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Callon Petroleum Co (Delaware)  (NYSE:CPE)
Q4 2018 Earnings Conference Call
Feb. 27, 2019, 9:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

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

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

Mark Brewer -- Director, Investor Relations

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'll be referencing the earnings results presentation we posted yesterday afternoon to our website, so I encourage everyone to download the presentation if you haven't already. You could 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'd like to remind everyone to review our cautionary statements and important disclosures included on slide two of today's presentation. We'll 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 this slide and in our periodic SEC filings.

We'll also refer to some non-GAAP financial measures today, which we believe helped 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.

Joseph C. Gatto -- President, Chief Executive Officer and Director

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 of the company and I would like to thank all of our employees for their efforts and dedication.

Let me start on slide three 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 is 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 one completion crew in late December as we prepare for a 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 un-hedged realized pricing per Boe.

Turning to slide four, we've highlighted the growth in our contiguous asset positions over the last few years, coupled with a 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. With 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've continue 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 five, 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 higher 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 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 midyear.

As we've 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'll 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. The select delineation is happening as part of our larger pad designs of 2019, with test of the middle Spraberry and Midland Basin, and the second Bone shale in the Delaware Basin in process.

I'll now take you to slide seven 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 the 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 interest 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 non-core 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 three months ago and has really done a remarkable job getting us ready for 2019 and beyond. Jeff?

Jeff Balmer -- Senior Vice President and Chief Operating Officer

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, our multi-well development concepts are showing that you can maximize both returns and resource simultaneously.

Looking at the two charts on slide eight, 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 40 plus day range but with our most recent changes to our drilling program and well designs were 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 the 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 larger pad development projects.

Moving on to slide nine. 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 in our return profiles.

On slide 10, we've provided an overview of some of the more recent co-development in multi-well projects we have going on across the asset base. In Monarch, our Kendra-Amanda pad is producing from both upper and Lower Spraberry along with the stack to Middle Spraberry well. Early results are quite positive in relation to earlier vintage offset pads in the same area. In our CASM mine (ph) area, which is also in Midland County, our most recent Wolfcamp A and B co-development just 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 at the Rendezvous pad with during its first 30 days produced 36,000 barrels of oil on average between the two 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 the first 30 days for 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 are increasing our capital efficiency to 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 of 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 has shifted toward 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 try 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 back-end 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 million of operational capital deployed.

In 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. 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 two years.

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

James P. Ulm -- Senior Vice President and Chief Financial Officer

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 toward our longer-term targets and ultimately remain under our desired threshold of two times on a net debt to adjusted EBITDAX 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 we'll 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 Grey 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 to 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.

Joseph C. Gatto -- President, Chief Executive Officer and Director

Thanks, Jim. Slide 16 summarizes our guidance for 2019 and highlight some 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 as 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 and are 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 a responsible Operator. In a long-term focus on developing our multi-zone 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?

Questions and Answers:

Operator

We will now begin the question-and-answer session. (Operator Instructions). Our first question comes from Neal Dingmann with SunTrust. Please go ahead.

Neal Dingmann -- SunTrust -- Analyst

Good morning, guys. And 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 accelerate 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?

Joseph C. Gatto -- President, Chief Executive Officer and Director

Neal, I'll maybe start off on that and turn it over to Jeff. But I guess directionally, Neal, I guess, you talk about it, for starting here in 2019 going 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 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. So Neal, 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 rigs commensurate with, we expanded our acreage position, quite a bit, but it's not likely doubled our acreage, 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, we'd like to comment in addition to just the cadence of wells and how that impacts the PDP decline, there're some other things that we're doing operationally from production optimization to help with that as well. And Jeff, if you want to spend some time on that?

Jeff Balmer -- Senior Vice President and Chief Operating Officer

Absolutely. Thank you, Joe. 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 flattened out a little bit. So some of the operational efficiencies that we look for or things like debottlenecking facilities, looking for opportunities to right size our equipments. 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 tried to work with our vendors to make sure that we get appropriate run times. So can we extend the life, that our pumps and our gas systems, et cetera, are tubulars are in the wells and if you can continue to improve your runtime by decreasing some of your failure rates, you'll naturally arrest, some of the overall decline within the PDP system.

Neal Dingmann -- SunTrust -- Analyst

And my second part guys, is just one on slide 10 prior presentation. Could you just talk about spacing of the four areas, I know, some guys have up spaced but how you just think about space in the areas? Thank you.

Joseph C. Gatto -- President, Chief Executive Officer and Director

Yes, again I'll start off and turn over to Jeff. We are -- I think, the slide you're referring to, is 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 increased 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 the downspacing 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 NPV's, we like to divide that NPV number by the investment on day one 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 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. Jeff, I'll let you add to that.

Jeff Balmer -- Senior Vice President and Chief Operating Officer

Yes, that's a great way to summarize it. As you can see from the slide -- that, that you're referring to, that there is some variability in it depending upon the reservoir of 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 in 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 place.

Neal Dingmann -- SunTrust -- Analyst

Thanks, guys. Great details.

Joseph C. Gatto -- President, Chief Executive Officer and Director

Thanks, Neal.

Operator

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

Brad Heffern -- RBC Capital Markets -- Analyst

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

Joseph C. Gatto -- President, Chief Executive Officer and Director

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 at 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 non-op physicians that we don't control our own destiny on. So probably better in someone else's hands are 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, that whether again trades are outright monetization.

So from an acreage standpoint, we think, there is a pretty large group and again they don't have to be all unblock that could be pieces and we have a team as you saw in 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 A&D markets are a little bit challenged, but for good assets, there's still an opportunity to get things done.

Brad Heffern -- RBC Capital Markets -- Analyst

Okay. And then, I guess, on the Spur reliability projects, the asset 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?

Joseph C. Gatto -- President, Chief Executive Officer and Director

Absolutely, the goal is to make everybody equal. So the operational parameters that we're going to apply to -- and of course, being new, I see dollars the same. So that the Cimarex assets are fantastic quality and we're very, very happy to have them. That 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 more safe manner, as well as, being efficient because we kind of try to see the same things on a regular daily basis. So the expectation is to apply the normal diligence on the assets, and 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.

Brad Heffern -- RBC Capital Markets -- Analyst

Okay, thanks.

Operator

Our next question comes from Gabe Daoud with Cowen. Please go ahead.

Gabe Daoud -- Cowen -- Analyst

Hey, good morning guys. Maybe just starting with guidance for '19. Could you give us more color on how you're risking volumes, I guess, any differently than years past to account for an increase in multi-zone co-development and perhaps even more Run (ph) wells in the program this year. And just trying to get a sense of whether that's a greater risking on the productivity side or just kind of like, you hit in prepared remarks longer time to peak rate or anything like that?

Joseph C. Gatto -- President, Chief Executive Officer and Director

Yes, Gabe, I think you hit that, right on the head in terms of what Jeff have hit in -- in the remarks, in terms of 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, now, it's really around what Jeff had highlighted upfront.

Gabe Daoud -- Cowen -- Analyst

Sure. 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 -- do you expect to hit free cash flow inflection at some point within 2020?

Joseph C. Gatto -- President, Chief Executive Officer and Director

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, a little bit higher than where we are this year. But looking at the single-double digits, so the 2020 contemplates a slight increase in completion activity, but not a -- not a big one, obviously, we're staying below 2018 D&C capital.

Gabe Daoud -- Cowen -- Analyst

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

Joseph C. Gatto -- President, Chief Executive Officer and Director

And then on the free cash. Yes, that's -- that would be for the year. If we look at the year, the deep-free cash flow generation of 50 to 50 WTI also have to, there is a component not huge, but just to make sure people are thinking about, we are 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 to go into that. But we are assuming 50 to 50, we see some modest for cash flow generation, see it for the entire year.

Gabe Daoud -- Cowen -- Analyst

Great, thanks a lot everyone.

Operator

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

Asit Sen -- Bank of America Merrill Lynch -- Analyst

Thanks. Good morning, everyone. I have a quick one for Jeff and then one for Joe. So Jeff on slide five, 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?

Jeff Balmer -- Senior Vice President and Chief Operating Officer

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 toward our bottom line.

Asit Sen -- Bank of America Merrill Lynch -- Analyst

Are there performance clauses in there?

Jeff Balmer -- Senior Vice President and Chief Operating Officer

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

Asit Sen -- Bank of America Merrill Lynch -- Analyst

Gotcha. And on the inflation assumption?

Jeff Balmer -- Senior Vice President and Chief Operating Officer

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.

Asit Sen -- Bank of America Merrill Lynch -- Analyst

Thanks, Jeff. And Joe, you precise nice little equity sale in 4Q and you talked about asset resolution as it relates to non-core location. But just wondering, if you have any updated thoughts on extracting value from your infrastructure?

Joseph C. Gatto -- President, Chief Executive Officer and Director

Yes, we certainly built out substantial infrastructure base, we talk about a lot about water. But certainly things around substations and things like that, that we've done and we did it to again control our own destiny here and with all the bottlenecks not only is a reliability issue certainly with moving water, but there's a cost environmental impact that goes with that. And over the last couple of 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, let's first and foremost as we can't compromise what we set out to initially accomplish was to make sure we have operational reliability and water is getting put away in 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.

Asit Sen -- Bank of America Merrill Lynch -- Analyst

Thanks, guys.

Operator

Our next question comes from Derrick Whitfield with Stifel. Please go ahead.

Derrick Whitfield -- Stifel -- Analyst

Hey, good morning all. Ad congrats on a strong quarter and update.

Joseph C. Gatto -- President, Chief Executive Officer and Director

Thanks, Derrick.

Derrick Whitfield -- Stifel -- Analyst

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

Joseph C. Gatto -- President, Chief Executive Officer and Director

The HBP flexibility will continue to improve on that trajectory. I don't have the exact number here, but it will continue to come down. We've gotten through the vast majority of the drilling obligations of the acquisitions that happened since 2016 and our latest acquisition in the Delaware really only came with a handful. Just given, add to our legacy production that was matured there. In terms of facilities, this year we are taking full advantage of the facilities that we 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 on a 10% to 15% range, I think, is where -- the good number for us to target with the team.

Derrick Whitfield -- Stifel -- Analyst

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 nine are quite impressive. Other than a slight timing differences in flowback of larger pads, would it be fair to think productivity in 2019 should be largely comparable to 2018?

Joseph C. Gatto -- President, Chief Executive Officer and Director

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

Derrick Whitfield -- Stifel -- Analyst

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

Joseph C. Gatto -- President, Chief Executive Officer and Director

That is absolutely the goal.

Derrick Whitfield -- Stifel -- Analyst

Very helpful. Thanks for your comments, guys.

Joseph C. Gatto -- President, Chief Executive Officer and Director

Thanks, Derrick.

Operator

Our next question comes from Ron Mills with Johnson Rice. Please go ahead.

Ronald Mills -- Johnson Rice & Company -- Analyst

Good morning. Just a quick follow-up on the slide, that Derrick just -- just mentioned. The improvement in both the Delaware and Midland in the fourth quarter wells that came online was thee -- 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?

Joseph C. Gatto -- President, Chief Executive Officer and Director

The primary difference in the Delaware could be really attributed to some -- some areas that had extremely good geology. That we took advantage by putting in a little bit more of an adaptive completion design, got after it a little bit harder and they are -- some of the best wells in the entire base and they're noted here, I think, individually the two team in our wells that we've got.

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.

Ronald Mills -- Johnson Rice & Company -- Analyst

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

Joseph C. Gatto -- President, Chief Executive Officer and Director

Sure. That I'll refer back to the inventory slide that on our 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 that on page 10, the top right hand corner that graph has six wells that are designated by the blue and orange colors, which have a Middle Spraberry well; two, upper Lower Spraberry wells; and three, lower Lower Spraberry wells, codeveloped within a package. So those are the types of things I think, that -- that you will see Callon focusing upon. We did it in 2018 and now we're extending that in to 2019.

Ronald Mills -- Johnson Rice & Company -- Analyst

Thank you.

Operator

Our next question comes from Tim Rezvan with Oppenheimer. Please go ahead.

Tim Rezvan -- Oppenheimer -- Analyst

Hi, good morning folks. Thank you for taking my questions. My first question related to slide 12. It's an 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, like put on the bare 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 that 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?

Mark Brewer -- Director, Investor Relations

Hey, John, this is Mark Brewer. I'll jump in here and tell you have been, 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 make it operational capital, that is attracting the capitalized interest expense, which doesn't show up in the income statement, the way we treat it. So when you look at year-over-year, there's a measurable step down in operational capital, for an increase in the net lateral feet based online. I don't know that there is 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 try to get with this slide.

Tim Rezvan -- Oppenheimer -- Analyst

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

Mark Brewer -- Director, Investor Relations

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

Tim Rezvan -- Oppenheimer -- Analyst

Okay, excellent. I appreciate that. And then if I could follow-up, you talked about the 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?

Joseph C. Gatto -- President, Chief Executive Officer and Director

Sure. I'd it shouldn't impact the medium to longer-term growth. It's just normal due diligence. We're looking at gas compression and optimizing that rightsizing our compression. Some of the lines that we have in the ground, need to be modified. And again that the idea is to get those -- all of 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.

Tim Rezvan -- Oppenheimer -- Analyst

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

Joseph C. Gatto -- President, Chief Executive Officer and Director

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

Tim Rezvan -- Oppenheimer -- Analyst

Okay, all right. Thank you for the responses.

Joseph C. Gatto -- President, Chief Executive Officer and Director

Thanks, Tim.

Operator

Our next question comes from William Thompson with Barclays. Please go ahead.

William Thompson -- Barclays -- Analyst

Hey, good morning. I just want to follow up on the PDP decline. First, thank you for disclosing those, those are actually really helpful to reconcile our models. You guys, obviously characterizes Cimarex acquisition of mature production. So I just imagine that helps. I think as Gary, I think last quarter doesn't quite interesting like given the fluid handling dynamics in early flowback control on longer laterals. The wells aren't really seen as much uplift in the early part of production, but are benefiting from shallower decline curves. And just how -- I just want to understand how that's the influence that's having on your lower base declines and maybe some of your peers?

Joseph C. Gatto -- President, Chief Executive Officer and Director

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, that 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 and the decline that we're seeing right now as Joe had mentioned versus what we're going to -- going to see going forward with the program that would have in place.

William Thompson -- Barclays -- Analyst

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

James P. Ulm -- Senior Vice President and Chief Financial Officer

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

William Thompson -- Barclays -- Analyst

Okay. It's a good color. Thank you.

Operator

Our next question comes from Brian Downey with Citi. Please go ahead.

Brian Downey -- Citi -- Analyst

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

Joseph C. Gatto -- President, Chief Executive Officer and Director

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 or looking at improving our pump time on the completion side. So one of the focus areas for us this past year, our couple of months was on -- that the common sense approach to seeing we're loosing time and then determined some solutions and put out the common sense approach to seeing where we were losing time. And then determined some solutions and put those in place.

A little bit you try on air but a lot more through the technological applications that we are able to consistently reduce some of that downtime and tripping the bottom hole assembly out and anytime that you reduce your failures within that system. You're going to start reducing hours and then eventually days.

Brian Downey -- Citi -- Analyst

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?

Joseph C. Gatto -- President, Chief Executive Officer and Director

We generally can -- every barrel of water that you can recycle and reuse depending upon where you are and what area, you got to be north of $0.50 between $0.50 and a buck on the savings for every barrel.

Brian Downey -- Citi -- Analyst

Got it. That's helpful. Appreciate it. Thanks, guys.

Operator

Our next question comes from Phillips Johnston with Capital One. Please go ahead.

Phillips Johnston -- Capital One Securities -- Analyst

Hey, guys. Thanks. Joe, just a clarification on the 2020 outlook. It sounds like you said it assumes 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 before coming out of '19 or would you expect the rig count to tick up to closer to a five rigs average next year.

Joseph C. Gatto -- President, Chief Executive Officer and Director

Yes, I think it's more the latter on a average five -- type five rig program.

Phillips Johnston -- Capital One Securities -- Analyst

Okay.

Joseph C. Gatto -- President, Chief Executive Officer and Director

Which is actually, Phillip that's actually in line with this year's programs, so remember we're at six now, we'll step down to four 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.

Phillips Johnston -- Capital One Securities -- Analyst

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 our CapEx and how that's capitalized expenses can sometimes create apples charges, comps versus consensus. My question is, what's the rationale for an onshore short cycle company like talent to capitalize any interest or G&A. And is there any consideration for changing the accounting methodology toward more simple and conservative?

Mark Brewer -- Director, Investor Relations

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

James P. Ulm -- Senior Vice President and Chief Financial Officer

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 in 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.

Phillips Johnston -- Capital One Securities -- Analyst

Okay, fair enough. Thank you.

Joseph C. Gatto -- President, Chief Executive Officer and Director

Thanks.

Operator

Our next question comes from Kashy Harrison with Simmons Energy. Please go ahead.

Kashy Harrison -- Simmons & Co. -- Analyst

Good morning, everyone, and congrats on a stellar quarter.

Joseph C. Gatto -- President, Chief Executive Officer and Director

Thank you.

Kashy Harrison -- Simmons & Co. -- Analyst

So just one -- one quick one from me. Jeff, given your history in the Permian, you probably have more visibility into full-field development the 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 packaged parent type wells on a lateral adjusted basis?

Joseph C. Gatto -- President, Chief Executive Officer and Director

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 and coming back in and doing infill drilling can be problematic. It's not that it's unsuccessful. But, generally speaking, the timing aspect of it is critically important also. Calendar 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 feet to 75,00 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 a successful completion design. Generally speaking, that's the best way to develop the reservoir.

Kashy Harrison -- Simmons & Co. -- Analyst

Got it. That's it from me. Thank you.

Operator

Our next call comes from Gail Nicholson with Stephens. Please go ahead.

Gail Nicholson -- Stephens -- Analyst

Good morning. With the field organization 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 we can conceptualize LOE in 2024d?

Joseph C. Gatto -- President, Chief Executive Officer and Director

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've covered in the call already. And then have that start to decrease throughout the rest, the remainder of 2019. And did you also asked about 2020 or kind of future operating expenses. My apologies, I couldn't hear the back end of the question.

Gail Nicholson -- Stephens -- Analyst

Yeah, so the last 2020, just I'm assuming that LOE's to be down year-over-year by just trying to understand, but a percentage standpoint.

Joseph C. Gatto -- President, Chief Executive Officer and Director

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

Gail Nicholson -- Stephens -- Analyst

Okay, great. And then you picked up some mineral rights, (inaudible) about 1,600 net mineral acres. Is that something that you guys would like to do more? Or is that just a one off?

Joseph C. Gatto -- President, Chief Executive Officer and Director

No, it's obviously a market that gets a lot of attention and there's a lot of capital chasing that, lot of private equity certainly. So we got -- get targeted in terms of where we're buying minerals. So it's going to be under beneath our leases. So we have saw that asymmetry of information, we know what our drilling plans. We have a pretty good sense of what the value proposition is and we will 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 we'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 of percentage points on NRI really makes a difference.

Gail Nicholson -- Stephens -- Analyst

Thank you.

Operator

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 one year on the company's website. Thank you again, and you may now disconnect.

Duration: 55 minutes

Call participants:

Mark Brewer -- Director, Investor Relations

Joseph C. Gatto -- President, Chief Executive Officer and Director

Jeff Balmer -- Senior Vice President and Chief Operating Officer

James P. Ulm -- Senior Vice President and Chief Financial Officer

Neal Dingmann -- SunTrust -- Analyst

Brad Heffern -- RBC Capital Markets -- Analyst

Gabe Daoud -- Cowen -- Analyst

Asit Sen -- Bank of America Merrill Lynch -- Analyst

Derrick Whitfield -- Stifel -- Analyst

Ronald Mills -- Johnson Rice & Company -- Analyst

Tim Rezvan -- Oppenheimer -- Analyst

William Thompson -- Barclays -- Analyst

Brian Downey -- Citi -- Analyst

Phillips Johnston -- Capital One Securities -- Analyst

Kashy Harrison -- Simmons & Co. -- Analyst

Gail Nicholson -- Stephens -- Analyst

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