Callon Petroleum Co (CPE) 2018 Q4 法說會逐字稿

Good day, and welcome to the Callon Petroleum Fourth Quarter 2018 Earnings and Operating Results Conference Call. (Operator Instructions) Please note that this event is being recorded. A replay of this event will be available on the company's website for 1 year.

I would now like to turn the conference over to Mark Brewer, Director of Investor Relations. Please go ahead.

Thank you, operator. Good morning and thank you all for taking time to join our conference call today. With me this morning are Joe Gatto, President and Chief Executive Officer; Dr. Jeff Balmer, Chief Operating Officer; and Jim Ulm, our Chief Financial Officer.

During our prepared remarks, we will 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 and Presentations page located within the Investors 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 Slide 2 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 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 and in our earnings press release, both of which are available on our website.

Following our prepared remarks, we will open the call for Q&A.

And with that, I'd like to turn the call over to Joe Gatto.

Thanks, Mark, and good morning, everyone joining us today. Our full year 2018 earnings results and operations update was posted yesterday after the market close and highlights Callon's strong execution and significant achievements not only in the fourth quarter but throughout the past year. Our team has worked hard over the last 12 months to set the stage for a new phase in our maturity as the company, and I would like to thank all of our employees for their effort and dedication.

Let me start on Slide 3 with a quick review of what we accomplished this past year. Total production came in at the very top of our increased guidance range with a significantly higher oil cut. Equally as important, the consistency of our strong cash margins continued with a peer-leading annual operating margin of $40.16 per BOE for the year. Adjusted EBITDA for the year was $432 million, an increase of 60% from 2017, and exceeded our cash D&C capital by almost $30 million.

You can see that we hit nearly every one of our guidance targets for the full year and ultimately brought online 54 net wells in 2018, including 17 in the fourth quarter. We exceeded our target for wells placed on production in the fourth quarter, providing a solid start to 2019, prior to decreasing to 1 completion crew in late December as we prepared for large-scale development in the Delaware Basin.

Overall, we generated discretionary cash flow per diluted share of $0.52 in the fourth quarter, which was a sequential increase over the third quarter despite a 15% decrease in unhedged realized pricing per BOE.

Turning to Slide 4, we've highlighted the growth in our contiguous asset positions over the last few years, coupled with the measured increase in drilling activity that has driven both production and reserve growth. Based on SEC-realized pricing of approximately $59 per barrel as of December 31, the proved developed value component of our reserve base stood at $2.2 billion after doubling in 2018 alone, primarily from the results of our drilling program, which added almost 40 million net BOE. What's equally important is that we've accomplished this while maintaining our D&C spending below our EBITDA generation, and you can see that in the bottom right-hand corner. We have continued to balance our capital program with our cash flow and production profile to ensure that we weren't simply growing, but maintaining a clear focus on reaching the inflection point of becoming a self-funding entity, which is where we are today.

Moving to Slide 5. You can see a critical factor driving our decreasing outspend and move to free cash flow generation, our cash margins that have consistently been at the top of a broad group of independent E&Ps. While our high oil cut provides a good starting point, our ability to bring down our operating and G&A cost structure has been essential to maintaining an EBITDA margin at approximately 75% through periods of commodity price volatility.

For 2018, our EBITDA margin was $36 per BOE, compared to a proved developed F&D cost of approximately $13.50 per BOE. We've been able to redeploy capital on a very efficient basis, generating profitable production growth and improving our corporate returns over time. We also have near-term opportunities to improve on this cash recycle ratio in support of free cash flow generation, ranging from capital efficiencies from reduced drilling days and completion enhancements to sustainable margin improvements from leveraging our established infrastructure base.

On the next page, several of these points are identified on the property map across both the Midland and Delaware basins. Multiple projects related to water management and recycling are now complete, ensuring reliable operations and contributing to capital and operating cost reductions. We recycled approximately 3 million barrels of water in 2018 and are targeting to double that amount in 2019, with upgrades to our Spur operations that we will be able to recycle 60,000 barrels of water per day by mid-year.

As we have discussed as part of our 2019 plan, following our success with mega-pads in the Midland Basin, we are shifting to larger pads in the Delaware Basin, with activity on both our legacy footprint and acreage that was acquired in 2018. We expect to benefit from meaningful cost savings from the transition, but also realize longer-term benefits from co-development of a resource system across multiple delineated intervals. In addition, we will continue to deploy simultaneous operations of completion crews on some of the larger pads to preserve our rate of cash conversion.

I will also point out that while we are clearly maturing our business model, we have not lost sight of the potential to organically replace inventory throughout our asset base. This select delineation is happening as part of our larger pad designs in 2019 with [tests] of the Middle Spraberry in the Midland Basin and the second Bone Shale in the Delaware Basin in process.

I'll now take you to Slide 7 to provide another perspective of how our business is evolving. We've had tremendous success acquiring high-quality properties that established the foundation of our core areas over the last 10 years. With a current position of 85,000 net acres, our focus now turns to optimization of that footprint, which means identifying opportunities that enhance the value of our current acreage and not looking to add additional operating areas. 2018 was a successful year in that respect, with several smaller transactions and trades that increased working interests and extended laterals. We were also able to acquire mineral rights on our existing leasehold position that will enhance the returns on our 2019 and 2020 drilling programs. And finally, we increased our level of divestitures of noncore assets and are currently pursuing additional monetizations of acreage and infrastructure.

At this point, I'd like to turn the call over to Jeff, who joined us about 3 months ago and has really done a remarkable job getting us ready for 2019 and beyond. Jeff?

Thank you very much, Joe. First off, let me say that I'm really excited to be here as part of the Callon team. We're doing a lot of things really well, and my goal is to continue to push us forward and maximize what our assets and our team is capable of producing.

Our fourth quarter production of over 41,000 BOE per day puts us in strong position to start the year. Our continued efforts to reduce costs are driving improved bottom line returns and our multi-well development concepts are showing that you can maximize both returns and resource simultaneously.

Looking at the 2 charts on Slide 8, you can see that we've made significant strides in reducing our drilling days in the Delaware. The earlier vintage wells in our program were running in the 40-plus-day range, but with our most recent changes to our drilling program and well designs, we're consistently matching our best efforts.

On the completion side of the equation, we've shown tremendous improvement in the efficiency of our operations as we shift from single-well pads to multi-well pads across the asset base. This meaningful change in net lateral feet completed on a daily basis has resulted in our reduction to a single frac crew during the early portion of our 2019 program, while we build our DUC backlog in the Delaware for our larger-pad development projects.

Moving on to Slide 9. Our understanding of the various reservoirs and ability to enhance the productivity across our footprint continues to improve. In both the Midland and Delaware basins, we continue to see strong return profiles that support our capital allocation decisions. The positive rate of change is more readily apparent in the Delaware, where we are now focusing a greater amount of our time and capital. As we progress our multi-interval projects in the Delaware later this year, we expect to gain additional insight about how these various zones geomechanically interact and what that will mean for maximizing long-term resource management and our return profiles.

On Slide 10, we've provided an overview of some of the more recent co-development and multi-well projects we have going on across the asset base. In Monarch, our Kendra-Amanda pad is producing from both the Upper and Lower-Lower Spraberry, along with a stacked Middle Spraberry well. Early results look quite positive in relation to earlier vintage offset pads in the same area. In our Casselman area, which is also in Midland County, our most recent Wolfcamp A and B co-development is tracking right on top of the previous tests in the section. This represents an additional opportunity to further progress our mega-pad development concepts from the Lower Spraberry in this area into a slightly deeper zone with similar economics.

We were quite pleased last year with our success with the Rendezvous pad, which during its first 30 days produced 36,000 barrels of oil on average between the 2 stacked upper and lower Wolfcamp A laterals. Our recent Teewinot wells have blown past that figure, producing an average of over 52,000 barrels of oil in their first 30 days for a combined total of more than 100,000 barrels in the first month of production. You can see from results like these why we are very excited about the potential from our Delaware Basin position.

Focusing now on our operational program for 2019, we're increasing our capital efficiency through longer laterals and lower cost development across the whole of our acreage. We expect to increase production over 20% at the midpoint of our guidance despite only running a single completion crew for nearly half the year. We do expect to see some downtime at Spur early in the year to handle some field optimization issues that require shutting in a number of tank batteries. The early portion of our capital program is shifted towards the Midland Basin, and then we'll begin completing and bringing on production in the Delaware during the second half of the year.

Much of this year's program focuses on proper resource capture and mitigation of longer-term parent-child impacts. In addition, we tried to be thoughtful about applying proper risk profiles for these larger developments to account for the potential of longer flowback times, offset frac impacts and other normal operational issues that can arise when shifting to larger multi-well projects in a new asset area. The backend-loaded nature of this program sets us up extremely well for 2020, as you can see in the lower chart.

As we hit our stride with the new development program, we forecast 2020 production growth in the 15% range with an operational capital spend below 2018 levels. We also expect to generate free cash flow for the year under an assumption of $52.50 per barrel WTI.

On Slide 12, we have provided a clear example of how the shift in our program is driving higher levels of capital efficiency. The 13% drop in operational capital actually results in more net lateral feet being placed on production in 2019 than we saw in 2018, despite a drop in the net number of wells. The combined effect produces an improvement of 22% in the amount of net lateral feet per $1 million of operational capital deployed.

An overview of the manner in which we continue to align our spending with our cash flow generation is featured on Slide 13. The shift to longer laterals coupled with larger pad designs is helping us generate adjusted EBITDA above our project drilling and completion capital costs. The equation is further improved as we are now able to focus less on HBP obligations and have significantly reduced the necessary infrastructure capital that was prevalent over the past 2 years.

And with that, I'd like to hand the call over to Jim.

Thank you, Jeff. It's great to have you on board with us here at Callon.

Turning to Slide 14. We have continued to maintain a strong liquidity position and have ample capital to pursue our current development program as our borrowing base was increased this past year to $1.1 billion. Our earliest debt maturity remains in 2023, and as Joe mentioned earlier, we will continue to focus on the generation of free cash flow as we move into 2020, complemented by selective asset rationalization. We remain confident that as our 2019 activity progresses, we will begin to see our debt metrics trend back towards our longer-term targets and ultimately remain under our desired threshold of 2x on a net debt to adjusted EBITDA(X) basis.

On Slide 15 you can see that our risk management and marketing arrangements continue to support the strong margins that our investors are used to and we will continue to enter into thoughtful hedge positions that enable us to both protect our cash flow and capture upside where possible. As part of this program, we have already begun to layer in 2020 hedges and will be looking at additional positions that coincide with new diversified pricing points.

Our 15,000 barrels per day that we expect to begin delivering into the Gray Oak pipeline later this year will receive a combination of MEH and waterborne pricing. In addition, we have entered into a separate firm sales and transport agreement that covers another 10,000 gross barrels per day starting January 1 of 2020. This agreement also will receive waterborne pricing for all barrels delivered.

We continue to actively look at other marketing and transport arrangements that appear beneficial from a pricing, term and risk mitigation perspective, and we will continue to actively manage our production portfolio using these various options.

With that, I would like to turn the call back over to Joe for the final slide.

Thanks, Jim. Slide 16 summarizes our guidance for 2019 and highlights a moderating growth profile and capital spend relative to 2018. It also shows a meaningful increase in net lateral feet placed on production in the second half of 2019. There's more than just a timing consideration for modeling of production; it represents a meaningful progression of our Delaware development program with important implications for sustainable capital efficiency and growth for many years to come.

Before I turn the call over for questions, I'll highlight a couple of points that we believe will differentiate Callon in a changing landscape, in addition to the asset quality that we've demonstrated over the years. Leading cash margins to drive incremental returns on capital as we move to a self-funding development model; a footprint of controlled infrastructure and water recycling that both preserves our margins and stays true to our commitment as responsible operators; and a long-term focus on developing our multizone resource base, balancing our near-term cash return profile with maintaining a deep inventory of high-quality projects for reinvestment into a sustainable business model. As we like to say, short-term drilling decisions have longer-term value implications, and we will continue to approach full field development of our asset base with this mindset.

That concludes our prepared remarks. And operator, could you please open the line for questions?

(Operator Instructions) Our first question comes from Neal Dingmann with SunTrust.

First of all, Jeff, congratulations on joining the great team. My first question is for Joe or Jeff. Around the PDP decline that you comment on Slide 11, how would this change, when you think about if your plans accelerated or slowed -- I'm just wondering, when you think about that wedge piece, could you talk about how you sort of envision the PDP decline, or maybe this won't change at all?

I'll maybe start off on that and turn it over to Jeff, but I guess directionally, Neal, I guess you're talking about, if we're starting here in 2019 and rolling forward to 2020, what would happen to your PDP decline rate depending if you accelerate or decelerate? I guess directionally, with drilling more wells and ramping up quickly in a year, that next year, when you roll into that PDP, you'd have a higher decline rate at the next first year. So directionally, that would be the case. I guess with our decline rate, as we've posted out there in the high 30s for 2019, first year decline, I think it's on the lower end of some of the declines that I've seen, certainly, and I think that's a reflection of how we've been measured in terms of developing the asset base, right? We didn't ramp up rates commensurate with -- we expanded our acreage position quite a bit, but it's not like we doubled our acreage or we doubled our rig count. We've been very measured. So I think that's reflective in that 2019, and you also see an improvement into 2020 with the plan that we've put together, again, as the asset base matures. But Jeff, I think, would like to comment. In addition to just the cadence of wells and how that impacts the PDP decline, there's some other things that we're doing operationally from production optimization to help with that as well. I think Jeff, you want to spend some time on that?

Absolutely, thank you. The PDP decline, as it stands, the wells that are already on production, we're consistently looking for operational efficiencies across the board on the way we can arrest that decline and make it flatten out a little bit. So some of the operational efficiencies that we look for are things like de-bottlenecking facilities, looking for opportunities to right-size our equipment. One of the big standards for us to focus upon is optimizing our lifting parameters. So if we have ESPs, are they correct-sized? We try to work with our vendors to make sure that we get appropriate run time, so can we extend the life that our pumps and our gas lift systems, et cetera, our tubulars, are in the wells, and if you can continue to improve your run time by decreasing some of your failure rates, you'll naturally arrest some of the overall decline within the PDP system.

And my second part, guys, is just wondering, on Slide 10 of the prior presentation, could you just talk about spacing of the 4 areas? I know some guys have up-spaced, but how you just think about spacing the areas? Thank you.

Yes, I'll -- again, I'll start off and turn it over to Jeff. We are -- I think the slide you're referring to with the orange delineated locations, we do have areas that have up to 10 locations in a single flow unit, particularly WildHorse, I guess Wolfcamp A. And we're obviously very thoughtful and measured, as we've talked about over the last few years, of how we step into increase spacing on each of these zones and the results that we've shown, I think, show that we're hanging in line, or sometimes even better, as completion designs advance with some of the -- more of the down-spacing types of tests. So we don't look at it as an NPV acceleration type of concept here, because there's a cost to attain NPV acceleration. So when we look at NPVs, we like to divide that NPV number by the investment on Day 1 to attain that. So you have to burden those NPVs and not just look to accelerate rate that way. So again, we're going to do the right thing over time. If we do see that we're benefited by modifying our spacing, we will, but certainly in the areas that we've delineated right now, with the pad results we've had in the Midland Basin, I think, shows that we feel pretty comfortable that that's the right spacing and not just an acceleration game. But Jeff, I'll let you add to that.

Yes, that's a great way to summarize it. The -- as you can see from the slide that you're referring to, there is some variability in it depending upon the reservoir, the target. And then of course there's a lot of focus that the industry as a whole, and of course we here at Callon, are putting into parent-child relationships and those types of things, so the spacing will also be a function of the target, the reservoir, and then also very importantly, the number of existing wells that are in place already, where their location is, not just horizontally but vertically also. And then the other component that needs to be taken into account is the vintage of the wells. So when the existing wells were drilled. And so all those items will have an effect on the overall spacing that we put in play.

Our next question comes from Brad Heffern with RBC Capital Markets.

Joe, in the prepared comments, you talked about continuing the asset rationalization program. I was wondering if that's sort of a similar scale to 2018 where you divested the 3,500 net acres, or could that potentially include something larger like maybe divesting Ranger?

Yes, Brad, I think that it takes various shapes and forms. We've identified acreage both on the Midland Basin side as well as the Delaware Basin. So you highlighted potential opportunity on the southern Midland Basin side where we haven't been as active, and we always look for opportunities to monetize drilling inventories at the back of our inventory, whether it's larger scale or pieces of some of our southern Midland Basin assets. But in the Delaware Basin, there is an opportunity set north of 5,000 net acres, let's say, that we've identified today that could encompass nonop positions that we don't control our own destiny on, so probably better in someone else's hands. There's things that we can trade out of, as well as really good pieces of acreage that might be a single section that we don't see an opportunity to build into something that we can get efficient on, whether, again, trades or outright monetization. So from an acreage standpoint, we think there's a pretty large group, and again, they don't have to be all en bloc. They could be pieces. And we have a team, as you saw on that slide, that have done a lot of transactions. We've put the summary numbers there, but there's a lot of transactions behind those numbers. So we're working hard on a lot of fronts. We recognize that the A&D market's a little bit challenged, but for good assets, there's still an opportunity to get things done.

Okay. And then I guess on the Spur reliability project, the assets that you acquired have that $9.5 million in LOE. Is there any indication you can give as to what that could go to post the project? And then is there an associated production benefit with that?

Absolutely. The goal is to make everybody equal. So the operational parameters that we're going to apply to the -- and of course, being new, I see it all as the same. So the Cimarex assets are a fantastic quality, and we're very, very happy to have them. The -- we strive for consistency in the operational parameters, from whether it's the facilities or how we approach them. That can also assist our operators to be -- to operate in a more safe manner as well as being efficient because we kind of tried to see the same things on a regular daily basis. So the expectation is to apply the normal diligence on the assets, get them lined up to where they're consistent with the structure and parameters that we have in place already, and eventually have the same lifting cost outputs within those assets as we do across the board everywhere else.

Our next question comes from Gabe Daoud with Cowen.

Maybe just starting with guidance for '19, could you give us more color on how you're risking volume, I guess, any differently than in years past, to account for an increase in multizone co-development, and perhaps even more abandoned wells in the program this year. Just trying to get a sense of whether it's a greater risking on the productivity side, or just kind of like you hit in prepared remarks, a longer time to peak rate or anything like that.

Yes, Gabe, I think you hit that right on the head in terms of what Jeff had hit in the remarks in terms risking around timing and things like that. We want to add a little bit of cushion there with some of the larger-scale projects. We've been executing them, obviously, in the Midland Basin, but doing the Delaware might be a little bit different, so to give us a little bit of cushion there, but from a productivity standpoint, no. It's really around what Jeff had highlighted up front.

Thanks, Joe. And then I guess just a follow-up. As we think about 2020, you gave high-level thoughts on operational capital, but could you just give us a sense of how much, if at all, activity, whether it's crews or rigs, increases year-over-year from '19 to hit that growth number? And then maybe just a clarification on the free cash flow point. Is that free cash generation on the full year, or do you expect to hit a free cash flow inflection at some point within 2020?

Yes, so in terms of activity, again, from a directional standpoint, about 15% production growth, and that was associated with the operational capital program that would be below 2018. Obviously 2018 is a little bit higher than where we are this year, about in the single, double digits. So the 2020 contemplates a slight increase in completion activity, but not a big one, obviously, if we're staying below 2018 D&C capital.

Thanks, Joe. And then just the free cash clarification?

And then on the free cash -- yes, that's for -- that would be for the year. If we looked at the year, there'd be free cash flow generation at $52.50 WTI. You also have to -- there is a component, not huge, but just to make sure as people are thinking about where we're evolving from a pricing point standpoint, has -- assumptions around where Brent pricing -- we have a $10 differential that we're assuming in 2020. So the things that are waterborne or Brent or MEH, they're going to have a little bit more of an uplift versus Midland that go into that. But we are assuming $52.50, and we'd see some modest free cash flow generation for the entire year.

Our next question comes from Asit Sen with Bank of America Merrill Lynch.

I have a quick one for Jeff and then one for Joe. So Jeff, on Slide 5, on future cost improvement, the last bullet, preferred vendor concession consolidation, what is that? And in your CapEx guidance for '19, what are you assuming in terms of inflation?

Sure. The preferred vendor concession consolidation is really just a fancy way of saying that the folks that we use as vendors, we treat them as partners. And because of that, we've been able to have extremely good performance both on the drilling and completion side of the equation as well as, of course, on the production. But the easier items to see, as we've demonstrated in this presentation, are the improvements on the drilling and completion side. So we're able to simultaneously have operational efficiency improvements, so drilling days, more fracs per day, et cetera, as well as strong price agreements with those that overall work towards our bottom line. The . . .

Are the performance clauses in there?

Let's just say that the best way to do it is, the better they perform, it's a win-win situation. So if that's a good enough answer, hopefully that'll give you the right direction.

Got you. And on inflation assumption?

So right now we are not anticipating any significant inflation. Certainly not across the board. There could be some small items that pop up, over steel tariffs, et cetera, those types of things. But generally speaking, we don't see that happening in 2019.

Thanks, Jeff. And Joe, you had a nice little acreage sale in 4Q and you talked about asset rationalization as it relates to noncore location, but just wondering if you have any updated thoughts on extracting value from your infrastructure?

Yes. We've certainly built out a substantial infrastructure base. We talk a lot about water, but certainly things around substations and things like that that we've done to -- and we did it to again control our own destiny out here, and with all the bottlenecks, not only is there a reliability issue, certainly with moving water, but there's a cost, an environmental impact that goes with that. And over the last couple years, we've done a phenomenal job being proactive on that front, so that coupled with moving to more recycling coupled with some strategic relationships we've built with third-party vendors, we are in a position that we can look at extracting value from certainly the water piece of the business. I think what's first and foremost is we can't compromise what we set out to initially accomplish, was to make sure we have operational reliability and water's getting put away in a responsible manner. So that's really the threshold we have to cross before we entertain any of that, but we are looking at that -- those opportunities to monetize, whether it be outright assets or monetize the capacity that we're not using, again, as long as it doesn't compromise our operational model.

Our next question comes from Derrick Whitfield with Stifel.

In thinking about your capital flexibility chart in the bottom right of Page 13, to what degree do your HBP obligations and the facilities spend improve in 2020?

Well, we -- the HBP flexibility will continue to improve on that trajectory. I don't have the exact number here, but it'll continue to come down. We've gotten through the vast majority of the drilling obligations, so the acquisitions that happened since 2016 and our latest acquisition in the Delaware really only came with a handful, just given it has a lot of legacy production that was mature there. In terms of facilities, this year we are taking full advantage of the facilities that we've put in place. I think it's something like 80% of our wells are going to existing facilities. And we will continue to target those types of levels. 15% is a good number, but not the one that we're -- the end goal. I think we're going to try to keep driving that down, but in that 10% to 15% range I think is where -- is a good number for us to target with the team.

Very helpful. And then as my follow-up, I'd like to clarify earlier questions on spacing and parent-child impacts. Your productivity plots on Page 9 are quite impressive. Other than the slight timing differences in flowback of larger pads, would it be fair to think productivity in 2019 should be largely comparable to 2018?

I'm sorry, could you repeat the question? I think what you're asking is, do we expect 2019 performance to be kind of at or as good or better than the vintage 2018 recent wells?

That's correct. I mean, you had noted earlier in the call that you're accounting for longer flowback times for larger pads. Just wanted to clarify that productivity-wise, it would be fair to think that you can attain in 2019 what you attained in 2018.

That is absolutely the goal.

Our next question comes from Ron Mills with Johnson Rice.

Just a quick follow-up on the slide that Derrick just mentioned. The improvement in both the Delaware and Midland in the fourth quarter wells that came online, was there -- what were the primary drivers behind the 25% improvement in the Delaware and the 15% in the Midland versus the wells placed online in the earlier part of 2018?

The primary difference in the Delaware could be really attributed to some areas that had extremely good geology that we took advantage by putting in a little bit more of an adapted completion design, got after it a little bit harder. And they are some of the best wells in the entire basin, and they're noted here, I think, individually, the 2 Teewinot wells that we've got. Yes. The Midland wells is kind of a larger-scale story that has had a number of different pads that are contributing to that performance, so overall, again, I think it's the combination of applying the correct completion design with the correct spacing and stacking and timing relative to the vintage of the existing wells, and all of those components roll into the performance that we're seeing here.

Okay, great. And then, moving over to Slide 10, you highlight some recent wells in terms of co-development from the multi-well pads. When you think about your -- the move to, for lack of a better term, cubes-type site development, how should we think about it in terms of number of formations that you plan to co-develop at one time, and number of wells? Trying to just think about the lag between capital spending and the production additions from those larger pads. Thanks.

Sure. That -- I'll refer back to the inventory slide that -- on a prior presentation that indicates some of the options that are both delineated zones and the ones that we're going to be testing. The optimal way to develop the resource would be what we're doing right now, which is co-development, proper spacing and stacking, and relatively simultaneous. So for instance, the -- on Page 10, the top right-hand corner, that graph has 6 wells that are designated by the blue and the orange colors, which have a Middle Spraberry well, 2 Upper-Lower Spraberry wells and 3 Lower-Lower Spraberry wells co-developed within a package. So those are the types of things, I think, that you'll see Callon focusing upon. We did it in 2018 and now we're extending that into 2019.

Our next question comes from Tim Rezvan with Oppenheimer.

My first question related to Slide 12. It's some pretty impressive kind of efficiencies you look to be gaining. And I guess when we compare that with 2019 guidance on the expense side and the CapEx side, part of the bear case on Callon relates to capital intensity, and I'm curious kind of how investors can expect to sort of see these efficiencies flow through the financials. Is this strictly on kind of a CapEx side, or how do you think about these efficiencies driving kind of half-cycle costs lower?

Hey, Tim, this is Mark Brewer. I'll jump in here and tell you, I mean, we get that there's -- tends to be a little bit of confusion because of the way we provide our capital guidance, but specifically, when you're looking at comparable terms against other companies, we look at operational capital. That is tracking the capitalized interest expense, which doesn't show up in the income statement the way we're treating it. So when you look at that year-over-year, there's a measurable step down in operational capital for an increase in the net lateral feet based on line. I don't know that there's a better way to show improving capital intensity trends than to say that you're spending less to get more. So that's, I think, what we tried to get at with this slide.

Okay. And I guess, rolling forward, you'd expect that to manifest itself in kind of F&D? Is that how you're thinking about that?

Correct. That's the exact way that you would expect to see it show up.

Okay, just wanted -- appreciate that. And then if I could follow up, you talked about downtime at Spur in the early part of the year. I was wondering if you could talk a little more about -- you mentioned shutting in tank batteries. Kind of what you're doing there and obviously, I guess, the goal is to optimize the facilities, but what's driving you to do that now, and kind of how you see that impacting medium-term growth?

Sure. It shouldn't impact the medium- or longer-term growth. It's just normal due diligence. We're looking at gas compression and optimizing that, right-sizing our compression, some of the lines that we have in the ground need to be modified, and again, the idea is to get those -- all those facilities kind of standardized is a good way to think about it, to make our overall operator competency increased and reduce the downtime within that area.

Okay. Is it more related to the Cimarex acquisition or just sort of a broad-brush approach to optimization?

It's a little bit of both. Certainly any time you bring some new assets in, it's like opening a great Christmas present and you're taking a look at what you have and bringing it into the fold. So it's just due diligence.

Our next question comes from William Thompson with Barclays.

I just want to follow up on the PDP declines. First, thank you for disclosing those; those are actually really helpful to reconcile our models. You guys have previously characterized the Cimarex acquisition as mature production, so I just would imagine that helps, and I think it was Gary, I think, last quarter, said something quite interesting, that given the fluid handling dynamics and early flowback control on longer laterals, the wells are really seen as much uplift in the early part of the production but are benefitting from shallower decline curves. I'm just -- how do -- I'm just wanting to understand how that's -- the influence that's having on your lower base declines than maybe some of your peers.

A portion of that can be affected by what type of lifting system that you have in place, and then if you have any surface constraints on water handling or any items like that. Generally speaking, the performance of the Delaware has been extremely good, and we gave a handful of wells, some of the individual well performances. I don't anticipate there being any type of substantial change in the declines that we're seeing right now, as Joe had mentioned, versus what we're going to see going forward with the program that we have in place.

Okay. And then just as my follow-up, in terms of thinking about high-level 2020 in terms of [trimming] cash return priorities given where the debt level is, just maybe, can you comment on where you guys' heads are now in terms of what you're thinking about for 2020?

Well, I think it -- this is Jim. It is important, as we've described numerous times in the call, as we progress towards free cash flow in 2020. And I think what we would say at this point is that we'll carefully consider all of the options. I believe that reducing the leverage will be an early and important priority, but again, as we become -- free cash flow basis, as we start to head out to 2020, we'll think about other options as well. But right now, clearly, the focus is, as we said, getting leverage back down under the 2x, which is our longer-term goal.

Our next question comes from Brian Downey with Citi.

On Slide 8, as you note, not only does the reduced number of drilling days and efficiencies there look impressive but so does that -- the consistency of drilling times. Can you dive in a little more and maybe give some color on -- a little more color on what you're doing differently that's driving that consistency?

Sure. Thanks very much for that question. The way that we are approaching our operations across the board is -- can kind of be described in a limiter theory where we are breaking down each individual component of how we spend our time, whether it's on the rig, doing production optimization work or looking at improving our pump time on the completion side. So one of the focus areas for us this past year or couple of months was on -- during the lateral in the Delaware, and we had a good application of technology as well as kind of the common sense approach to seeing where we were losing time, and then determined some solutions and put those in place, a little bit through trial and error but a lot more through the technological applications, that we were able to consistently reduce some of that downtime and tripping the bottom-hole assembly out. And any time that you reduce your failures within that system, you're going to start reducing hours and then eventually days.

Got it, that's helpful. And then as a follow-up on the prior water question, just given the added water recycling capability and capacity, could you give any color on potentially -- or quantify how we should think about that impacting either capital or LOE spending on a go-forward basis?

We generally can -- every barrel of water than you can recycle and reuse, depending upon where you are, in what area, you've got to be north of $0.50. Between $0.50 and $1 on the savings for every barrel.

Our next question comes from Phillips Johnston with Capital One.

Joe, just a clarification on the 2020 outlook. It sounds like you said it assumes the net PoP count increases slightly from the 47 to 49 net wells planned for this year, but on the rig program, and apologies if I missed this, but would you expect it to stay pretty flattish at 4 coming out of '19, or would you expect the rig count to tick up to closer to a 5-rig average next year?

Yes, I think it's more the latter on an average, 5-rig program.

Okay, and . . .

Which is actually a -- Phillips, that's actually in line with this year's program. As you remember, we're at 6 now. We'll step down to 4 in the second half of the year. So it's actually fairly consistent. There's just some timing issues around trying to get these larger pads prepped for completion.

Yes, okay. Got it. And Mark, just a follow-up, I guess, to your early comments on capitalized expenses in the CapEx guidance, it seems like we often see some investor confusion around your CapEx and how the capitalized expenses can sometimes create apples-to-oranges comps versus consensus. My question is, what's the rationale for an onshore, short-cycle company like Callon to capitalize any interest or G&A? And is there any consideration for changing the accounting methodology to where it's more simple and conservative?

I'll defer to our CFO and resident accounting expert Jim Ulm for that.

Thank you, Mark. I would say that the theory behind why you capitalize G&A and interest is really to match the fact that you have a long-life inventory and many of the activities and efforts that you're doing today will have benefits in the future. Clearly, as we grow and evolve the company and get bigger, that'll be something that we'll think about over time. I don't have anything different to say about it today, but it's something that we will consider this year.

Our next question comes from Kashy Harrison with Simmons Energy.

So just wanted to -- one quick one from me. Jeff, given your history in the Permian, you probably have more visibility into full-field development than most. Just based on the data that you've seen over the last several years, how do you think we should think about the longer-term oil performance, let's call it 18 to 24 months, of larger packages relative to smaller-package, parent-type wells on a lateral adjusted basis?

Thanks very much for the question. The best way to think about that is probably using Callon as an example, and I know I'm biased when I say that, but generally speaking, developing the sequences together both laterally as well as vertically, generally speaking, that's the best option. Coming back in and doing in-fill drilling can be problematic. It's not that it's unsuccessful, but generally speaking, the timing aspect of it is critically important also. Callon has done an extraordinary job even in the last year of looking at the land picture also and trying to put together a position where the longer laterals are achievable, so moving from 5,000-foot to 7,500 or 10,000 feet. That helps your overall capital efficiency because your cost per lateral foot goes down substantially as you continue to make longer laterals. And then if you can put the right lifting systems in place after successful completion design, generally speaking, that's the best way to develop the reservoir.

Our next call comes from Gail Nicholson with Stephens.

With the field optimization project and the water infrastructure upgrades that you guys are doing this year, can you talk about the trajectory of LOE per BOE at the end of '19 versus the beginning of the year? And how would you conceptualize LOE in 2020 forward?

The goal, of course, is always to have our lifting costs drop, and so the game plan in 2019 will be to incorporate some of the items that we have covered in the call already and then have that start to decrease throughout the rest -- the remainder of 2019. And did you also ask about 2020, or kind of future operating expenses? My apologies. I couldn't hear the back end of the question.

Yes, as well as 2020. Just -- I'm assuming that LOE should be down year-over-year, but I'm just trying to understand the -- a percentage standpoint.

I don't have a solid answer for that other than I'm in agreement with you that my job is to make sure that our operating expenses decrease over time.

Okay, great. And then you picked up the mineral rights on about 1,600 net mineral acres. Is that something that you guys would like to do more of or was that just a one-off?

Well, it's obviously a market that gets a lot of attention. There's a lot of capital chasing that, a lot of private equity certainly. So we like to get targeted in terms of where we're buying minerals, so it's going to be underneath our leases, so we have sort of that asymmetry of information because we know what our drilling plans and have a pretty good sense of what the value proposition is, and we'll stay focused on those opportunities. So that won't be the last one that you see, and we see an opportunity set across our entire acreage position to keep doing that. So you'll probably see a little bit more over time as we look at ways to really enhance our return profile by picking up a couple percentage points on NRI. It really makes a difference.

This now concludes the question-and-answer session as well as the conference call. Thank you for attending today's presentation. A replay of this event will be available for 1 year on the company's website. Thank you again, and you may now disconnect.