Callon Petroleum Co (CPE) 2017 Q3 法說會逐字稿

Good morning, and welcome to the Callon Petroleum Third Quarter 2017 Earnings and Operating Results Conference Call. (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.

At this time, I would like to turn the conference over to Mr. Mark Brewer, Director of Investor Relations. Please go ahead, sir.

Thank you, operator. Good morning, everyone, and thank you for taking the time to join our conference call today. 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 on 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'll 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 as well as 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 Gatto.

Thanks, Mark, and thanks to everyone for joining us this morning. Our quarterly earnings release was out yesterday after the market closed, and I believe it reflects how focused we are on creating value. Despite 2017 overall being a year of significant transition for us, we've clearly maintained our vision of responsibly growing the business and enhancing our corporate level returns while maintaining a line of sight to near-term cash flow neutrality.

With that I'd like to direct you to Slide 4 of our presentation. During the third quarter, we continue to drive down operating costs, while maintaining a strong base of oil rich production, which resulted in continued growth in our operating margins. Our oil production mix of 77% was directly in line with our guidance as was the overall production rate of 22,500 barrels of oil equivalent per day. Total production was up 36% year-over-year, and with the addition of our fourth rig in July, we expect to meaningfully grow that production rate into year-end with the impact of new wells that were brought online around the end of September, an estimated 13 completions in the fourth quarter and a reduction in the production volumes that were offline for completion activities in the third quarter.

While we did have another strong quarter of cash margin expansion, our production volumes fell short of our original expectations. We experienced a higher-than-expected level of production that was offline for offsetting completions in frac operations by offset operators at Carpe Diem. We also experienced extended cycle times in the quarter, due to unplanned downtime from services, such as wireline and coil tubing operations that support our completions. While I expect these types of issue to be transitory and have seen improvements in cycle times over the last several weeks, the resulting scheduling delays did shift our completion schedule and resulted in a reduction of total wells online for the year. Based on these delays and completion timing and lower-than-forecast nonoperated activity for the year combined with the assumption that we will continue to see longer dewatering times for Lower Spraberry wells and WildHorse discussed last quarter persist, we revised our full-year production guidance in October to 22,000 to 23,000 barrels of oil equivalent per day, representing a year-over-year growth rate of 48% at the midpoint.

Importantly, we are off to a solid start through October with strong production growth, which we expect to drive sequential fourth quarter growth of approximately 10% at the midpoint, including the assumption of increased December downtime for weather-related issues and set the stage for a strong trajectory in 2018. Operations team has been diligent in working to reduce field operating costs, as we have increased activity and our hard work is reflected in the 23% decrease in lease operating expense per BOE since the first quarter. This improvement translates into continuous improvement in our EBITDA margins over the last 4 quarters with a 74% adjusted EBITDA margin achieved in the third quarter. In addition to generating one of the highest cash margins in the industry, our team continues to post consistently strong results across all of our 4 core operating areas. A couple of these highlights include -- it's Spur, our first operated Callon well has been producing above the type curve through the first 30 days and has generated a peak 24-hour rate to date of about 238 BOE per 1,000 lateral feet under natural flowing pressure. At WildHorse, Wolfcamp A program has demonstrated consistent production results with very high oil cuts across our entire Howard County position and will be an important underlying driver of our growth going forward.

And at Ranger, our first 2 Lower Wolfcamp B wells since 2015 have shown very strong natural flow rates and through the first 60 days are exceeding oil type curve for this area. This is a great outcome for an underappreciated area within our portfolio that will continue to attract capital into 2018.

As I mentioned, we're running 4 operated rigs, 3 in the Midland Basin and 1 in the Delaware and in our final contract discussions for a fifth rig. We expect this rig to be working in the field at our Spur asset around the middle or the first quarter of 2018.

Moving over to Slide 5. There's been a great deal of talk recently about the industry's need to generate sustainable corporate level returns. This has been a focal point for Callon for some time after deploying the capital needed to build what we believe is a world-class asset base. Our continued focus on efficient and thoughtful long-term development underpins our corporate planning process. We consistently evaluate the full-cycle returns available across our asset base to create a development program that provides a path to corporate level returns that will exceed our cost of capital. In order to do this, we need to pull forward the attractive field level returns offered within our portfolio within a defined and a reasonable framework of both leverage and liquidity levels. Moreover, we will maintain our consistency of maintaining a visible path to cash flow neutrality within 4 to 6 quarters at planning case priced X after increasing our operational activity to preserve our operational and financial flexibility.

These return objectives create a high bar for organization. We believe these goals are readily attainable given the exceptional internal cash margins generated from a high-quality asset base and a proven ability to execute at increasing levels of activity while also reducing our cash operating cost structure. With a robust pace of internally generated cash flow per BOE produced coupled with an asset base position for capital efficient development with investment in critical infrastructure in 2017, we believe we are well positioned to earn strong returns coupled with sustained production growth as we exploit our resources base.

If you look at Slide 6, you can see that we have delivered impressive growth over the past 3 years, and expect to achieve growth approaching 50% this year compared to 2016. Like most of our peers, we're well into 2018 budgeting process and developing a plan that furthers the returns and financial objectives I just discussed for a measured increase in operating activity.

This increased labor groundwork for our broader 2018 operational program that incorporates a number of potential organic growth opportunities as well as operational efficiency initiatives including downspacing test in Howard County, delineation of new zones in both the Midland and Delaware Basins, simultaneous completion of adjacent multi-well pads to improve capital efficiency and reduce the impact of offsetting completion operations, and development of the small DUC inventory to improve operational flexibility as we increase our activity.

Our ultimate production growth rate in 2018 will be the result of the balancing act between capital allocation to accelerate robust well level economics and prudent management of our financial position. While I do expect 2018 to generate an outspend at our planning case prices, we remain squarely focused on a clear path to near-term cash flow neutrality, something we have been talking about consistently for some time now.

On Slide 7. We provide an update for our capital outlays for the year. As I mentioned previously, some of this change from our original budget is due to the natural course of change in our overall drilling plan and mix of lateral lengths and working interest. Another change we made as we pursue the optimal development of the resource with adding roughly $8 million to the budget as we have increased our usage of rotary steerables in drilling and an increasing portion of the long laterals -- sorry, an increasing portion of long laterals and incorporation of enhanced diverted [zones] in our completions.

In addition, with the ultimate decision to allocate our planned fifth drilling rig to the Delaware versus the Midland around mid-year, we accelerated a few critical facilities projects to support that 2-rig program in the near term. However, the forecast of this acceleration of capital will be offset in its entirety by the selective monetization of infrastructure assets by year-end with additional opportunities for monetization in the future. The other portion included in the capital increase is related to service cost inflation above our original estimate of 10% for the year, which is now expected to be approximately 15% on total D&C costs. As we are formulating our budget for 2018, we are [eyeing] several initiatives to counter any future potential inflation.

With that, I'll turn the call over to Gary.

Thank you, Joe, and good morning to everyone listening in today. Beginning on Slide 8. I want to highlight some of the critical infrastructure activity that we have been discussing throughout the year. Joe mentioned how significant the improvement in LOE per BOE has been. This is a direct result of hard work by our field operations teams and thoughtful investment and properly scaled infrastructure. These are long-term benefits and contribute not only to improved margins in the immediate quarter but carryover that margin enhancing benefit well into the future as we further develop the assets in these areas.

You can see here that we've been active across the entire scope of our Permian operations, something that we stated would be important in preparing for multi-year development of an asset base that tripled in just over a year. Roughly 3 months ago, saltwater disposal became a hot topic throughout the Permian Basin. As we mentioned during our last call, we've been very proactive in addressing saltwater disposal both from the standpoint of deeper disposal wells as well as water recycling. We're adding or upgrading 7 different saltwater disposal wells, 4 in Midland and 3 in the Delaware over the course of this year. In total, we will have added more than 200,000 barrels per day of disposal capacity across our footprint. This really enhances our ability to deepwater wells in a cost effective manner and brings new production online without concerns around disposal or rate limitations. We've also secured the ability to dispose of these volumes at much better rates, further reducing our associated expenses per barrel produced as we ramp activity.

On the recycling front, we are currently utilizing third-party frac water volumes in the Casselman area at Monarch. This is yet another benefit of our continued efforts and we should soon be able to utilize recycled volumes across nearly the entire CaBo area which will see a fair amount of activity during the fourth quarter of 2017. We've also made headway in prepping the water transfer lines, recycle facilities and frac pits at Spur to maximize efficiency as we kick off our 2-rig program in 2018. We expect to see meaningful savings as we ramp our recycling program in the Delaware.

We've progressed plans to install electrical substations in Howard and Ward counties which will reduce the need to utilize temporary generators to run our ESPs across a large portion of our footprint. As a result, we will relieve ourselves of rather expensive rental generator fees and fuel cost while increasing overall reliability.

Over the past 2 years, we have made a concerted effort to get all of the new pads on the LACT units and feed oil volumes directly into gathering systems. Our trucking costs vary [binary] and this likely saves us anywhere from $0.50 to a $1 per barrel of oil produced as well as reduces downtime risk associated with trucking barrels during the problematic winter months.

Moving on to our Spur assets on Slide 9. We are very pleased with the outcome of our first operated Lower Wolfcamp A well, Sleeping Indian A1 #1LA. It's still very early for this well with first oil production coming at the very end of September, but through the first 4 weeks, we've seen very good performance currently outpacing the 7,500 for type curve by more than 60% on a cumulative production basis. This is our first well utilizing our refined landing zones and refined completion design, which reduced the profit loadings and employed a greater number of clusters per stage. Overall, we are very encouraged with the early outcome here and look forward to seeing its continued performance.

Our next well, the Saratoga A1 #7LA, finished frac operations and is in the early stages of flowback. We will drill 1 more single well pad before kicking off our multi-well pad operations in the Delaware with staggered upper and lower Wolfcamp A wells from a single pad. As we continue to evaluate the best way to develop our Spur asset, we are continuing to acquire data to improve our planning and analysis. We have recently drilled a pilot hole when taken [sidewall cores] on the Avalon Shale through the Wolfcamp C at Spur. We will be using the analysis from these data samples to enhance our drilling program design and determine which intervals to focus upon beyond the established 2 flow units in the Wolfcamp A and the Wolfcamp B. We are encouraged by offset operating results nearby in the second Bone Spring shale and the Wolfcamp C. Both of these intervals are likely to see capital in the relatively near future, as we look to delineate our acreage vertically.

On Slide 10. You can see that we continue to have very impressive performance across the entire acreage position at WildHorse, with multiple Wolfcamp A wells online and a few more currently on flow back. The Players wells continue to increase in rate and are both approaching a rate of 1,000 barrels of oil per day. The Garrett wells have been online roughly 2 weeks and are showing very solid early performance as well. The Wright Unit well was actually placed on flowback this morning. We are continuing with our program here and have another 3 to 4 wells on the drilling schedule for the fourth quarter, although almost all of those will see first production in early 2018.

Last quarter, we discussed how our Lower Spraberry wells and Howard County were taking longer to clean up with a larger frac designs and that we expect it to revert to a smaller design that will enhance the near-wellbore in nature of the fracture network. As we are in the early stages of flowback for this small sample that we have thus far, we will provide more data on the next call. Along with the reversion to lower sand loadings, we recently changed the order of completion for stack laterals in the Wolfcamp A and Lower Spraberry. In 2018, we plan to test the staggered placement of Wolfcamp A and Lower Spraberry wells in this area as we believe there could be some level of interference between the 2 zones when developed in a stacked pattern.

Our existing WildHorse inventory represents a premier opportunity to invest capital. We are excited about testing tighter spacing within the Wolfcamp A in this area in 2018. If we can create the same quality outcomes with 10 wells per section versus our current assumption of 8 wells per section, the value uplift will be significant, as we would add roughly 25% to our inventory in this prolific area. We have also begun to test the Wolfcamp B and look forward to providing updates in this zone in coming quarters.

Moving on to Slide 11. Our Ranger assets have become an area of significant interest, as we have reinitiated drilling activity here for the first time since 2015. During the quarter, we've gone online are 2 Eaglehead Lower Wolfcamp B wells, both of which flowed under natural pressure well into their third month. We've since placed them on pump and they continue to outperform extremely well. As you can see on the slide they have been outperforming the oil type curve on average by more than 23% thus far. Our first Wolfcamp C well in Reagan County along with 2 more Wolfcamp B wells are slated for completion during the latter half of the quarter and should be placed on production right around year-end. With very positive results from offset wells, we are excited about the potential in this area but we'll wait for further results before committing to significant activity beyond the current lineup. Should our results support additional activity, we could be looking at 50 locations in the Wolfcamp C and Reagan County, a zone that we have never featured as part of our inventory.

Slide 12 features on Monarch assets. And while we did not bring online any new wells here during the third quarter, we did complete the drilling and completion of our Kendra pad. This 3-well pad featured our longest laterals to-date in the Midland Basin, at an average true measured depth of 21,127 feet. All 3 wells were recently completed and placed on production during October with average completed lateral lengths of 10,601 feet. Although it's early, we really like what we are seeing from these wells as they move into the fourth week of production. Also on Monarch, we are currently fracking Casselman wells utilizing recycled frac water. Not only is this the responsible course of action, but it achieves the goal of reducing costs both for sourcing and disposal. As I mentioned earlier, our recent strides in infrastructure are critical not only for operational efficiency but to create lasting, cost advantages as we continue to develop our assets with greater scale.

I would also like to touch on 1 of our operations initiatives in 2018 that we believe can make a real difference in our long-term development plans. Many of our peers have begun utilizing various cube or tank style development techniques. We are currently planning to conduct simultaneous drilling operations involving 2, 3 well pads side-by-side at on Monarch asset. We will then complete all 6 wells together and bring all of the new wells online simultaneously. The underlying goal here is to really focus on reducing the impact of refracking into wells that have been recently placed online. We have seen multiple instances during the year for completions operations in both WildHorse and Monarch have deferred significant production volumes from relatively new wells. We can potentially avoid this issue when we adjust our planning process to minimize revisiting new production areas for a longer period of time, while maximizing drilling and completion efficiencies with larger pads. I would caution that this is still in the planning stages and is not something we are ready to replicate across our entire footprint, as there are implications such as infrastructure requirements and Reagan completion crew timing. We have consistently tried to be proactive and incorporating leading edge processes and techniques that drive operational efficiency along overall -- with overall well returns. This is just 1 of the initiatives that we think could unearth additional value as we continue to refine our operational techniques.

I would now like to turn the call over to Correne, our CFO, for the financial discussion.

Thanks, Gary. I'll pick up with the financial update on Slide 13. As you can see, we have entered into the fourth quarter with a strong liquidity position of $562 million, which included $62 million of cash balances and almost $500 million of availability under our senior credit facility. We are currently working through our semi-annual fall borrowing base review with our lenders and anticipate increasing our current borrowing base from $650 million to $700 million with this review. As shown here, our cash -- our balance sheet remains well positioned with no near-term maturities and the net debt to third quarter analyzed adjusted EBITDA of 2.2x, which is one of the strongest among our small to mid-cap peers. You will find a detailed hedge schedule in the appendix of our quarterly earnings slide deck on Slide 16 and 17. We remain committed to maintain a level of price protection that will allow us to execute our development program. Therefore throughout the quarter, we have continued to layer on additional hedges to provide cash flow protection, as we work towards our goal of cash flow neutrality within the next 12 to 18 months from the time that we [adopt] this rig. As of yesterday, based upon 2018 consensus estimates, we had just under 55% of our 2018 oil volumes hedged to WTI at a weighted average floor price of roughly $50. We will continue to look for opportunities to layer on additional oil, gas and basis hedges throughout the fourth quarter and into 2019.

Finally on Slide 14. We wanted to highlight our third quarter performance and fourth quarter guidance. The hard work that our employees have contributed throughout 2017 is highlighted in Callon's continued reduction in our lease operating expense. The third quarter was no different, as we've reported LOE of $5.08 per BOE, which represents a 23% reduction since the first quarter of 2017. As a reminder, we report our production volumes on the 2-stream basis and our LOE would be below $5 per BOE on a 3-stream basis, which is reported by many of our peers. This continued focus on cost has allowed Callon to maintain strong adjusted EBITDA margins in the low to mid-70% range on average throughout the past 2 years.

As we look ahead into year-end, we are forecasting fourth quarter production to be 24,000 to 25,500 BOEs per day with 77% of our production coming from oil. This represents a sequential growth of approximately 10% at the midpoint. As a normal course of planning, we do budget for workovers as a part of our LOE; this is reflected in our fourth quarter guidance. You will also see that we have a projected a growth operational CapEx range as well as a net effect that includes our projected monetizations which we expect to occur prior to year-end. Lastly, we wanted to highlight a slight uptick in our wells placed on production during the fourth quarter as compared to the third. And with that I will turn the call back over to Joe.

Thank you, Correne. I think we've covered a lot of ground here. So I think we'll open it up for questions at this point.

(Operator Instructions) The first question will come from Neal Dingmann of SunTrust.

Joe, first question, I had -- you guys certainly -- are you mentioned about the free cash flow and that seems to be topic to sort out there. Could you talk about -- I think you all have mentioned 2019 but how the midstream monetizations might play in there, so I'm trying to get a sense of how material those could be and again how quickly or could that change sort of the path to get to that free cash flow neutrality?

In terms of our goal post on cash flow neutrality, I think we're pretty consistent in terms of how we think about it. Whenever we add a rig, we want to see a path to getting back to cash flow neutral at our plan in case [decks] within sort of 4 to 6 quarters and that's something that will stay true to. The monetizations -- when we see perhaps doing some more of that activity, everyone say it's going to be a needle mover in terms of accelerating us to get to cash flow neutrality any sooner, I think it's really more -- really in line with improving our capital efficiency. We have invested a lot in some small projects on infrastructure that allows to control our own destiny in terms of our pace of development, doing some responsible things on deeper saltwater disposal and recycling, as Gary has talked about. But we're at a point now that once we control a lot of that infrastructure that we can selectively monetize things, but it's really just enhancements to capital efficiency versus a big driver, Neal, of cash flow neutrality in [our minds].

And then just last one maybe for Gary. Gary you mentioned 2 things -- you already mentioned the potential 10 wells section, obviously that would be a big uplift and then bringing those 6 wells online you kind of have various things going on, I'm just wondering maybe addressing that would either 1 of these you had some issues with the offset operations. Just wonder when you look at cadence next year, do you see sort of working around that because of some of these things that you're driving that for 2018?

Well, the 10 wells per section at WildHorse is something that we're very good attached. We've increased density significantly at the Lower Spraberry and Monarch and we think that that has worked very well for us. I think that same opportunity exist at Lower Spraberry -- within the Wolfcamp A at WildHorse and we're anxious to show some of the results as we get those wells online. That would just be a huge uplift to our inventory and through our current asset value. So that's a little different than really the interference with wells, as the industry has increased in activity and there's a network of companies out there working closely to try to advise other companies when they're fracking, when they might be fracking, when we can anticipate frac offsets, but that's always a moving target. So there's always some uncertainty and kind of who's going to be fracking when, but if we go to simultaneous operations and we're very anxious to show what we can do with this -- at really the Casselman at least in Monarch. We did a simultaneous drilling operations when we drill in 2, 3 well pads at the same time and we come in and frac those wells simultaneously with 2 frac fleets at the same time. We think there is significant uplift there because, one, you're fracking to really some original rock all throughout the entire really half the section of development is what it is, it's not a full section of development yet, and so there would be significant opportunity if we build out the infrastructure properly and some of the infrastructure we built out over the last few years that Casselman allows us to do it very quickly at Casselman . Then we can flow these wells back unrestricted. We can get the right production uplift for the investment we're making in an unrestricted manner, because we have good salt water disposal capacity in the area and then we can lock those wells produce for an extended period of time before we come back in and complete the other half section. So we think that's just the right way to go in the maturity of our development and really leveraging the infrastructure that we've already invested in the right manner.

The next question will come from Gabe Daoud of JPMorgan.

Appreciate you still kind of in the process of budgeting for next year, but I was just wondering how we should be thinking about the prior guidepost on capital and production for next year, and if there is an update to those at this point?

We are certainly in the [trailers] of the 2018 budget process and well on our way. So we're certainly not in the position to be talking about specific guidance ranges and such. We want to make sure that putting together right plan, the checks the boxes in all of our objectives that we've outlined, since we're giving you some parameters. I know we've laid out some plans for the course of the year in terms of [illustrative] program starting at Jan 1, 2018; obviously, that's a little bit different now in terms of our assumption. I'd say that the only other thing that we can talk about now that we know it will be factored into our program is a little bit less nonop activity than what we had originally planned for at that time, again nothing material, maybe a couple percent difference there, but I could tell you that we're going to dial that assumption back until we get a little bit more visibility on [people's] plans. But overall directionally to give an update on that, we're still looking at oil growth year-over-year in excess of 40% as a target, and will continue to refine that as we get into January when we will come up with more formal budget.

And then I guess just going on to the services side, you've talked about D&C enhancements and then service cost inflation, given those 2 items, I guess, can you just speak to current (inaudible) look like in both the Delaware and the Midland and then is there an update on use of in-basin sand and at this point?

This is Gary. But in the Midland Basin, we're drilling 7,500 foot laterals in the Wolfcamp A in WildHorse for right around $6 million to $6.5 million and we think that has significant opportunity to move downward with the utilization of local sand. We're in conversation with several companies now including working directly with our pumping service provider, ProPetro on (inaudible) local sand. Certainly, the Midland Basin, we think it'll work very, very well. Hence we're excited about that that new opportunity there seems to be growing by multiple mines being open throughout the year. At Spraberry well right at for 7,500 foot lateral, we're anywhere from right around $8.5 million to $9.2 million. And again, we're not quite anxious to go do local sand in the Delaware Basin yet, but we're certainly going to watch closely as others employ that type of technology in a timely manner, and hopefully it will work out well, because if we could get rid of the uplift to cost on rail that would be very beneficial. And of course, we would also expect that local mines would actually cause (inaudible) to be much more competitive in the future.

The next question will come from Brad Heffern of RBC Capital Markets.

Versus the operations update that you guys put out in September talking about the 20% in efficiency losses, can you talk about where that stands today, maybe relative to that 20% and how confident you continue to be that there's not going to be much spillover into 2018 from those issues?

Yes, I can talk about that, Brad. We measure NPT time on everything we do -- the nonproductive time in everything we do so that we can always find ways to work with all of our service providers on how we go forward and different trends that we see. Hopefully, other companies do the same thing; I'm sure they do. And essentially there's 2 components to NPT time that we see -- there is actually -- there is very 2 distinct components. One is, in the industry, the explosive growth that we've had, we've actually had a lot of lesser experienced personnel show up at our sites. Now some companies integrate those lesser experienced personnel better than others and I'll tell you that ProPetro does a phenomenal job with that. We're very pleased with the way they incorporate new hands and they care deeply about their people, they do it in a safe and efficient manner, and so we're pleased to be partnered with them. But also the biggest challenges we've had, have been around wireline and coil tubing services. And that's where we've seen a large increase in inexperience in the operation and it shows up on some of the most difficult wells. So whenever you're drilling a long lateral and you're completing it and a wireline operator just makes a bit of a mistake and presets a plug, then a coil tubing unit comes out and shows up and then it has its mechanical problems as well simply because of the nature of the industry, a single pad could be compounded and that's essentially what we had in the fourth quarter. It wasn't prevalent throughout. It was a single pad that we had issues on that extended that pad for multiple days. So I don't see this as a big issue, I see it is transitory. I think it's an industry issue in incorporating kind of bringing up the whole industry to a level of experience that we're accustomed to when activity levels were much lower. The second component to the NPT time is complexity of frac. We've actually utilized and when working with, in a way that we think will be beneficial in the future, more complex fracture stimulations. In other words, we're incorporating 1, 2, now 3 stages of diverter material in each stage to the point where it takes longer to frac, it takes longer pump time, it takes higher pressures, and as a result of that, you put more and more wear and tear on the equipment. So there's 2 components to this that had a day or 2 per pad, but I think all that cycle time will be resolved in the near term, very near term. It won't be something that will linger for a long time. But it is somewhat complex, it's something that we can't describe well in a single press release, but at the end of the day, we're working through it.

And then I guess shifting over to the new Ranger Wolfcamp B wells. Nice to see them 20% about the type curve, but can you talk about how that compared with your expectations, I assume that you would have assumed that they would do better given your technology and so on, and then how do those wells compete within the portfolio overall?

We're very happy with these results. We drill these wells because we have some drilling commitments down there in some of this acreage that we acquired in April or May of 2016. And so we're happy with it. There are good returns, but they still are at the lower end of our -- the Wolfcamp B is still at the lower end of our portfolio. Good returns, but still things that we would probably minimize just to manage -- as we've said, manage drilling commitments and hold onto to the acreage. The excitement here is the Wolfcamp C. Everybody is aware of Parsley's well. We've look at our data -- we think our data is and our assets are justice perspective. We're anxious to get that well completed in the near term and get some results. If the Wolfcamp C becomes in the way we expected to anywhere near the Parsley result that they have just over to the north and to the east of our position, this will become a very active area for us.

The next question will come from Irene Haas of Imperial Capital.

My question is to do with the Spur area in the Delaware Basin. Obviously, you're doing very well in the Wolfcamp A and I'm kind of curious why you're going to be testing stack-stagger, and it seems like you have a lot of space there? And then just sort of a longer-term outlook. So you probably not terribly worried about any impact from developing the other zones, such as the Avalon and Wolfcamp B and C later on because of the quite a bit more [cygnus] between these formations, can we have a little color on that? And how come you really -- the transition in the pad drilling is pretty quick, so hope can you also give us a little color on that as well?

You're absolutely right. The Wolfcamp A results are phenomenal. And so why wouldn't we just keep doing that. We love that opportunity set, it's right. And so but importantly the Wolfcamp C, we think, has tremendous upside, and we think understanding that upside sooner than later would be helpful. It may not change our plans in the end, but because there is enough vertical separation, but it may well be helpful because simply the efficient development if we go to more and more to tank or cube type development as we get more and more ramped up to beyond 5 rigs, we want to understand the full vertical capacity and complexity of our entire asset base going forward in order to optimize our future development. So without question, like you said, very happy with the results we have. It'll only be a well or 2. We will again continue to launch offset operators. We've been a very fast follower, we don't intend to be beyond that. But we think some of the technology we bring can actually prove up kind of what we think has tremendous potential for our asset base. It's similar to the Wolfcamp C at Ranger. We love Parsley go out and do several wells. We've tried to work in exchange data and learn as much as we can from offset operators. And now we're out doing it ourselves. So it'll be a similar type thing at Spur. Was there another question there which you asked me, I'm sorry?

The transition into pad drilling this quickly. So you must feel very confident and also you're not terribly worried about interference from the layers above and below?

No, no. We're not. We were very anxious to get the pad drilling. Again, we wanted to get out here, drill a few wells, kind of show kind of what the opportunity set was, what we could then do beyond what we saw other operators doing, kind of spend a little bit of time getting the infrastructure in place. And some of the infrastructure costs that we're going to have to work on in 2018 will primarily be focused on acceleration at Spur, but wanted to kind of [coast] into it but now we are going right to pad drilling after the next well or after the well we're on right now, actually. So we're only overly concerned. I'm sorry…

May I ask a follow-up question, you guys said that you're looking to use in-basin sand towards the Midland Basin, but CDEV, I mean, Centennial is actually using that in Delaware Basin to. So would that be a possibility for you guys as well?

Nice question. We're very closely monitoring what Centennial is doing. Those guys are doing a great job out there. They kind of showing the way on many different fronts. So congratulations to them. But yes, we're very anxious to see additional results. We think early time it will be equivalent and we're a little concerned a little bit about maybe 6 months to a year after the production, embedment and crushing, because of the deeper overburden pressures. Now that's being very conservative on our part, but certainly the results the CDEV is delivering are exceptional. Well done on their part.

The next question will come from Will Green of Stephens.

I wanted to follow-on on that last point on infrastructure. It sounds like you guys have laid a lot of infrastructure work and Slide 7 even kind of implies that you're preparing for '18 with some of this additional capital expenditure this year. You did mention that you still have some additional work to be done in Delaware. Can you comment on just what else needs to be done. It does appear like you guys have done a lot of the heavy lifting on the infrastructure side, just not asking for guidance necessarily, but is 2018 a year where we will still see a significant amount of infrastructure spending need to take place or would you consider kind of this year as being the year where most of took place?

Well, we have more to do especially at Spur. The important thing is, couple of things have just matured, right. We put a lot of infrastructure in place. We enhanced it. Now we're dealing with third party service providers, especially on SWDs that actually help us then get -- that provide more flexibility and more optionality and more capacity for growing capacity and growing rate in all the areas that we've been working on. So where we develop those third party relationships and we're not quite ready to talk about all those yet. We can then share the cost of the infrastructure that we've already built, and that's where the monetization side that's coming. And so we'll continue to do that. And the monetization that we've already done here was really associated with some plants and some gas processing that was done at Spur that we're happy with. But at Spur, we've got to get ready for 2 things, it's really 2 things. It's recycle, because the higher water volumes, we want to be able to utilize that recycled water in responsible way minimize disposal capacity on the site . And so it's all we're doing is drilling a few more water disposal wells for kind of insurance. It's really what it is, because you all are aware of the third-party deal that we did with Goodnight to move water at a very reasonable price off of our site in the Delaware and then it's getting ready for that recycles building 2 pits, interconnecting those pits and then interconnecting our SWDs. That only if for any reason we would ever have any downtime with the Goodnight system, so that we could always have certain be of rate and flow on the field service. So there is more to do. It's necessary -- we think it's necessary, we think it will make us more efficient and provide more optionality. The recycle side, we know we can recycle water cheaper than we can buy it. So that's going to be a huge cost advantage to payout in short order. So it will go to the economics of the wells, but there's more to come. And then any time we go to a new area, we always have to build central tank battery facilities. So there always be a component of central tank batteries. We only have a few left to build in WildHorse and that's just ready for continued development. Any new section that we go to in Casselman, and there are still a few new sections in Casselman we go to then we'll have to build a new central battery and those cost about $3 million each. And but January 2018 will have, I would say, a moderate level of spend for infrastructure, simply because we're still preparing Spur for efficient development.

It does appear that these are yielding some very good results from you guys. LOE was very impressive and I know you guys kind of mentioned that it will uptick because of workovers this next quarter, but are we now in a position where on the OpEx side, we're kind of getting a glimpse as to what the full run rate looks like once you guys have completed a lot of this infrastructure work both on maybe on LOE side and a differential side, are we starting to get a glimpse of what this potentially looks like once you guys are finished with those projects? Is the current quarter kind of a good glimpse of that?

It's couple of things there, Will. I think it gives you a glimpse of what we can continue to do on the back of some of these investments plus some things we haven't even talked about in terms of getting better on the chemical side of the business, and you mentioned workovers. The workovers side of it, it's very difficult to forecast, right. So we're just going to have a running assumption that workovers are going to pop up with some time. So it may or may not show up in a quarter, we put it in every quarter, so that's why we always have a bit of that influencing our guidance from quarter to quarter. But I think overall, we have driven LOE down this year and pretty marked pace and I am going to think we're going to continue to have a trajectory where we can keep making progress on that. So I wouldn't say that this a snapshot and this is where we are. I think there is still some efficiencies we're trying to capture as we move forward, but more to come as you noted the infrastructure investments we're making certainly have an impact, the recycling initiatives that Gary talked about will have an impact going forward, that's the next leg I think for us, but with the operating team we have and adding new people to the team and bringing some new perspectives, I think we're well positioned to keep working that number down.

The next question will be from Jeanine Wai of Citigroup.

Circling back on some of the prior questions, not to beat a dead horse or anything of that, but you are holding to having that 12 to 18-month runway for hitting cash neutrality, and then given the current efficiency or inefficiencies that you're seeing and your commitments about growth with corporate returns and cash flow alignments, how are you thinking about the timing of that sixth rig? And since we're appreciating that there is no guidance out there right now, how is this changed since the last earnings call when you talked about it. For example, is there more of a preference now to showcase doing more at west or is their preference now just not exacerbate [out some]?

From a high level 2018, we're looking at adding a fifth rig, obviously, early in the year as we talked about, so no change to that. In terms of the sixth rig, certainly, it's an option down the road. I think 1 of the factors that we're cognizant of is, just getting started in the Delaware this year, adding a second rig next year. We're getting up the learning curve, and I think we would like to see how efficient we can be with the 2-rig program and probably try to improve our cycle times there before we think about adding a sixth rig and maybe using [what's] doing more with less. We have a lot to work with here. But right now we're not incorporating a sixth rig in our 2018 planning for right now; we do want to see how the 2-rig program in Spur is evolving early next year before we make any decisions around that.

And then in your prepared remarks you walked through your rationale [going for value] next year, which was really helpful, so thanks for that. And this might be somewhat of an unfair question. But do you think Callon would also get rewarded if it instead show something like pretty close to cash flow neutrality in '18. I mean, on numbers you could still get pretty competitive growth next year although '19 might be a different story, but are there other factors such as testing or getting a scale that maybe we're just under appreciating?

It's a fair question, but answer with cash flow neutrality, we have that as a goal post to have visibility to that to make sure we never get too far in outspend situation, but fact to matter is, we deployed a lot of capital in 2016 that we need to earn returns on and bring that those forward. So we have exceptional returns available within our inventory of investments. So we are pulling them forward on a measured basis, so we have been a returns-focused company and I think that the company awards for that. Now we will be responsible on cash flow neutrality, having visibility in the balance sheet, we're in a very strong position there. But in our minds earning returns above our cost of capital is a business that should be rewarded by the market and that's how we're thinking about our plans.

The next question will come from Jeff Grampp of Northland.

Just a couple of quicker operational ones. I guess you mentioned several times here implementing recycled water seemingly in a couple different operational areas, I'm kind of wondering out still early days here, but any kind of ballpark quantification of how that could potentially impact your well costs?

Yes, it could significantly reduce water supply and the water disposal on both sides of that equation. So from a capital perspective as well as an LOE perspectives recycle water could reduce those levels by -- just those 2 components by nearly 50 % in those cost categories, that's a big number. Getting water sourcing from $0.80 down to below $0.40 and getting water disposal from say $0.50 to nothing because you’re recycling it and we're using it. Those are big numbers. We think that has tremendous opportunity that everyone should be doing plus in the Midland Basin we think it's certainly the responsible thing to do. We've been working toward that goal to minimize the use of freshwater for since we started drilling horizontal wells than looking for more blackish water sources as well as the opportunity to recycle in and around Midland itself, the city of Midland. We are now partnered with a couple high capacity third-party SWD wells that we're working very strategically on to be able to recycle that water instead of just disposing that. It will help tremendously for many different functions as we go forward.

And then you mentioned, I think in the slide deck getting some improved times in terms of getting first oil for Lower Spraberry in Howard. Can you guys maybe talk about kind of where things were at previously and kind of where things are on the [newer gen] wells with some of the tweaks you guys have been making there?

Yes. Those wells just started flowing back, so we're early time -- they did come on early oil, but we're not prepared to talk about those wells at this time.

The next question will come from Ron Mills of Johnson Rice.

Guys most have been asked but a quick question on the Wolfcamp C at Ranger. I know Parsley's activity is more around the northern part of your position as is your first well. When you look at your Ranger position, how prevalent do you think the Wolfcamp C can be across that whole position or could it be more localized?

Right now we're looking at it as a bit localized, Ron, but we don't want to limit it and when we're looking at a localized because we've only looked at it around Lonesome Draw and Garrison Draw areas at the present. We think it could expand into Upton County. We think it would be limited going toward Taylor Draw.

And then we need to go back to Spur as Irene asked the quick move to multi-well pad development seems to bode well for that area and also when you talk about the additional zones I think you talked about the Wolfcamp C there, I think you also earlier had mentioned second Bone Springs. What is the lay of the land in terms of offset operator activity in some of those other zones and anything that maybe a focus as you do some testing next year?

We've seen data in both of those zones relatively nearby by mix of public and some private operators that we've shared data with. So can't talk a lot of detail about that, Ron. But there are supporting data points that fit with our view of the subsurface and the work we've done, as you remember we took a whole core samples in that the first Lower Wolfcamp A well and had a pretty good look at things and the team is pretty excited. So as we've done in the past, we want to corroborate that subsurface view with the real well results and we've seen some encouraging results around us in both of those zones. And we expect to see some more data points coming out over the next few months based on our discussions that will help you further refine those views.

And then lastly as you -- at Monarch, as you move to that cube or min-cube type development in '18, it sounds like, Gary, a lot of that is a function of the infrastructure you have in place, you will be able to flow at unconstrained levels. As we think about other assets in your portfolio, do you continue to move or you're getting close on the infrastructure side where if cube development becomes the way to do it, you can transport that in short order across other assets?

We're getting very close at WildHorse on infrastructure, extremely close, and I think we're nearly there. We certainly there for the most part of Monarch and Spur still more to come, but it won't take as long in '18 to get well prepared for more program development there. It'll be a mix of about of one drilling obligations and some of the areas that we have that will drive certain levels of activity as well as where we have options we will go to min cube or full cube type of development as we get further along in our development. But you're right, Ron, it is a matter of being prepared to do that. Some of the challenges that many of the companies are having in Howard is they haven't invested in SWD facilities or infrastructure, so they're bringing on these large cubes and trucking a ton of water to various SWD facilities that are full and the capacity is full. So we think the plan is right. It's just that if they are not properly positioned with infrastructure, it becomes a very inefficient and bring in back the whole investment forward and utilizing or actually leveraging the right level of spend on infrastructure to bring all that additional capital investment for multi-well pad development forward and in efficient way. But it'll be a mix. Again, we now have -- a couple of years ago, we had luxury of having no drilling obligations. We do have some drilling obligations on the expanded footprint. So it'll be a mix as we go forward.

Either Joe or Correne, does that cube move to cube development have any appreciable impact on the ability to any kind of at least achieve that cash flow neutrality within 12 to 18 months given the cycle times?

No, Ron, it's not going to an impact, but I think there's a question earlier around sixth rig and things like that that as we look out in the longer term plans, we'll make sure there is flexibility in the program to handle potentially increased cycle times that are going to be a function of some larger development, but it doesn't move the needle in terms of our near-term objectives as we look at '18 and '19. I think it's just more of a longer term thing that we have to keep in the back of our minds, if that's the right way to go. But this will be a good first half, so I think it's a pretty interesting concept that the team has come up with.

The next question will be from Chris Stevens of KeyBanc.

Just wanted to ask on your level of completions in 2018. You've seen some inefficiencies this year with some of your service cost providers and completed a fewer number of wells than expected. So do you think 2 frac crews is enough to handle the 5-rig program that you set for next year? Are there any plans to maybe bring in a third frac crew for portion of that year to maybe catch up a little bit on the completion schedule?

Chris, we're currently caught up on all of our wells, I mean, we don't have any DUCs waiting. We want to build a bit of a DUC inventory to be a little bit more efficient and a little bit more prep work associated with getting ready for the frac. So yes, 2-frac crew is going to be just fine throughout most of '18. I expect we'll go from 4.5 stages of day to 5 or 5.5 to 6, that efficiency is coming -- just coming throughout the entire industry. So we are well set going forward.

And then I guess with this Wolfcamp A well in the Delaware that you drilled this quarter, the oil cut was I guess above 80% and your type curve, I think, is closer to 70%. Do you think the 80% plus is a good mix going forward out there in the Delaware?

We like to think so. It's a small data set, but it certainly looks to be a fairly high oil cut, lower or [GOR] type development, but I'm not ready to put a stamp on what that number should be, Chris. I'm sorry. Everybody will work and will come back.

The next question will come from Derrick Whitfield of Stifel Financial.

Two quick questions perhaps for Gary. You commented on Wolfcamp A and Lower Spraberry codevelopment at WildHorse earlier in the call. To clarify, are you of the view that they need to be codeveloped based on your current well design or rock mechanics work?

I don't think they need to be. I think it would be helpful if we figured it out sooner than later. The Wolfcamp A is phenomenal. There's no question about it across the entire asset base. We're trying to figure out how best to optimize the value at the Lower Spraberry. Frankly, the Lower Spraberry that we've drilled so far it kind of under-performed our expectations and it's really the ramp that we've been struggling with and we think the [stat] development actually could be interfering with some of that in the way we've enhanced the size and complexity of our Wolfcamp completions and then doing a Lower Spraberry completion right on top of it. So we want to get to this point of offset Lower Spraberry development to see how that works. And ultimately we might get to a point where we're actually developing the reserves in the Lower Spraberry from the Upper Wolfcamp A. So we'll have to see how that materializes. There's still a lot of work to do yet before we fully define that potential, but I don't think they have to be done together to answer your questions.

And then, similar to Daoud's question, do you see Upper and Lower Wolfcamp A needs to be codeveloped at Spur?

We think that would be optimal, we do. We think doing that chevron pattern across that would be the best way to do it. There is no doubt about it, [not in mines].

And then one last, if I could. So could you comment on the current Wolfcamp A design of the Delaware and where you think state-of-art might be based on your early activity in industrial results?

Again, what we did there, we pulled back considerably on the level of sand loading. The first couple of wells, I think, with the Corbets and Wolfcamp A and that was completed by Ameredev. And then the Saratoga was a Wolfcamp B well, which was -- both of those were completed with 2,800 pounds per foot, and we're fairly confident that was way too big, way too much energy infused into the zones simply because we saw the impact in the upper Bone Springs production. That was terrible but both those wells are still very good wells, but we felt that we could pull back on cost, pull back on complexity and actually place the equivalent effective sand volume, pulling back to 2,000 pounds per foot, still 200 for stage length, and using some diverters to make sure we disperse that sand along the wellbore, and we're very pleased with the results of the Sleeping Indian. It seems to worked out just fine. So it should help -- I don't know where the state of the industry is in track complexity and design for the Delaware. I think, it's still all over from lower sand loading to a 100 mesh sand or 100% 100 meshed all the way over to minimal 100 mesh to immediately go to 40-70. So I can't tell you -- we're learning as much as we can from all the offset operators that we're meeting with and we're meeting with anyone who wants to talk to us, and we've met with many of the offset operators already, but I'm happy with the results we're getting and I think we're hopefully with the results we're starting to show and demonstrate, we're contributing to the learning curve for the industry.

And the final question this morning will come from Dan McSpirit of BMO Capital Markets.

Can you speak to cycle times today versus where they were say, earlier this year and what's expected as a company hits its stride, just trying to get a sense of where the company is in getting back on track and maybe better assess the risk of additional slippage to production growth here?

The cycle time continues to improve from where we are a week ago, right, it improves every week and we'll get more and more experience under [about them]. We get all these teams working together as 1 effort, 1 group. But in the first half of the year, our cycle times were anywhere from around probably 5 stages a day and we've already come back to about 4.5 stages a day. So that's not terrible given the level of dilution we've had to our experienced workforce and it's really not terrible whenever you think about the level of complexity that we've actually added to the fracture stimulation, thus making it harder to pump and pumping longer stages and pumping more sand. All that has more and more wear and tear on equipment, and so you would expect that some additional time would come into play. But it's just not terrible, it's 1 or 2 days per pad, is what it is and we'll pull all of that back in very short order. So don't think we're overly concerned about this. This is a natural progression of explosive growth in the industry, especially in a focused area like the Permian Basin.

And ladies and gentlemen, this will conclude our question-and-answer session. I would like to hand the conference back over to Joe Gatto for any closing remarks.

Thank you and appreciate everyone's time on the call and all of the thoughtful questions, and we'll look forward to talking again soon. Thanks.

Thank you, sir. The conference has now concluded. A replay of this event will be available for 1 year on the company's website. Thank you for attending today's presentation. At this time, you may disconnect your lines. And once again, the conference has concluded. You may disconnect your lines.