Company. Please go ahead.
Ron Mills
Good morning, guys. Gary, for you, especially with the Wolfcamp A now derisked across really all of your Howard County position, how do you still think about internally the allocation of rigs and drilling activity between the 2 or 3 different targets in that area?
And did that success as you moved through Maverick to Fairway, does that have any impact on your expected inventory versus what you’ve already put out?
Gary Newberry
We’re not ready to change the inventory yet to answer your last question. But again, I referenced that we’re going to do a spacing test in the Wolfcamp A soon.
So we will get that underway in the next couple quarters. And we’ll start again moving those numbers as appropriate.
We are excited about WildHorse, I mean, it’s phenomenal. We like what we see there.
We think the Lower Spraberry still has upside to be had. We’ve got a B well, that’s currently flowing back that we’re excited about.
And so, we are still defining the B potential in the Southern part of the acreage potential. So as we continue to see these results, we will decide whether we go B, A, Lower Spraberry or focus on what we know to be highly prospective A in the future.
But the cadence that you referenced is as we go to five rigs, and there will be to rigs in the Delaware, there still be about 1.5 rig in WildHorse and then about 1.5 rig in Monarch and Ranger. It’s kind of the way we see it.
That could all change significantly once we get to see well done in Ranger. We see significant potential there, but presently it’s about 1.5 rig, WildHorse 1.5 rig, Monarch and Ranger, we’re primarily focused on Monarch and then two rigs in Spur.
Ron Mills
Okay. And then as you talk about Ranger, not only restarting the Wolfcamp B activity there, but how far away are you from the recent partially activity in the C because those wells on a per foot basis are coming in 50 plus percent higher than the shallower Wolfcamp zones and where has the Wolfcamp C been in your prior inventory counts?
Because that seems to be one of the higher rate of change opportunities.
Gary Newberry
Yes, we haven’t carried any inventory in the C, Ron, so it is a great opportunity. But if you look at Slide 12, it kind of generally guides you into the overall distance from our footprint to that number 4 is the well that you’ve referenced.
And it’s about 8 to 10 miles away. Geologically, we’ve looked at.
And again, I will remind everybody that before we ever pivoted back in ‘14 or ‘15, we were looking at decline and the C in our existing footprint in Garrison Draw, which is part of that range or package further to the South, and we saw this significant potential. So we were very excited to see partially come out with this type of a result.
Our exploration geologists always said, "Hey, this potential exists, we just need to go try it.’’ So you can see where we are relative to that well.
And we’re currently drilling the intermediate section for that C well today. And we’ll drill the intermediate section for the two B wells, and then we’ll go complete all three of those wells together once we are done.
So we’re anxious report that, perhaps, later in the year. We’ll see.
Operator
Our next question comes from Jeb Bachmann of Scotia Howard Weil. Please go ahead.
Jeb Bachmann
Good morning guys. Gary, just quickly, when the fifth rig arrives early next year, are the 2 dedicated crews going to be enough to handle the completion cadence from that -- from those programs or you are going to have to bring in another one?
Gary Newberry
Again, we’re seeing some pretty good cycle times on the most recent frack crew. We are experimenting with certain -- along with ProPetro’s support, we’re experimenting with the certain different sand delivery system as well.
So given the cycle times we’re seeing, the 2 crews should handle a good bit of that program. But if not, we’ll be working toward, again, ProPetro and others, it’s amazing how many call we -- inbound calls we still get about wanting to do work for us as well as potentially crews.
Again, the coming of contracted other very capable operators who want to put to work as part of our base fleet. But I think for now it will be just fine.
We’ll handle it. Certainly for the first half of the year with the 2 crews that we have.
And it will likely carry us all the way through 2018.
Jeb Bachmann
Okay, great. And last one from me, and I apologize if you addressed this already.
But the new proppant design up in the Howard County with the Lower Spraberry, what is that loading going from and to?
Gary Newberry
We’ll go back to some of the original loading around 1,400, 1500 pounds per foot. We’re just not pumping those today.
We just finished one, we’re pumping another one today. And so we’ll have some results on that hopefully by the end of the year during our third quarter call.
But doing that with the different cluster spacing, number of clusters per stage as well as utilizing a more intense diverter programs to keep that near wellbore and contain that energy, stay away from any water that we may have gotten into with those other bigger jobs for several wells. And we’re pretty confident that’s what occurred.
And we’ll have some information by the end of the year.
Operator
Our next question comes from Mike Kelly of Seaport Global.
Mike Kelly
Just a quick one for me. Gary, what’s the added cost of disposing water in the Alan Berg versa some shallow results.
Gary Newberry
The real cost is just in the -- that the -- the only real cost is just in if -- well, I’ll get the better backup. If you just go out there and just drill Alan Berger wells, your chance of success go down.
If you go out there and drill Alan Berger wells using technology the way we have developed it, your chance of success go up. So given a high chance of success, the extra cost is in the drilling of the well, only the drilling of the well.
In fact, you get higher disposal capacity with an Alan Berger well than you do with the shallow well. So the efficiency of that well going forward more than offsets the extra cost for the well.
And that extra cost is somewhere around about $0.5 million.
Mike Kelly
Okay. Got it.
So if the industry turns to that, this whole phenomenon here and potentially haven’t used 4 strings of casing and that could go in all the point in, is that the right read that ultimately you guys as an industry will kind of overcome this?
Gary Newberry
There’s no doubt, there are a lot of smart people in this industry. We -- one of the only ones that foresaw this issue, everyone else has seen it too, and they are all working toward it.
And it’s a combination of 2 things that’s going to solve it. It’s going to be deep disposal, and it’s going to be recycled.
Those are the 2 things that are going to solve this issue, and the industry will clearly solve it in the near term. I’ve seen a lot of press on it, but again, we’ve been ahead of it, because we know how impactful it is to us.
And we want to make sure that we go about this in the right way from the start. We have used shallow development as a bridge to deeper development, but at the end of the day, our goal all along has been to get deep and get to recycle as quickly as we can to minimize disposal.
Mike Kelly
And just a quick follow-up there. The number of wells a single-disposal well can support, what’s a good kind of frame of reference there?
Gary Newberry
A bunch as in my answer. A good deep disposal well, a couple of deep disposal wells could probably handle our entire Fairway development in Howard.
So it’s a lot, it’s a lot. It’s the peak loading that you want to get prepared for, because if you don’t prepare for that, then you have a natural choke on your well and then you get behind on your production.
Those benefits to managing infrastructure stand in the right way on both the cost side over the long term, minimizing drilling [indiscernible] over the long term, and being able to ramp your wells as fast as you can to get to your highest oil cut operations sooner and bring that value forward. So there’s a lot of reasons you want to get to the right answer.
But again, I don’t want to just count the opportunity for recycle, and a lot of other companies are well ahead of us on recycle, we’re not quite where I want to be at. But I know a lot of other companies have been, and I’ve been learning as much as I can from them, because I think that’s a critical component to the answer as well.
Operator
This concludes our question-and-answer session. I would like to turn the conference back over to Joe Gatto for any closing remarks.
Joe Gatto
I appreciate everyone’s interest in the questions, and we look forward to talking again soon. Thanks.
Operator
The conference has now concluded, thank you. A replay of this event will be available for 1 year on the company’s website.
Thank you for attending today’s presentation. You may now disconnect your lines.