Callon Petroleum (CPE) Fred L. Callon on Q1 2016 Results - Earnings Call Transcript

Callon Petroleum Co. (CPE) Q1 2016 Earnings Call May 5, 2016 9:00 AM ET

Executives

Eric Williams - Manager of Finance, Callon Petroleum Co.
Fred L. Callon - Chairman, President & Chief Executive Officer
Gary A. Newberry - Senior Vice President-Operations
Joseph C. Gatto, Jr. - Chief Financial Officer, Treasurer & Senior VP

Analysts

Ronald E. Mills - Johnson Rice & Co. LLC
Irene Oiyin Haas - Wunderlich Securities, Inc.
Will O. Green - Stephens, Inc.
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
Jeff S. Grampp - Northland Securities, Inc.
Gabriel J. Daoud - JPMorgan Securities LLC
Mike Kelly - Seaport Global Securities LLC
Jeb Bachmann - Scotia Capital (USA), Inc.
Ipsit Mohanty - GMP Securities LLC

Operator

Welcome to the Callon Petroleum Company First Quarter 2016 Earnings and Operating Results Conference Call. All participants will be in listen-only mode. After today's presentation, there will be an opportunity to ask questions. Please note this conference is being recorded. A replay will be available for one year on the company's website following this presentation.

I would now like to turn the conference over to Eric Williams, Manager of Finance. Please go ahead.

Eric Williams - Manager of Finance, Callon Petroleum Co.

Good morning and thank you for taking time to join our conference call. With me this morning are Fred Callon, Chairman and Chief Executive Officer; Gary Newberry, Senior Vice President of Operations; and Joe Gatto, Senior Vice President, Chief Financial Officer and Treasurer.

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 Investors section of our website at www.callon.com.

Before we begin, I would like to remind everyone joining this call that our comments today include forward-looking statements. A variety of factors could cause Callon's actual results to differ materially from the anticipated results or expectations expressed in these forward-looking statements. For a complete discussion of these risks, we encourage you to read our filings with the SEC, including our Form 10-K available on our website or the SEC's website.

Today's call will also contain discussions of certain non-GAAP financial measures. Please refer to the earnings press release we issued yesterday afternoon for important disclosures regarding such measures and the corresponding reconciliations. You can obtain a copy of our press release in the News section of our website. As the operator mentioned, following our prepared remarks, we will open the call for Q&A.

And with that, I would like to turn the call over to Fred Callon and direct the audience to slide three of the earnings presentation. Fred?

Fred L. Callon - Chairman, President & Chief Executive Officer

Thank you, Eric, and thanks to everyone for joining this morning.

For nearly 18 months now, we've been positioning Callon to weather the volatile commodity price markets and this past quarter provided a true test of our business model, our assets, and our team. Oil prices that range from below $30 to over $42 a barrel. Our focus continues to be around asset quality, where we have some of the best rock and capital efficiency, where I think we have one of the best operating teams. As a result, despite the environment, we continued to increase production to a record 12,440 barrels of oil equivalent a day.

Our hedge position provides some insulation. We recognize that our sustained focus on internal cash generation and operating cost initiatives are even more important as we continue to navigate through this current environment. We reduced our total cash operating cost, including G&A, to approximately $11.50 per barrel on a two-stream basis, and a reduction of over 5% from the previous quarter, and 20% compared to just six months ago.

When we combine the resulting cash margins with well costs of approximately $5 million, we've created a visible path to operating within our means, which also delivering production growth through the next couple of quarters as we position ourselves for future activity later in this year. In summary, we think our operating performance highlights the future potential of our asset base when combined with consistently demonstrated capabilities as an organization.

The key part of this anticipated increase in activity will include the initial drilling at our recently announced acquisition in Howard County that we anticipate will close in late May. We will provide additional detail on our development plans for the asset after the closing date, but we're very excited to add another core operating area to our existing high-quality portfolio. We believe that this expanded opportunity set provides us with a deep inventory that delivers strong returns and warrants continued investment in the current commodity price environment.

As we detailed in the acquisition presentation that was released on April 19, we've identified three de-risked benches, including the Lower Spraberry and Wolfcamp A, as well as the B. And we'll focus on our initial efforts, with anticipated completion of a drilled uncompleted Wolfcamp A well coming up in June.

As we look out in the balance to 2016, we still face uncertainties as the commodity price markets continue to rebalance, but we're confident in our ability to deliver capital-efficient growth while simultaneously delivering our plan of achieving sustained cash flow neutrality before we increase our activity levels. Currently, we anticipate returning our second rig to service later this year, with a focus on Howard County while maintaining a rig focused on the Lower Spraberry program in Midland County through the balance of the year.

I'll now turn the call over to Gary Newberry, our Senior Vice President of Operations. Gary?

Gary A. Newberry - Senior Vice President-Operations

Thank you, Fred, and good morning. I will begin with slide four, which provides a snapshot of our current area of operational focus, primarily in Midland County.

We had an active quarter, as we've been transitioning to a one-rig program in March, bringing eight gross wells in the Casselman and Bohannon area on-line. Despite being shorter laterals, these Lower Spraberry wells have demonstrated stellar capital efficiency, delivering average IP rates of 930 barrels of oil equivalent per day, with oil content of 87% at a well cost of $4 million. We also continued to invest in facilities and water handling in this area, which will further enhance operating efficiency and reduce cost as our development program expands.

Our two other core fields in this area, Carpe Diem and Pecan Acres, will continue to feature long lateral development throughout the year. Some of this can be attributed to a partnership with an offsetting operator to increase lateral lengths in both the Lower Spraberry and Wolfcamp A and B zones. Presently, we expect to drill five additional 9,000-foot wells to 10,000-foot wells in these fields during the remainder of this year, in addition to several shorter laterals.

Moving to slide five, I want to update you on our Lower Spraberry down-spacing test in the Central Midland Basin assets. The existing 11-well per section spacing test continues to perform in line with our type curve, with encouraging performance on a longer-term basis. Most of our existing Lower Spraberry wells are producing from the lower section of the bench. But we have advanced our initiatives to drill the upper section of the Lower Spraberry.

We are currently drilling a three-well pad at Carpe Diem adjacent to existing wells, which will test 12 wells per section and further validate the potential for an additional level of development in the upper part of the Lower Spraberry. We will then move back to our Casselman lease and test 13 wells per section. We are very encouraged with the potential to significantly add to our inventory of wells in this highly prospective area.

Slide six illustrates the continued improvement achieved with the deliberate drilling and completion costs. We continue to work with all service providers on scheduling work and bundling of services to achieve added efficiencies. We are consistently delivering 7,500-feet well costs at or below $5 million and 5,000-feet well costs at $4 million. These cost reductions have been achieved across a broad spectrum of services. Competition for services continues to increase as we actively develop with one rig while timing to reactivate the second rig later in the year in a state of an improving commodity price environment.

As shown on slide seven, effective management and controlling the base level operating costs are equally important to capital cost reductions for drilling and completing wells. Similar to capital costs, we continue to review every aspect of our cost structure and effectively engage our service partners across our entire business. As shown on the right side of the slide, we are delivering leading-edge operating costs relative to our peers.

We look forward to further leveraging both our capital and operating expertise and service partnerships to our recently announced asset acquisitions in Howard and Reagan Counties. We're on track to complete our due diligence with anticipation of closing the asset transactions later this month. We're working with the current operators to effect a smooth transition.

Joe Gatto, our Chief Financial Officer, will pick up on slide eight with the financial discussion.

Joseph C. Gatto, Jr. - Chief Financial Officer, Treasurer & Senior VP

Thanks, Gary.

Looking at key drivers for the business, you can see that the top line production growth is benefited from the performance of Lower Spraberry, in addition to production optimization at other fields. Callon delivered sequential growth of 17% in the first quarter, while maintaining a high oil cut of almost 80%. Importantly, this growth is associated with another sequential decrease in capital spending in the chart in the lower left-hand side of the page. When viewed together, these two charts capture the strides we've made in terms of capital efficiency while maintaining operational momentum in the business.

The realized oil pricing chart to the right is obviously a key driver of our results as well. One piece of pricing that we can influence is our transportation costs. They have been reduced by 40% on average over the last three quarters, adding almost $1 of margin improvement.

Slide nine illustrates the EBITDA margin per barrel of oil produced on the right-hand side of the page, which was over 65% in the first quarter, or approximately $22.25 per BOE. In addition to a bit of price recovery in oil since the first quarter, we expect to see continued improvement in our per-unit cash operating structure over time, driven by the cost initiatives that Gary described, as well as the addition of production volumes from our pending transactions announced in April.

Slide 10 provides our current views on the progression of these per-unit costs, as well as the anticipated trajectory of production for the coming quarters. This guidance assumes the closing of our pending transactions by late May. With anticipated production contribution for one month from the transactions, we estimate production volumes of 13,500 BOE per day to 14,500 BOE per day in the second quarter, and associated cash operating costs of $11.88 per BOE, based on the midpoint of each line item, including a sequential increase in production taxes from the improvement in pricing from the first quarter.

For the full year 2016, we currently forecast production growth of over 50% year-over-year under our current one-rig program and the completion of an incremental three drilled uncompleted wells on the properties to be acquired. This guidance does not reflect a potential increase in activity in late 2016. We will provide an update regarding our operational plans and related guidance as part of our second quarter results in August.

Following our recent equity offering last month, our financial position remains solid on a pro forma basis, as illustrated on slide 11. Our liquidity position of over $260 million is complemented by an operational program that we expect to be modestly cash flow positive in the next few quarters, based on current commodity prices. In addition, this liquidity position does not include any potential impact on the borrowing base from the addition of pending transactions after closing, which we currently estimate to be in the range of a 15% to 20% increase.

From a leverage standpoint, we estimate our pro forma debt-to-LTM EBITDA to be approximately 2.25 times post-closing the transactions and remain focused on maintaining similar leverage metrics as we develop our operational plans going forward.

This topic takes me to page 12 and an overview of our current planning parameters for the next several quarters. Our base case assumes the return to a two-rig horizontal program during the fourth quarter of 2016, with the incremental activity focused on Howard County development in the Wolfcamp A and Lower Spraberry zones. This plan is premised on oil prices in the $40 to $45 range for 2017, with no further cost saving assumptions. We also see the option to increase activity to three rigs in 2017 should we see further improvement in well level returns.

To provide some directional guidance, such improvement could be driven by incremental type curve outperformance, additional cost reductions or, the most obvious and talked about catalyst, a further recovery in oil prices, which in our case would be in the $45 to $50 range. Conversely, we have the ability to pull back activity to just over one rig in a weaker 2017 pricing environment and still fulfill any drilling obligations associated with the pending transactions, given that all of our legacy properties are held by production.

Overall, we try not to focus too much on magic crude oil prices, especially in a volatile environment. While it is impossible to run a completely price agnostic E&P business, we focus on what we can control, namely delivering robust full-cycle returns that are underpinned by our ability to manage capital costs and operating expenses and produce consistent strong well performance. This laser focus on controlling our cost structure has benefited the company, creating a deep inventory of investment opportunities that offer robust return profiles below $50 a barrel. We believe that our strong cash flow, margins, and balance sheet strength will enable us to pull even more of this value forward for our shareholders over the coming quarters in a variety of price scenarios.

With that, I'll turn the call back to Fred for some final comments.

Fred L. Callon - Chairman, President & Chief Executive Officer

Thank you, Joe. Again, we appreciate everyone taking the time to call in this morning. And with that, I think we'll just open the call to questions.

Question-and-Answer Session

Operator

Thank you. We will now begin the question-and-answer session. And our first question will come from Ron Mills of Johnson Rice. Please go ahead.

Ronald E. Mills - Johnson Rice & Co. LLC

Good morning. Joe, maybe for you. You gave a couple price ranges where you're comfortable to definitely add that second rig and potentially the third rig. With the strip pricing within those ranges, how much time has to go by where you feel comfortable enough with that oil price scenario to move forward with moving closer to your bull case activities?

Joseph C. Gatto, Jr. - Chief Financial Officer, Treasurer & Senior VP

Yeah. Thanks, Ron. I guess in terms of the base case, we can start there, as we've been talking about, it's really been a couple quarters of delivering on our goal of cash neutrality and maybe do a little bit better than that over the next two quarters. So, as we leg into this over the next several quarters, I think initially, we're looking at a couple quarters of stability. Importantly, what goes hand-in-hand with that is going to be our operating cost structure and capital well costs, keep seeing the right trajectory on that.

As we go into the base case, to accelerate a case beyond that, I think some of that's going to be predicated on – and Gary can jump in on this, but our incremental activity on that third rig, again, a lot of that will be focused on Howard County. So it's going to take a little bit of time for us to leg into that position in the right way, developing the infrastructure, seeing the type curve performance for ourselves. So there's probably a little bit of time there between the second rig and third rig that's not necessarily all price-related, but potentially driven by the results that we're seeing – the path that we see for efficient development as it relates to infrastructure, et cetera. But, Gary, I'd welcome your thoughts on that as well.

Gary A. Newberry - Senior Vice President-Operations

Yeah. I think a couple of quarters, Ron, makes sense to me. It gives us some time to really fully evaluate what we need to do from an infrastructure perspective in Howard County to be very efficient. We don't want to get too far ahead of ourselves with that. There's a good infrastructure in place today. But as you know, as we get into efficient pad development, there's some costs associated with being good at handling those increased volumes and an accelerated pace of development. So we're anxious to get going with that, evaluate that, take the best odds to start, align with even some of the 2017 lease obligations for that area.

But we'll certainly be well planned out. We put a lot of emphasis on planning and being good at what we do. And so that certainly fits well with me, and I think it gives us some comfort that commodity prices are more stable, that the market is heading in the direction and staying in the direction that we kind of feel it should go. And I've already started conversations with our primary service providers about, hey, you all helped us tremendously on the down-cycle, now how do we manage this on the up-cycle as well? What is the – how do we work through all this to where there's a lot of gain and a lot of movement in both sides. Because as you would expect, I mean, they're wanting to claw-back some of the cost concessions that they've certainly given us to help us be successful. So that helps us to be fully aligned as we go forward with the service providers that we have, but we spend a couple of quarters planning this work.

Ronald E. Mills - Johnson Rice & Co. LLC

Okay. Great. And then on the down-spacing tests, going from 11-well per section to 12-well per section to 13-well per section and with some of the industry on 16-well per section to 20-well per section, can you just clarify, when you were doing those chevron patterns, were both of those in what you would call the Lower Spraberry? Or would that – would those chevron patterns comprised the upper Lower Spraberry and the lower Lower Spraberry? I guess I'm trying to get a sense as to how thick the Lower Spraberry is and do you really have maybe not just two parts of the Lower Spraberry, but maybe more to develop? Or am I just not understanding that well?

Gary A. Newberry - Senior Vice President-Operations

I know. When I say Lower Spraberry, I'm talking about the entire Lower Spraberry section, not the lower Lower. But the Lower Spraberry section we see is thick enough to manage two intervals. They are somewhat different. The upper part of the Lower Spraberry is actually a cleaner environment, a cleaner depositional environment. And so, we were thinking perhaps that we could likely get better performance by dropping all of our wells to the lower section and fracing up. But what was very important about our last test, the test that's currently continuing today the 11-well per section test is the upper well is actually outperforming the lower well. And we're very encouraged with that. And so, it suggests that we aren't quite getting what we thought we could get for the development of the whole section.

Now, the two wells – the three wells that we've got going on right now, the importance of those three wells is there are two upper Lower Spraberry wells and one lower Lower Spraberry well. And so, we're truly going to test this two levels of development in the Lower Spraberry. Now, the reason we're being somewhat disciplined about how fast we go is just the way I like to do business, essentially. Again, some people have already said 16-well per section to 20-well per section, and we certainly respect those operators. They're very good at what they do. They've done a lot of work and science around this, but I never want to get to a point where I'm over-capitalizing an area. And so I'm going to be deliberate about it. I'm going to 12-well per section, and then I'm going to 13-well per section, like I said before. And if I start seeing some degradation in performance with the inventory I have, I'll likely stop at whatever level I see any type of degradation in performance. So far, I haven't seen it. I've been very encouraged with it. So we'll continue with that. So hopefully, that answers that question.

Ronald E. Mills - Johnson Rice & Co. LLC

It does. And then just on the cost side. I know you've talked before about roughly half or so of the cost being more efficiency related versus just service cost related on the well cost. On the OpEx side, how much leverage is there on the OpEx side when you think about if activity levels do increase? Or do you think you'd be able to hold those OpEx improvements through a higher oil price environment?

Gary A. Newberry - Senior Vice President-Operations

I think the OpEx improvements are part of a better understanding of operating our wells, getting really down into the guts of our business, Ron. That's important to us. The way wells operate, the way you can efficiently manage those wells, the way you can minimize well failures, the wear on wear of rods and tubing, and all of the efficient operation of a sub-pump versus a rod pump. A lot of that is coming through increased production, but it also leads to a lower overall cost. So we've put an awful lot of effort into proper chemical treatment, proper well design, proper rod design, guides, rotators, a lot of work going into being better with our base operations, because we think that's where a lot of money can be made, and we should never lose sight of that; regardless of how fast we're running on the new well, drilling and completion side, the base operations delivered solid results.

And so I think a lot of that's pretty sticky as well. I think certainly all of the vendors again will try to try and work with us the best they can and be as competitive as they possibly can in an increasing price environment and a higher competitive price environment. But so far, we're getting a lot of interest from a lot of companies who want to help us be better at what we do, not just from cost concessions, but learning more about how we can be better at running our base business.

Ronald E. Mills - Johnson Rice & Co. LLC

Perfect. Thanks, guys.

Gary A. Newberry - Senior Vice President-Operations

Thanks, Ron.

Operator

The next question will come from Irene Haas of Wunderlich. Please go ahead.

Irene Oiyin Haas - Wunderlich Securities, Inc.

Hey. Good morning. Just a little question on Howard County in general. This is not like the west side of the basin, which is really well wired. So I was wondering, when can you start the permitting process? In 2017, how many rigs or wells you need to drill to keep your acreage? And generally, how's the gathering picture there on the ground, water disposal, things that just – power supply?

Gary A. Newberry - Senior Vice President-Operations

Yeah, Irene. Those are good questions. And that's why I like the fact that I'm going to take a few months here to plan all that out before we actually start up the rig. I'm anxious to get started, because it's a great asset base to have. We see a lot of really good potential here, especially around all the wells that have already been drilled. A lot of work has been done to de-risk this area, and we're happy to have it.

But you're right. It's not as interconnected and infrastructure as well developed as some of the other more active areas in the basin have been to-date. We will work hard to – and even partner with many of the companies that are out there that are around us, whether it be Rock Oil or Encana or any of the other companies – and even Diamondback's close to us up in the northern part of Howard County, with figuring out how we can best together develop the right disposal infrastructure. Water sourcing doesn't seem to be much of a challenge to us up there right now, because there's a lot of work that's been done with that already. And then we'll work hard to connect every bit of this, just like we did in 2015 for our legacy asset's two-pipe to move the oil product out of the basin much more efficiently. As Joe said, we've increased our margins there by almost $1.00, by our solid focus on that effort. And we'll do the same thing there.

There's a lot of interest in that area as activity levels ramp up. But – and we're already talking to several of our current transporters today about their plans in moving that area. And there's already still good activity – or good capacity in the area. We just aren't connected to it yet. But that all aligns to an active program, right? And so, again, I would hope, and then as we've talked about and as Joe's shown on the last slide that we're driven or we're working towards starting that second rig back up in Howard County in the fourth quarter, so long as we're prepared to go do that and be efficient with it. So we're reaching out already, even though we don't actually have the assets yet. We're reaching out to other operators. And we're already planning technical exchanges as well as operational discussions. That way we can all be more efficient in the area.

Irene Oiyin Haas - Wunderlich Securities, Inc.

Do you have power lines up there? Do you have power?

Gary A. Newberry - Senior Vice President-Operations

Yeah. We do have electrical power. We don't seem to be short on power at this point in time in the areas that we're at. But again, as we align – that kind of goes to the partnerships that we have with all of our providers. Even power providers are willing to upgrade their systems, so long as they see the demand coming. And a company like Callon, when we put our plans together, we execute on them. We hope people understand that that's what we do, and that they can count on that additional demand or revenue even to them after they upgrade their systems should it be necessary to all participate in better revenue growth. So we'll work on that. We're pretty connected to that, but there's power everywhere we're at.

Irene Oiyin Haas - Wunderlich Securities, Inc.

Good. Great. Thank you.

Operator

Our next question will come from Will Green of Stephens. Please go ahead.

Will O. Green - Stephens, Inc.

Good morning, guys.

Fred L. Callon - Chairman, President & Chief Executive Officer

Good morning.

Gary A. Newberry - Senior Vice President-Operations

Hi, Will.

Will O. Green - Stephens, Inc.

Wanted to stick on the same theme for just a minute and talk about infrastructure out there. I know there's a refinery out there in Big Spring that probably helps you guys out a little bit, but it does sound like that there's still some transport to maybe figure out. So I guess the question is, is the proximity to that refinery enough of a benefit to where it offsets some of those additional costs on the transport side. Should we expect that maybe there's a little bit of creep up in LOE costs as you initially ramp-up production there? Or perhaps differentials look a little bit wider? How should we think about how that interacts with the model once you guys start bringing on new production from that area?

Gary A. Newberry - Senior Vice President-Operations

As far as LOE goes, Will, I'll talk about in a couple of different forms. But as far as LOE goes, once we solve the issue of water management, which is the biggest driver for us on LOE in a newly – new and emerging developing area, and we're already focused on that now, then I think LOE should be well managed throughout the area. They have good metrics today in the assets that they have. They're operating those very efficiently. And that we've just got to get prepared for the ramp-up. So until we get that solved, there could be some additional cost in water disposal, not so much in water sourcing, because they've got good water sourcing opportunities in the areas that we're currently planning to focus on in 2017 today.

Actual well management today, they do a very good job with the way they designed their wells, the way they operate the wells, the way they optimize production. So I feel like we will just continue that same practice, perhaps improve upon it just a little bit, but ultimately, that's the value of merging several different teams because some of their team is coming with us to join us, so we're happy to have them to effect a very smooth transition.

As far as the refinery goes, it certainly should provide us a pretty good opportunity to deliver crude at a very short and low cost to that refinery, and we'd love to be one of their providers. But we're not going to count on that refinery all the time. We've got to have a supply that goes out of the marketplace. And there's a couple of systems in there right now that are close. And then there's systems that we work with in the southern part of the basin that are building out. So, again, that all gets aligned with a defined, committed development program. And once we get started, I think the competition for our products will intensify, and we'll get some of the best options available to us.

Joe, do you have something else to add to that?

Joseph C. Gatto, Jr. - Chief Financial Officer, Treasurer & Senior VP

No, I think that's right. Best we can do is stay ahead of it; we are getting a lot of inbounds from folks in terms of talking about what our plans are for takeaway, and starting those conversations early. But it is an area overall that's active, I think. The last drilling activity report I saw, about five rigs or six rigs running in Howard, a lot of activity which is getting the attention of midstream folks. But, yeah, the refinery's a good start. But I think it's important to have a lot of options around that so that there's some more pipe going in the ground out there. And we'll – whether it be us underpinning some more activity, or some of the other offset operators, that collectively we put together a good system.

But we feel pretty good. We've tried to capture some of that. It's not going to have much of an impact this year, because as Gary said, what they've been doing is very competitive on an LOE basis, relative to what we are doing. I think going into 2017, hopefully we'll have a lot of that figured out and it won't have really any impact on our LOE in terms of what we've been running on our baseline.

Will O. Green - Stephens, Inc.

Great. I appreciate the color there. And then, slide six in the presentation is very informative. It definitely shows the differences you guys are seeing on well costs now versus some time ago. Are we at a point in the cycle where you guys are looking at maybe applying some of these savings back into the wellbore and experimenting with some newer technologies? One thing that I did notice is it does look like average profit per stage is down a little bit, so maybe that rules that out. But I wondered if you could just talk about that. Are we at a point where you guys maybe are looking at some different things that maybe enhance the EURs versus just straight cost-cutting measures? I'd love your take on the balance there that you guys are considering.

Gary A. Newberry - Senior Vice President-Operations

Yeah. Well, that's a great question. And we spend a lot of time on things like that here. And we are going to – we pay a lot of attention to what was recently published, right? I mean, Pioneer came out with a lot of data, all on things just like that. And RSP talks about some of the experimentation that they've been doing, and we're very encouraged with things like that. Those are very good companies that have done a lot of the early-time work on showing what good technical application can do with enhancing completion design. But at the end of the day, the wells we're about to complete, we're going to go ahead and increase sand proppant. We're going to experiment with shorter stage lengths. We are going to start applying more of that as we go forward, because we want to get to an optimum number.

And we're happy that all those other companies are doing that work, because it gives us a larger data set to actually look and compare. And we're encouraged with some of the work that we've already done on that. But we hadn't seen a major uplift in that. But the next three wells or four wells that we complete we think will be somewhat telling. So especially on the new assets. We're looking around at what has been done, and what we can do that can enhance even that performance above the type curves that we purchased it at (34:08).

So, yes, we are going to do a little bit more work on that. We won't be too aggressive, because we'll be very mindful of making sure the cost-benefit analysis is truly there, and that we don't get too far ahead of ourselves in capital efficiency. We have been very mindful of that, as you know.

Will O. Green - Stephens, Inc.

Absolutely. Thanks for the color, guys.

Gary A. Newberry - Senior Vice President-Operations

Thanks, Will.

Operator

Our next question will come from Neal Dingmann of SunTrust. Please go ahead.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Hey. Good morning, guys. Maybe a question for you, just looking at that slide 5 versus 2015, just looking at the type curve of the existing, obviously, versus the Big Star. The question is, I'm just kind of looking at that type curve comparison. Is it fair to say, I mean, I guess the way you're kind of envisioning now, pretty comparable? I mean, am I looking at that – or is it still just a bit ahead on the existing acreage?

Gary A. Newberry - Senior Vice President-Operations

We're very encouraged with the results of the wells that are producing today and we think that those are exceptional wells. Certainly the A wells are solid performers. Lower Spraberry, not quite as good. Early time, for those wells that they have there, but certainly still very good. The A well we're about to complete together, jointly, we've been collaborating. We had a meeting in Midland actually this week with the current owners and current design, as well as with the Callon team, and came out of that meeting with a couple of suggestions on how to further enhance completions to even outperform this type curve. So we're pretty excited about that, Neal, and we think that we'll have – we hope to be able to tell you that we're delivering solid results beyond what we've seen on this slide on page 15.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Yeah. I've got confidence in this, definitely. Last question, just in the release, it mentioned about commencing activity in early October. Again, could that depend again on prices, how aggressively you sort of start hitting that in October? I mean, again, I'd love to hear from Gary either you or Joe or Fred just how you see, kind of thoughts about when you start tackling this new (36:39)- is it price dependent? Or are there a lot more other variables obviously to consider once you start tackling that?

Gary A. Newberry - Senior Vice President-Operations

Joe or Fred?

Joseph C. Gatto, Jr. - Chief Financial Officer, Treasurer & Senior VP

Yeah...

Fred L. Callon - Chairman, President & Chief Executive Officer

I'll jump in. This is Fred. But – and Joe just mentioned, and I think you've heard us say that cash flow neutrality has just been a goal forward here and we feel like we've gotten there this quarter. And we'd like to see a couple of quarters where, quite frankly, we proved ourself, we're there, we're living within cash flow while we monitor commodity prices. But the short answer is, as sure as we – prices strengthen and we build a confidence there that they're going to remain strong – relatively strong, we may bring the rig out earlier. But as we said, clearly, we've got the economics and projects. Right now, we've got this great acquisition and we're integrating that and obviously getting ready to bring the first rig. When we bring the second rig out, we're going to Howard County. So all of those things come into play, but I think the driving point for us has been the balance sheet. And, obviously, we feel good about the balance sheet and, obviously, we've got great liquidity. So commodity prices remain strong, improve, and operationally, we get ready, there's certainly a chance we can bring the rig out before the fourth quarter.

Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.

Makes sense. Thanks so much, Fred. Thanks, guys.

Operator

And our next question will come from Jeff Grampp of Northland Capital Markets. Please go ahead.

Jeff S. Grampp - Northland Securities, Inc.

Good morning, guys.

Gary A. Newberry - Senior Vice President-Operations

Good morning, Jeff.

Jeff S. Grampp - Northland Securities, Inc.

I just wanted to talk about Howard some more. As you guys plan to get the rig out there, how are you thinking about developing that in terms of, from a pad development perspective? I mean, do you go a three-well pad all in the A? Do you do a stacked across the A/B, Lower Spraberry? Or how are you guys kind of thinking about that today?

Gary A. Newberry - Senior Vice President-Operations

Yeah, Jeff, that's a main point of discussion that we're having within the team right now. We certainly will likely start, given what we see in the larger chunky part of that acreage position in Central Howard County. And we're very excited about those A results that are being delivered there. And so we'll likely start with – at least the way we see it today – with two-well pads. And we'll want to get a couple of A wells done, and then we'll want to certainly test the A, Lower Spraberry pairs. And then we'll certainly want to figure out how we go forward with that. But right now, it's A, Lower Spraberry, with a focus on the A, with a minimum of two-well pad development to be efficient with rig moves and capture all the efficiency related to multi-well pad development.

Jeff S. Grampp - Northland Securities, Inc.

Okay. Perfect. That's helpful. And then I noticed, I think it was on slide four, you guys mentioned some artificial lift optimization at Garrison Draw, positively impacting production. That seems to be a topic a bit in the Midland Basin in terms of kind of what's optimal for various zones and areas. Can you guys just kind of talk about what you all did there, and your thoughts on that front?

Gary A. Newberry - Senior Vice President-Operations

Yeah. What we've been doing there, Jeff, is really – we've been a bit conservative. We've talked about it a long time, on how we've been pulling wells with sub-pumps. We've been cranking that up just a little bit, trying to find that nice sweet spot. We won't pull them hard to where we're pulling a lot of sand in from the formation, but we think we've been a little overly-conservative on that front. So we're starting to crank that up to a midpoint. We don't know if we've found the sweet spot quite yet. But also, we're looking hard at how we optimize even our rod strength designs, as we shift from sub-pump to potentially a smaller sub-pump, and ultimately to a rod pump. We've been able to – like I said, a part of understanding our whole business – increase the overall performance of those wells in a very positive way.

Jeff S. Grampp - Northland Securities, Inc.

Got it. That's helpful. Great quarter, guys.

Gary A. Newberry - Senior Vice President-Operations

Thanks.

Operator

Our next question will come from Gabe Daoud of JPMorgan. Please go ahead.

Gabriel J. Daoud - JPMorgan Securities LLC

Hey. Good morning, guys. Just wanted to make sure – maybe I heard Gary's comment earlier in the prepared remarks correctly – did you say that you guys are going to drill or participate in an additional five longer laterals in Midland County, and did I hear that right? And does this deviate at all from the base business plan of – was it 14 net completions for the year?

Gary A. Newberry - Senior Vice President-Operations

No, that's just restating what was in our base plan. I just wanted to emphasize that, even though we're somewhat restricted on the Casselman and Bohannon on lateral length, we're very happy with that well performance, because those are still very capital-efficient with the capital costs we're delivering on those, and the exceptional results we're seeing from those wells. But we also have opportunity in Central Midland Basin for long laterals as well. I was just trying to re-emphasize that point. It is part of the base business that we've already defined.

Gabriel J. Daoud - JPMorgan Securities LLC

Got you. Got you. Thanks, Gary. And then just broadly speaking, obviously, in getting the big deal done – and congrats on that – but just wanted to get a sense of your appetite for further blocking up some acreage in Midland County, or even just in other areas of Midland? Just kind of what the appetite is there, and if you probably need like 12 months or 18 months or so just to digest this new deal here?

Joseph C. Gatto, Jr. - Chief Financial Officer, Treasurer & Senior VP

Well, certainly this is a meaningful transaction, and a new area. But I don't think that 12 months to 18 months is a timeframe that we're going to sit still, right? I mean, the premise here is that we have a very capable operational team looking to overlay that on a larger footprint. But I think one of the biggest things is going to be, we have to have a path to getting to develop it and bring forward the returns on anything that we're going to step into from here.

So we still have a lot of flexibility in our business, because we are held by production on all of our legacy properties, which – the flexibility has not gone away. So, out of the gates, we're certainly going to be looking to do more around that Howard County footprint. And bolting-on, it is a little bit more of an emerging area. But there is a lot of deal flow, and we think we're going to have some opportunities to bolt-on in that new core area.

But no, we'll continue to look at bolting-on around our existing acreage. And we're certainly not precluded from looking at similarly sized deals in the not too distant future. And we have built a lot of flexibility in the business from an operational and financial standpoint. I think that the market, investors appreciated what we can deliver on the operational side, and I think being supportive of additional acquisitions going forward.

Gabriel J. Daoud - JPMorgan Securities LLC

Thanks, Joe. That makes sense. That's all I had, guys.

Joseph C. Gatto, Jr. - Chief Financial Officer, Treasurer & Senior VP

Thank you.

Operator

Our next question will come from Mike Kelly of Seaport Global. Please go ahead.

Mike Kelly - Seaport Global Securities LLC

Hey, guys. Good morning. Just a point of clarification here. That base case plan that you laid out in slide 12, is that – right now, does that match up with that – the $95 million to $105 million of CapEx, or is that something that will be adjusted after next quarter?

Joseph C. Gatto, Jr. - Chief Financial Officer, Treasurer & Senior VP

It'll probably be revisited. The $95 million to $105 million number, Mike, really contemplated the one-rig program, plus three drilled uncompleted wells that are part of the transactions, plus some infrastructure work around getting prepared for getting going a little bit harder in 2017. So there's probably a little bit of an increment from the impact, depending on the timing of when we get going in the fourth quarter. So we'll update it again. It's not going to be a huge delta, but we're going to have to refine that a little bit once we figure out the right pace, and if it's in October, November, September when we get going with the rig.

Mike Kelly - Seaport Global Securities LLC

Got it. Okay. You guys previously laid out some thoughts on 2017. It was really kind of more on the bear case scenario, just running one rig. But if you run through a couple of those scenarios, slide 12 there, maybe put some more rigs back to work, have you done any preliminary studies on what that could mean for you from a growth perspective in 2017? Just kind of curious on how you guys foresee it playing out next year. Thanks.

Joseph C. Gatto, Jr. - Chief Financial Officer, Treasurer & Senior VP

Sure. Yeah. Short answer is that we've certainly looked at a lot of different cases. But I think it's just premature to talk too much about where the direction is. We've laid out three different scenarios here. Embedded in each of those are going to be how we attack pad development, how that impacts timing, production coming on line, things like that. So I think at this point, we'll probably table that and revisit it in August, once we have a little bit more refined plan, once we have the transactions closed, and provide a little bit more visibility.

Mike Kelly - Seaport Global Securities LLC

Got it. Makes sense. And, Joe, maybe a final one for me. You guys have done really just a great job in terms of getting your capital efficiency to be – spot is better than everybody else in the basin. If you look at that slide 15, and I know you guys are hoping that Howard ultimately puts up economics pretty similar to your legacy – your legacy in Midland acreage. But if there is a delta, if there is 2x returns on your legacy acreage, how do you think about allocating capital going forward? Are you still going to try to just maintain activity really weighted for the best returns, or are you going to have to spread it out more?

Joseph C. Gatto, Jr. - Chief Financial Officer, Treasurer & Senior VP

We're always going to be biased to the best returns, which we have done, right. We've shown that in terms of how we've pivoted the business over the last several months, and moving all of our activity Lower Spraberry and Midland County and managed volatility. But I think the strongest message here is we wouldn't have stepped in this position if we didn't think it could compete for capital on a similar basis with what we're doing in other areas.

And we like to – we look at acquisitions of this magnitude, we are going to have a bias to, let's not get over our skis in terms of type curves, and see a real path to improving that efficiency, whether it be from overlaying next-generation completion techniques, working on the capital side – which I think we've shown our ability to get down that cost curve. So we see a good path for getting the returns even better than what we've shown here, which will squarely compete for capital. I would imagine, going forward, we will be spreading out our activity a little bit, and Gary can comment on that, but I would expect that we're going to have one to two rigs in our legacy properties in Midland County, one rig to two rigs in Howard County and some other activity in some of our high-graded operations in Reagan County, over time, and just giving you some directions. So it'll be spread out. We have some really good areas that all compete for capital in our minds.

Mike Kelly - Seaport Global Securities LLC

Okay. Great. Thanks, guys.

Operator

And our next question will come from Jeb Bachmann of Scotia Howard Weil. Please go ahead.

Jeb Bachmann - Scotia Capital (USA), Inc.

Good morning, guys. Just a quick one from me, Gary. I know you guys have gotten some cost relief, day rate relief on the Cactus rigs here as the price declined. And just wondering when that starts to go back up? And could you mitigate that by adding that fourth rig potentially later this year?

Gary A. Newberry - Senior Vice President-Operations

Four rigs? Whoa. That's an exciting time. That's great, Jeb. Thanks for planting that seed. But, yeah, I had a conversation with the Cactus guys just the other day. They were excited about our asset acquisitions, and they're excited that, given the partnerships that we've had, that it actually leads to potentially more business for them. And they had no questions about when they'd start clawing that back. They were happy with where they are, with what we're doing. And moving on, they recognize that we need to see a longer-term strengthening of commodity price environments, and a little bit less volatility than we're seeing now.

But they see the opportunity to work more actively with us, because of the way we've worked. And I think you've hit it, that because of that – again, all of our service providers, including Cactus, will do their best to manage cost, even upward-appreciating cost in a competitive environment – higher competitive environment going forward, because of the way we've worked together in the down-cycle. It hasn't been just bid, bid, bid and get to the lower cost. It's been, what can we do together? And that's the kind of conversation we had with Cactus.

So I think we're well-positioned with them, Jeb, and all of our service providers in that environment. And I'm thankful for what they've done. They were an early mover in 2015. They gave us the courage to keep moving and keep going, and help us get to where we got to. Same with ProPetro Services as well, on the pumping services side. So we have solid relationships with those guys. And I think it'll help us going forward. And the increased activity is only a benefit to all of us.

Jeb Bachmann - Scotia Capital (USA), Inc.

Great. I appreciate that, Gary.

Operator

And our final question this morning will come from Ipsit Mohanty of GMP Securities. Please go ahead.

Ipsit Mohanty - GMP Securities LLC

Hey. Good morning, guys. Thanks for squeezing me in. I appreciate your slide of the scenarios, slide 12. And I hate to break up the four-rig party a bit. But if you think about, let's say, you go through the transaction and then after that you kind of almost show one rig for a year on the bear case scenario, when you go through the transaction then oil takes a leg down. How do you think about that one rig between your Central Midland and Howard County?

Joseph C. Gatto, Jr. - Chief Financial Officer, Treasurer & Senior VP

We would be a little bit biased to Howard County, just because we do have some wells to drill there in 2017, roughly eight wells or nine wells. But – so there would be a lot of activity there, but we would also continue in the Midland County area as well. I guess, Gary...

Gary A. Newberry - Senior Vice President-Operations

The way I understand it today, Ipsit, is that we've got five two-well pads, so ten wells to drill to hold those – that whole entire package together, in good prospective areas, we're happy to be drilling those wells. And it's going to help fully define the full potential and what we can actually do to further enhance the development in Howard County.

And so we'll do that, and if oil takes a leg down, we'll do what's necessary to keep that all working together and kind of prove to ourselves, what is the difference in returns between that area and our Central Midland Basin assets. Because we're blessed and happy to have those Central Midland Basin assets, and it's very difficult to duplicate those types of returns and capital efficiency. But at the end of the day, we intend to do that very thing in Howard. And if we do, then we'll be indifferent. But if not, we'll be still driven to value, we're always driven to value. And we'll do the minimal case for holding the leases together and get back to what's delivering the best returns.

Ipsit Mohanty - GMP Securities LLC

Okay. Thanks for that. Gary, you look at slide five, left-hand side chart, where you see the average well going below the type curve, and then suddenly it shoots above that. I was just wondering what happens there and what causes that sort of an uplift or boost to the type curve?

Gary A. Newberry - Senior Vice President-Operations

Once again, that's really an operating philosophy, is what it's been. Again, we've been very – I just kind of mentioned it a little earlier – some of the optimization we recently did in Garrison Draw and Reagan County was really starting to crank those sub-pumps up sooner. And so we'll claw backs. We've known we've left some value on the table by doing that, but we'll claw back as we start ramping those up a little bit sooner. We won't get to – again, we won't likely just pull them as hard as we possibly can to get headline IPs. We're not into that. We're into long-term value creation. But that's really the difference. It's really operating philosophy going forward there.

Ipsit Mohanty - GMP Securities LLC

Okay. And then one final one, and this is sort of for the team in general. When you looked at these transactions, and if you've looked at everything that's come under – I was wondering, beyond price, were there other decisions that fed into going into sort of an island like Howard, island in the sense that you were not there before, versus bolting onto where you had in Central Midland or Southern Midland?

Fred L. Callon - Chairman, President & Chief Executive Officer

I'll jump in and just say that I think the Howard County, which as we counted before – obviously, we worked the entire Permian and focus in the Midland Basin – but Howard County, the well performance up there really I think is what was driving that. We felt like it gave us an opportunity to add another core area that we could continue to hopefully do the bolt-ons around that. And as Gary's kind of outlined, I mean, we certainly feel like that it's an area that competes for capital even today. Right now, it's strong as what we're doing in Northwest Midland County, but I think we saw this opportunity to add significantly to our position and do it in what we consider to be a core area. And that had the potential, I think, to compete for capital today. And there are not a lot of opportunities like that in the Midland Basin.

Ipsit Mohanty - GMP Securities LLC

Got you. Okay. Thank you, guys.

Operator

And ladies and gentlemen, that will conclude our question-and-answer session. I would like to hand the conference back over to Fred Callon for his closing thoughts.

Fred L. Callon - Chairman, President & Chief Executive Officer

Once again, thanks to everyone for taking time to call in. As you can tell, we're excited about where we are today, despite the current commodity price environment. And I think maybe key takeaway, hopefully, to understand is the flexibility we have. With great assets, and great operating team, and strong balance sheet, we feel like we've got the flexibility to pivot as necessary going forward. And hopefully with the continuing improvement in commodity prices, we'll see a continued ramp-up in our activity throughout the year.

So once again, thank you for taking the time to call in, and if anyone has any questions, don't hesitate to give us a call any time.

Operator

Thank you, sir. Ladies and gentlemen, the conference has concluded. A replay of this event will be available for one year on the company's website. Thank you for attending today's presentation. You may now disconnect.