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Callon Petroleum Co (CPE)
Q3Â 2018 Earnings Conference Call
Nov. 07, 2018, 9:00 a.m. ET
Contents:
- Prepared Remarks
- Questions and Answers
- Call Participants
Prepared Remarks:
Operator
Good morning, and welcome to the Callon Petroleum Third Quarter 2018 Earnings and Operating Results Conference Call. (Operator Instructions) Please note this event is being recorded. A replay of this event will be available on the company's website for one year. I would now like to turn the conference over to Mark Brewer. Please go ahead.
Mark Brewer -- IR Director
Thank you, operator. Good morning, everyone, and thank you for taking time to join our conference call this morning. With me this morning are Joe Gatto, President and Chief Executive Officer; Gary Newberry, our 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 and our Events and Presentations page located within the Investor section of our website at www.callon.com.
Before we begin, I'd like to remind everybody to review our cautionary statements and important disclosures included on Slide 2 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 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.
With that, I'd like to turn the call over to Joe Gatto.
Joseph Gatto -- President & Chief Executive Officer
Thanks, Mark, and good morning to everyone joining us today. Yesterday after the close, we provided our third quarter earnings release which detailed yet another very successful quarter for the company. In a separate release, we announced the retirement of our Chief Operating Officer, Gary Newberry and the hiring of Jeff Balmer as his successor. Gary has been an impactful leader, building a track record of top-tier operations for us in the Permian Basin over almost 10 years and doing it with a high level of integrity. His many contributions to Callon, including the talented team he has assembled will carry on with us well into the future. And we are pleased to welcome Jeff Balmer to the management team. With Jeff, we gained a proven leader, who not only exemplifies the high standards that have earned us respect as responsible operator, but also has the experience to advance program development across our footprint.
Jeff's experience in the Permian and other large-scale unconventional operations is a great fit for this next phase of our growth. And importantly, his qualities as a person align well with the values and culture of our team. Jeff will be assuming the role of COO next month and Gary will stay on until January to ensure a smooth transition. Once again, Gary, on behalf of all the Callon team from me personally, I want to thank you for all that you've done for the company and wish you all the best enjoying a well-deserved retirement and time with your family.
Our third quarter earnings release is out yesterday, along with the earnings slide deck that we'll be referencing during today's call. We posted leading operating margins, coupled with strong sequential production growth in the third quarter, which has been a consistent trend throughout 2018. This level of execution and resulting operational performance maintains and potentially accelerates the path to achieving our goals related to cash flow generation, corporate returns and balance sheet strength. With that in mind, I want to take a step back and talk about how we're positioned today in our priorities moving forward. I'll move to Slide 3 as a backdrop for some of these comments.
As the company transitioned to a Permian operator, we strategically sought out the best available acreage across the Midland and Delaware basins. We invested in both infrastructure and people to execute the longer-term plans that would bring forward value from this meaningful acreage investment, all while maintaining a healthy capital structure and liquidity position to achieve those strategic initiatives. Looking forward to 2019, we are entering a new phase of growth with the maturing of the company and our production base, a phase that provides optionality for delivering shareholder value.
First and foremost, our organic drilling program will benefit from larger pad development and co-development of multiple delineated zones as we have progressed from testing an HBP drilling over the last couple of years. With these tailored program developments, we will also be able to reap the economic and reliability benefits of the proactive infrastructure investments we have made across both the Midland and Delaware basins. In addition, with an acreage position approaching 90,000 net acres, we are evaluating several options for asset rationalization of non-core inventory, as well as opportunities to extract value from infrastructure without impacting our operational flexibility. With these strong underpinnings, the stage is set for accelerating cash flow generation that is driven by asset quality and industry-leading margins.
Looking at Slide 4, we provide a snapshot of our path to assembling a high-quality acreage portfolio that provides us with a critical mass of delineated investment opportunities for years to come, as well as upside from zones that are emerging across the basin. Overall, our net acreage position has grown nearly four-fold and production is up more than six-fold since 2014, due to the efforts of the team that has doubled over that time, driven by the growth in our Midland operations office and a bolstered technical group. With this type of growth profile, it's sometimes easy to lose sight of what's really important, which is profitability.
During these same four years, we've consistently improved our EBITDA margins as production has grown at a compounded annual growth rate of 45%. This is a testament to our team's focus on cost control and making investments for long-term efficiency. Importantly, with the changes in our organization over the last few years, we've continued to set compensation goals that reflect the priorities and purpose outlined on the last slide. As our business model has matured, we've changed some of our key performance metrics to align with the results that we believe drive shareholder value. In general, we moved from a bias toward absolute growth metrics as we are building scale to achieve efficiencies to ones that relate to capital efficiency and will ultimately advance our free cash flow goals. Clearly, this is not a static list and we will continue to refine our metrics over time to focus on shareholder priorities for value creation.
You can see on Slide 5, we are executing on our key performance metrics, with strong quarterly production growth that came in with an oil content that was up over 2% versus last quarter. As we mentioned in the earnings release, the outage of a third-party gas processing facility has reduced our gas and NGL production expectations for the fourth quarter, but we are still targeting 40,000 barrels of oil equivalent per day, which is the level we achieved for the month of September and which we experienced selling gas takeaway curtailments. While this two-stream BOE per day goal is somewhat dependent on the timing of the plants return to full capacity, we are confident that the oil growth will remain robust as we reiterate our guidance for the quarter.
Cash margin strength was sustained in the quarter at over $39 per BOE and adjusted EBITDA was $118.4 million, reflecting a 15% sequential increase. We placed more than 30 net wells on production for the second quarter in a row and see these D&C efficiencies driving that performance to continue into the fourth quarter. Gary will detail more operational highlights in a minute, but I did want to highlight the extension of our preferred vendor agreement for completion services. The amended agreement provides cost certainty for a meaningful percentage of our D&C activity from October of 2018 through December of 2019. It continues to build on our successful partnership with Schlumberger that started over a year ago.
Beyond the normal quarterly stats that get a lot of focus, Page 6 gives you a better picture of how we are trending into the next several quarters. We've included two charts that depict key drivers of capital efficiency, and the resulting impact on cash flow generation on a third chart. Following a series of acquisitions over the last couple of years, our drilling and completion activity demanded a focus on HBP requirements and establishing infrastructure to support program development, both of which are now substantially complete. As a result, we will benefit in two key ways. One, we can advance to larger pad concepts and associated capital savings across all of our core areas instead of being less efficient with single wells or small pads to manage HBP commitments on a timely basis. And two, infrastructure spending as a percentage of operational CapEx will continue to decrease, allowing more capital to flow to D&C, while also realizing the cost benefits from past infrastructure investments.
In the bottom left hand quadrant, you can clearly see these impacts starting to emerge and when combined with strong well performance, deliver a step change and field-level free cash flow that is forecast for the fourth quarter. This is yet another solid tangible step along our path to our corporate free cash flow generation that is expected next year.
At this point, I'd like to hand the call over to Gary.
Gary Newberry -- Chief Operating Officer
Thank you, Joe, and good morning to everyone. On Slide 7, you can see that our ramp in activity in the Delaware Basin has resulted in the marked change in efficiency. In 2019, we expect further gains as we initiate a robust program of multi-well and multi-interval pad development across our existing footprint. We are planning multi-well pads, that include upper and lower Wolfcamp A pair development and a variety of other pad concepts involving multi-interval pads, exploring the Wolfcamp A, Wolfcamp B and second Bone Spring shale.
Most of our completions in the Delaware Basin have been single well pads and have averaged around 650 lateral feet per day as compared to our Midland Basin completions, which have been far more focused on multi-well pad completions and have been approximately 65% more efficient. As we begin to carry over the operating efficiencies we have found in our Midland operations, our ability to drive faster cycle times and lower costs will translate to increasingly strong returns.
Our asset development teams, working alongside our subsurface team led by James Hawkins, have undertaken a thorough review of industry results from 2016 to 2018 and are utilizing this data to further refine our geologic, reservoir and completion modeling to further exploit the various intervals across our Delaware footprint. We've also begun ramping our recycling program with Spur, which will be complemented by the recent activation of the Goodnight Midstream water disposal system. As we ramp activity levels through improved efficiency, water management strategies, including recycled water will significantly reduce cost and further improve operating margins.
When comparing the savings of this program at full tilt against market rates, we are realizing almost $450,000 in cost reductions on a 10,000 foot lateral. As I mentioned on the last call, we've been utilizing more in-basin sand across all areas and that begun employing a 100 mesh local sand and some of our Delaware completions. We have now performed 100% in-basin sand test in one of our lower Wolfcamp A wells and we are planning to increase the use of local sand by year-end, as we further leverage benefits of our pumping services agreement with Schlumberger.
Moving to Slide 8, you can see that we've begun to drill across our entire acreage footprint. You can also see just above the chart, our year-over-year results have shown measured improvement with the average well increasing its IP30 rate by 33%. In fact, more of the wells in 2018 are longer laterals, which do not show as much uplift in initial production due to fluid handling dynamics and controlled rates during early time flowback of these high rate wells. The wells hold pressures longer with shallower declines, which result in outperformance in the 90 to 180 day range.
One of the wells on the acquired acreage was recently completed by the previous operator in the River Tract area, in Southern Ward County, the Effie Ponder 33-18 05H and Upper Wolfcamp A well, that was landed roughly a 100 feet below the Third Bone Spring interval. This well offsets current Third Bone Spring production and has performed above expectations for this landing zone with an IP24 of over 1,400 barrels oil equivalent per day with approximately 91% oil cut.
Our upper and lower Wolfcamp A pair test, that we revealed last quarter, has continued to be an extremely positive sign of (inaudible). The Rendezvous pad has now produced a cumulative 425,000 barrels oil equivalent with 85% oil through 200 days. We are planning multiple pads with upper and lower Wolfcamp A co-development as part of our 2019 program.
Moving to Slide 9, as Joe discussed earlier, we're at a turning point in the program, where we are beginning to move to full-field development mode across all of our acreage position. These larger pad concepts are going to become the norm, and will drive greater operational efficiency throughout our operations. As shown in the upper right insert, at Monarch, our first mega pad, the Casselman 16 has begun to outpace the offsetting vintage three-well pads, resulting in 30% outperformance against the expected average well oil type curve.
Our second mega pad, the Casselman 4 is beginning to track the same trajectory as the Casselman 16 pad, which is highly encouraging. On the lower left insert, Rendezvous pad is showing roughly 17% outperformance against expectations through 200 days in the Delaware. And finally on the lower right insert, we've recently brought on a four-well pad, testing a new design for Wolfcamp A and lower Spraberry co-development at WildHorse. The initial results are approximately 20% ahead of expectations for the combined pad type curve.
On Slide 10, focusing more on the Midland Basin at a high level, you can see that we've consistently outpaced our 1 million barrel type curve on a normalized basis. Continued success from our 10-well downspacing has resulted has in a five-well pad design on tighter spacing, which is currently drilling as we move to leverage our learnings quickly. We will continue to seek opportunities to reduce absolute cost and drive greater value to the bottom line. Completion designs, utilizing reduced fluid loading in Howard and utilization of more than 900,000 barrels of recycled water in Monarch during the quarter are just two examples of how we compare operational responsibility with cost saving measures to make sure we're doing the right for both the shareholder and the stakeholders in the basin.
The key message here is that Callon has begun to shift into a mode of maximizing resource recovery from its valuable acreage position. We believe with proper application of technology, we will deliver a highly competitive returns over a multi-year cycle that allows us to fully exploit our inventory. We've made this a priority for how we look at our 2019 program and the technical teams continue to refine these larger pad designs and completion concepts to maximize the total economic value of the investments we've made thus far.
I've watched this team grow and expand as we have tackled these issues over the past nine years. I'm extremely proud of what we've accomplished and what Jeff joining the leadership team, I'm certain that Callon will continue to be at the forefront of operational leadership in the Permian Basin. I want to say thank you to our team, our partners, vendors and to those who have supported our efforts along the way. It is an honor to be part of the team here at Callon. And I wish everyone the very best.
With that, I would like to hand the call over to Jim Ulm.
Jim Ulm -- Chief Financial Officer
Thank you, Gary and congratulations on your well-deserved retirement. It is a privilege to work alongside you. The company continues to maintain a very strong liquidity position, with our credit facility increasing to $1.1 billion with an elected commitment amount of $850 million after our most recent borrowing base redetermination. At the end of the third quarter, we had just $65 million drawn with $12 million of cash on hand, leaving us nearly $800 million of unused capacity. Our pro forma net debt-to-EBITDA remains at a comfortable 2x, a level we expect will begin to trend downward as we move toward the state of corporate cash flow neutrality over the next several quarters. We are also in an excellent position from a debt maturity standpoint, as our two senior note issuances mature in 2024 and 2026. As Joe mentioned earlier, we are highly focused on growing our cash flow per debt adjusted share and managing our relative debt levels.
On Slide 12, you can see that we continue to maintain a strong hedge position to protect our growing cash flow from operations. In 2019, we are more than 50% hedged on WTI and roughly 40% covered via Midland differential swaps over the same period. We've also taken steps to mitigate regional gas price risk via additional Waha basis swaps with nearly 10 billion cubic feet equivalent covered at a weighted average price of $1.25 per Mcfe. As we mentioned during the previous call, we have contracted for 15,000 barrels of FT capacity on the Grey Oak pipeline, starting around the fourth quarter of 2019. These barrels are already tied to multi-year sales contracts and will receive a combination of Brent and premium Gulf Coast pricing. We will continue to look at additional transportation options and we'll continue to diversify our oil delivery points as part of our methodical portfolio sales approach.
An overview of the changes to our full-year guidance has been provided on Slide 13. We have raised our full-year production guidance at the midpoint, despite expectations for a 1,500 BOE per day reduction of gas volumes during the quarter due to the previously discussed gas plant issue. We are also raising our full-year oil guidance as production has exceeded expectations through the first three quarters and should not be affected by the gas plant issue. Given our continued high level of D&C efficiency, we are raising the midpoint of our total CapEx, inclusive of capitalized expenses by 2%, while raising our net wells placed on production expectations by 5%.
Due to the benefits of our recently extended completion services agreement, significant infrastructure progress during the first three quarters of the year and much of the costs related to our second megapad accounted for in the third quarter, we are confident targeting the top end of the operational capital guidance range at $560 million. LOE guidance for the year remains the same as we account for the integration of the recently acquired Delaware assets, which will initially have slightly higher per unit operating costs. We also expect our field level cash flow to accelerate based upon current internal projections.
With that, I would like to hand the call back over to Joe.
Joseph Gatto -- President & Chief Executive Officer
Thanks, Jim. I'm going to wrap up turning to Slide 14 where we reiterated our key objectives for the next few years that also provide a preview of our tactical plans for 2019, which will be detailed early next year. We will continue to approach the business with a longer-term mindset, seeking to maximize near-term returns on capital, while also employing larger scale development concepts that preserve and potentially enhance the inherent value of our delineated inventory, ensuring a solid base for sustained reinvestment over time.
As Gary discussed, we are very encouraged by the results from our larger 2018 development concepts and will be steadily increasing usage across our asset base next year. As part of our near-term plans, we will also be evaluating options to rationalize non-core, non-operated assets to complement near-term drilling returns on capital. Looking at the bigger picture beyond next year's initiatives, we are moving to life of field development of a multi-zone resource base, while also transitioning to an operating model that could generate free cash flow. This cash flow will provide us optionality for deployment into drilling projects and bolt-on activity, as well as support for strengthening of the balance sheet and the potential for returns of capital to shareholders as the model matures.
With that, that concludes our prepared remarks. And operator, I ask you to please open up for questions.
Questions and Answers:
Operator
(Operator Instructions) And it looks like today's first question will be from Brad Heffern with RBC Capital. Please go ahead.
Brad Heffern -- RBC Capital -- Analyst
Hey, good morning everyone. Joe, just following on last comment that you made there. I mean you laid out a bunch of options for free cash flow in the future, but you talked about reinvesting in a sustained growth model. So, I was wondering if you could just dive into that concept a little more. Does the implication there that free cash flow is sort of in the near to medium term is more likely to go into growth rather than returns to shareholders or how do you think about that?
Joseph Gatto -- President & Chief Executive Officer
Yes, Brad. It's a good question. And I think first and foremost, it's good to be in a position we're sitting here evaluating some of these types of options, right, to be in a spot in the last couple of years where we were pulling forward returns from a lot of the acquisitions that we've done in a bit of an out spend mode and sitting here today with a good path to getting to free cash flow. I think the bottom line is that we do have a very strong inventory with a lot of optionality to invest both in near term delineated zones and testing of other zones to expand organically.
What we are going to be doing through 2019 is continue to obviously to invest in the business. I get to a point where we are at cash flow or generating free cash flow. We'll probably like to operate at that level for a period of time, reinvesting in the business and study some longer-term options, but it's more of a walk before we run. But the bottom line is, we are looking at other options beyond reinvesting in the business as we continue to mature. But what we need to get to that point first and operate at sustained basis.
Brad Heffern -- RBC Capital -- Analyst
Okay, thanks for that. And then I guess, understanding that you're not going to put out the 2019 guide until next year, any preliminary thoughts on what the rig count is going to look like? Obviously, you've locked in a lot of the services, so I would think you'd have a good idea at this point. Thanks.
Joseph Gatto -- President & Chief Executive Officer
We're obviously heading to the back of 2018, some good momentum going into 2019. We try to provide some guidepost as to where we're going, as models for development in 2019 which are going to be pointed to larger pads and bias to that, certainly in the Delaware with that position moving to at least two well pads and up to larger pads with simultaneous operations. I wouldn't expect a big uptick in activity, just given that we are governed by some of our cash flow goals. So, I think that's an easy one to say.
Would also relate it as we move into larger pad development, it's a little bit different than what we've been doing in the Delaware, there's going to be a period of time where we are building a bit of a duck inventory to get prepared and give us the operational flexibility to execute in the right way on that program. But again, as you said, we'll detail more of the cadence of activity and level of activity. But I think we gave you a good sense of some of our key objectives as well as our goals around cash flow that probably narrow that down a bit in terms of levels of activity.
Brad Heffern -- RBC Capital -- Analyst
Appreciate the thoughts.
Operator
Thank you. Next question will be from Will Thompson with Barclays. Please go ahead.
Will Thompson -- Barclays -- Analyst
Good morning, Joe. You quoted 12.5% year-to-date improvement in the cycle times in Delaware was sub-35 day drilling times in the application of simultaneous operations, which I presume includes zipper fracs for these multi-well pads in the Midland. You've given some -- you ran some obviously price concessions on your two frac rates with pricing visibility there. How should we think about well costs heading into 2019 with all those benefits?
Joseph Gatto -- President & Chief Executive Officer
Yes, there is a -- certainly a lot of things to point to as we move into 2019. As we look at it today, some big things right -- the completion vendor agreement is obviously going to be a benefit, not only from a bit of a price improvement, but also providing price certainty through 2019 that people are looking at a potential uptick in activity and maybe some tightening in the market going to the back end. We do see other benefits as well.
Increased penetration of local sand that we're going to be starting in the back half of this year, actually in the Delaware, where we hadn't been employing as much local sand. So that's certainly another plus in the column of cost savings. Moving to multi-well pads, we see million dollar plus savings per well on that basis, but we have to be cognizant of, there's a lot of activity going on in the Permian in labor, steel, chemicals. There's a lot of other pressure points, but overall as we look at and add it up, we think that the pluses and minuses put us in a pretty good position to be relatively stable on drilling completion costs into next year.
Will Thompson -- Barclays -- Analyst
That's helpful. And then one of your peers yesterday spent some time talking about the increasing mix of bounded wells and the implications on type curves relative to parent wells. Just curious on your thoughts there, particularly as you transition to megapads and co-developed programs.
Gary Newberry -- Chief Operating Officer
Yes, this is Gary. And I guess I'll address that from the results we've been delivering. We've typically established our expectations based on a wider range of wells in the area and so we're very confident with the results that we're expecting. And actually with the advent of technology -- with the way we look at the way we're fracking wells, the way we look at the time frame in which we need to come back and work on those wells, in the way we can manage that now with an HBP inventory of activity, we see that we're able to deliver at or improved results from the offset wells.
So, we think we manage that quite well and continue to develop. I think the open pad results that we're showing you over and over again actually demonstrate that quite well, because that was really some additional wells next to some existing wells and outperforming what we have done before. So, we think that's achieved through technology advancement and through a thorough understanding of how you can enhance the performance through the application of technology.
Will Thompson -- Barclays -- Analyst
That's a helpful color. Thank you.
Operator
Next question will be from Neal Dingmann with SunTrust. Please go ahead.
Neal Dingmann -- SunTrust -- Analyst
Good morning all. Congrats Gary. Well deserved. Fittingly, Gary, maybe I'll ask you my first question, just looking at that Slide 8, you guys have done a great job with the co-development, specifically on that Slide 8, you talked about the upper and lower Wolfcamp A. I know -- I think it was in the press release yesterday, Pioneer is now talking about the success of their (inaudible) I guess they call it. Gary, can you just talk about the potential overall for more co-development besides just the upper and lower Wolfcamp A that you see from all of your experience?
Gary Newberry -- Chief Operating Officer
Hey, Neal. Thanks for those kind words you started with. It's been a pleasure working with you over the last nine years, I guess. We first met early time in my career here. So thanks for all that. And thanks for the support.
We're really excited about what the co-development that is clearly being exhibited in the Rendezvous well, that whole thing around frac complexity is important to understand. You can do more in the way you cycle stages, the way you frac wells, the way you ultimately work toward a larger type of development concept.
And we see that certainly within the same zone and we're going to certainly -- we believe we're going to see it in a big way in multi-interval stacked development, similar to what we talked about in my remarks. From the Wolfcamp C to Wolfcamp B and then Wolfcamp A, I think, all of that will be complementary to the results of our expectations. And then of course, the Bone Springs to shale that we're in the process of drilling, about to complete and frac sometime with results next year.
We're excited about the opportunity that's emerging there. But I think ultimately, as I said before, technology matters, understanding your assets in a very detailed way matters, and ultimately the way you cycle and sequence fracture stimulations across the board allows you to get additional frac complexity that further enhances results from the basin. So, we're excited about the future.
Neal Dingmann -- SunTrust -- Analyst
I like that upside. And then lastly, just looking at Slide 7, I want to make sure, Joe for you and the guys, did I understand this right? You talked about here -- sort of here in the point of efficiency gains. I'm just wondering, overall when you look at that I know you talked about sort of cost earlier in the question, but when you see the efficiency gains, when you and Gary talked about it, how much more savings, if we see, I don't know, whatever 5%, 10%,15% more service inflation, will that be offset by these efficiency gains? I just want to make sure that I'm understanding what you're showing in the upside to be in efficiency gains through 2019?
Joseph Gatto -- President & Chief Executive Officer
Yes. Neal again, good question. With what we've been able to achieve, the way we achieve some cost reduction and our pumping services agreement was achieving those types of efficiency gains kind of sharing in that upside. We actually see more to come. So those efficiency gains through -- comes through reduced cycle time, it comes through actually from a cost perspective access to the local sand, which we've now done, really almost a couple of four wells now in the Delaware and we've certainly adopted that in the Midland Basin.
But that savings is going to do a significant amount of cost reduction and ultimately acceleration of production. So, that's the way we look at that, the partnerships that we have with our drilling contractors as well as with our service providers, allow us to be very open and transparent and be very efficient with the time frame and what we're executing on this work. We've talked in the past a reduction in the Delaware drilling cycle times from spud to TD. We've already achieved a significant reduction and there's more to come. But at the end of the day, I personally think that these gains will offset impacts of inflation.
Gary Newberry -- Chief Operating Officer
And Neal, on Page 7, as you pointed out some other benefits here, obviously moving to larger pads and scales I talked about is going to drive savings from some zipper fracs and obviously, the scale from that type of development. But importantly, don't want to lose sight of investments on the water side and we included a chart here on the bottom left in terms of how that's going to start to add up over time with the recycling and investments that we've made should also provide some nice tailwinds for cost savings. So overall, even with your headline -- vendor metrics maybe moving up 5% 10% -- whatever it is, these are the benefits are really going to be a benefit going forward.
Joseph Gatto -- President & Chief Executive Officer
And they are really even -- they actually compound those benefits as you actually start ramping even higher rates and become more efficient. Because that infrastructure investment is paying huge dividends today for us. So, pleased to have done that well.
Will Thompson -- Barclays -- Analyst
Absolutely. Thanks guys.
Operator
Next question will be from Irene Haas with Imperial Capital. Please go ahead.
Irene Haas -- Imperial Capital -- Analyst
Yes. Hi, Gary. Firstly, I want to -- congratulations on your second retirement and hopefully this time sticks. And it's been a real pleasure to see what you have done in at Callon has been great.
Gary Newberry -- Chief Operating Officer
Thank you, Irene. I'll take that as a complement, and I appreciate that. It's very good. This time at Callon has gone so fast. It's been so much fun and this team has been quite an honor to work with. So, appreciate those kind words.
Irene Haas -- Imperial Capital -- Analyst
Great. Question on Delaware Basin. You guys are still relatively a new comer. I just want to know how much truck traffic you have left in terms of all the (inaudible) certainly using more local sand, what's your preferred method of storage and transportation for the sand?
Gary Newberry -- Chief Operating Officer
Yes. Okay. Well, good questions. All again related to operational efficiency and planning for ramp in activity. But as far as oil goes, we're partnered there with a great company. We get connected to oil transport immediately after what pads are coming on. So we're essentially connected the pipelines right away. So, it's the Medallion Pipeline System that we've been enjoyed in the Midland Basin. They are now connecting our pads prior to bringing wells on.
So, we're not trucking oil. Maybe, a few isolated vertical pads, but very minor oil volumes. Water; the investments we've made in water, the onsite disposal wells, the pipeline infrastructure that we kind of promise we'd be done by the end of the third quarter and it's essentially done, as well as the activation of the Goodnight Midstream partnership that we just recently started to help manage some of that onsite disposal and taking it offsite to another disposal field is essential.
But we're really not trucking much water at all. A little bit of trucking associated with the newly acquired assets that were integrating some enhancements to those wells as well to where we can minimize that. And your third question to local sand, we've done, as I've said one full well in the Delaware now. We're in the process of doing a second well, and we will follow shortly with the third well. We've looked at the results.
We've looked at all the API specs of the local sand. We think it meets all the requirements that we need in order to properly stimulate these wells and enhance production. And so, we're pretty much all in on local sand, going forward throughout our 2019 program.
Irene Haas -- Imperial Capital -- Analyst
In the sand are they, kind of, trucked from the sand mines just in time or do you store it on location?
Gary Newberry -- Chief Operating Officer
No, frankly in the Delaware Basin, the mine is about 15 miles away. So it's actually stored in the mine. And so -- and the delivery method is actually through the boxes that you see out on the -- if you out -- out in the Permian much, you'll see a lots of boxes being carried around on some of these flatbed trucks. So multiple delivery methods, but it's primarily box delivered right now. Through our Schlumberger agreement, we're going to go to even more efficient delivery system in January that we're excited about there, kind of, a new delivery system within the Schlumberger fleet that I think, will drive even more efficiencies with sand delivery. And we've had no bottlenecks whatsoever on trucking or waiting on sand not through Schlumberger nor through our Hi-Crush agreement that we have in place, today. So it's very efficient.
Irene Haas -- Imperial Capital -- Analyst
Great. Thank you.
Operator
Next question is from Kevin MacCurdy with Heikkinen Energy Advisors. Please go ahead.
Kevin MacCurdy -- Heikkinen Energy Advisors -- Analyst
Yes. That's Heikkinen Energy Advisors. Gary, thanks for the good detail on the (inaudible) pad drilling and co-development for next year. My question is what about WildHorse and Monarch? What will a typical pad look like in WildHorse next year?
Gary Newberry -- Chief Operating Officer
Yes, WildHorse would be very similar. It's going to be -- again, the way we've done -- WildHorse will essentially go with limited change as far as the cycle time goes, there is still going to be three well pads for the most part, two wells, two rigs drilling side-by-side, its going to be co-development of multiple wells in the same zone and multiple wells between Wolfcamp A and the Lower Spraberry.
So, still going to be very efficient, just like the same efficiencies we've gained this year. We've done multiple sim-up operations this year. We just haven't really talked about them much, because it's not our normal course of business. So WildHorse will be essentially the same, unchanged but more -- incorporating more Lower Spraberry development, co-developed with Wolfcamp A going forward, given some of the enhancements we've made to the way we frac those wells.
Kevin MacCurdy -- Heikkinen Energy Advisors -- Analyst
And in Monarch, are we're going to continue to see the mega pads in 2019?
Gary Newberry -- Chief Operating Officer
Yes, those results are spectacular. I mean, so -- we'll try to improve those even further with the way we frac them, but be more of the same, a mix between the Lower Spraberry and combination of the Wolfcamp A, Wolfcamp B type larger pad development. The benefit of that, Kevin, clearly comes from improved frac complexity. Clearly, the results are showing that we're doing something right there and as well as minimum really future parent-child relationships that we have to manage or worry about. So, we'll continue that throughout our entire portfolio going forward.
Kevin MacCurdy -- Heikkinen Energy Advisors -- Analyst
Thanks for the color and we're going to miss you, Gary.
Gary Newberry -- Chief Operating Officer
Kevin, I really enjoyed the Heikkinen Conference. So thanks for -- thanks a lot and be a part of, that's a great conference. Appreciate that.
Kevin MacCurdy -- Heikkinen Energy Advisors -- Analyst
We appreciate it too, thanks.
Operator
Next question will be from Kashy Harrison with Simmons Energy. Please go ahead.
Kashy Harrison -- Simmons Energy -- Analyst
Good morning everyone and thanks for taking my question. So, I know you're limited on what you can share regarding 2019. But I was wondering if you could talk about infrastructure as a percentage of the 2018 operational CapEx and how we should think about that evolving in 2019 and then maybe what a normalized longer-term percentage looks like in 2020 and beyond.
Joseph Gatto -- President & Chief Executive Officer
I think, the best page points to Kashy is Page 6 to give you a sense of where we've been trending. If you look back at 2017 as we were putting some infrastructure investments to make acquisitions more efficient, what we need to do there. We're in the 25%-ish or even more sometimes as a percentage of total capital for infrastructure. You can see that that trend coming down quite dramatically as we've gotten past the bigger projects. Going forward, we'll certainly have the real-time type investments in centralized tank batteries, flow lines, etcetera, but in terms of larger scale projects, they will start tapering off.
I think the biggest thing that we will be tackling next year will be integrating the water system in the acquired assets in the Delaware into our broader footprint in Spur, but again it's not a huge capital item relative what we're doing in the past. You add all that up, and we should be in that 15% type of zip code for next year, and we hope that over time that will continue to trend down.
Kashy Harrison -- Simmons Energy -- Analyst
And then again, sticking with just trying to get some high-level thoughts on 2019. I was wondering if you could discuss the percentage of top between the Midland and the Delaware during 2018. What that percentage looks like and then, your base case expectation of how that could roughly evolve during 2019?
Joseph Gatto -- President & Chief Executive Officer
Yes, let's not get too far into the detail this year. Our capital allocation was about 60% Midland, 40% the Delaware. Next year probably start trending more toward 50-50.
Operator
Next question will be from Derrick Whitfield with Stifel. Please go ahead.
Derrick Whitfield -- Stifel -- Analyst
Perhaps for Gary, referencing Page 8 of your PowerPoint and specifically the Effie Ponder well, how does the performance of that will compare versus your pre-drill expectations?
Gary Newberry -- Chief Operating Officer
Again, that -- this well is performing quite well, given where it's landed in relation to the Third Bone Springs development. It's doing quite well. So, we're doing very, very well there. It's only a 100-foot into the Wolfcamp A. Our landing zone would be generally deeper. This was drilled and completed by the previous operator. And so, we would change a few things going forward, but we're happy with that performance.
Derrick Whitfield -- Stifel -- Analyst
If you could remind me of the vertical separation between the Wolfcamp A and the Third Bone Spring in that area?
Gary Newberry -- Chief Operating Officer
Yes, it varies. It's 200 to 250 feet or so, but generally it's plenty of oil in place. We clearly understand really the various stresses in that zone. We're going to use that knowledge to place the frac in a very efficient way and deliver strong results.
Operator
Next question will be from Sameer Panjwani with Tudor, Pickering, Holt. Please go ahead.
Sameer Panjwani -- Tudor, Pickering, Holt -- Analyst
As you make the shift to slower growth and balancing cash flows, one of the benefits should be a shallowing of the PDP decline. Can you give us a feel for what the base decline looks like today, following the recent acquisition and how that could change over a multi-year period?
Joseph Gatto -- President & Chief Executive Officer
Yes. We've talked about this with the -- maturation of not only our legacy properties, but with the acquisition that had a pretty mature profile. You look back a year ago, probably in the high-30% sort of base declines and with the acquisition and with again the maturation of our program moving toward the mid to lower-30% range now over time. Again, we really haven't provided that type of color, but as we get these assets integrated, we rollout our program, which is going to be in larger pad designs, some additional incremental zones. We probably want some time before we give that color in terms of where declines go over time.
Sameer Panjwani -- Tudor, Pickering, Holt -- Analyst
And just sticking with the same theme. How much growth do you think you can achieve within cash flow over the next few years. And I'm not trying to nail you down to a specific number, but I think just some high level thoughts or range like 10%, 20%, 30% would be helpful.
Joseph Gatto -- President & Chief Executive Officer
Yes, that's a big range, but I'd say double digits is certainly something that we're squarely focused on. And again, as we get into some of the larger development concepts, get rolling with that, we'll be able to provide some more visibility on a longer-term basis, but let's get into 2019 first and then we'll be able to provide some of that color.
Operator
Next question will be from Noel Parks with Coker Palmer Institutional. Please go ahead.
Noel Parks -- Coker Palmer Institutional -- Analyst
I hopped on a little late, so sorry if you already touched on this, but I was wondering as far as your inventory size, what you're thinking is about what may be the ideal size? Your inventory was in the decade even before the acquisition and just interested on your thoughts on that, especially also given some of the movement we've seen in oil price and also as you move to larger pads, the somewhat longer paybacks that implies before you get all the wells of the pad online. So, you have any thoughts on that?
Joseph Gatto -- President & Chief Executive Officer
Sort of few questions there to address from a high level. If you look at the math in inventory, one of things we need to look at not only the absolute number, but what that implies in terms of lateral feet, right. We're biased to longer laterals and we're moving that direction, certainly in the Delaware with the acquisition allows to lengthened laterals. We have been coring up in certain areas. So, a lot of things we're doing in the Delaware, our 10,000 foot, and a lot we're doing in Midland are pushing toward 10,000 feet. So, need to be mindful of -- when you're looking at inventory, what that means on our net lateral feet.
Doing the math on our activity in 2018, we are squarely into the 20 years on our operated inventory, but that doesn't take into account our ability to increase activity over time within the cash flow goals, we talked about. We like to stay in that sort of mid-teens of core inventory that delineated. And over time, we'll be able to add to that organically with testing of new zones, as we get into some of these larger development concepts. So we feel very good where we stand today, in terms of inventory levels and the ability to grow that organically with an increase in activity. In terms of some of the other questions, Gary, if you wanted to address the other couple of points there.
Gary Newberry -- Chief Operating Officer
Yes, I'll just address that the issue around cycle time, because the way we've managed that with an HBP inventory across the whole asset base now is we have a lot of flexibility as to how we move that forward. We've been typically putting two rigs side-by-side, drilling wells within the same cycles that we've actually been delivering before. So, it's not extending that economic return, it's actually accelerating it and it's actually given us an opportunity to improve the overall results with lower cost associated with the efficiencies of doing it that way, and the complexities we get with the frac initiation with the sequencing of frac stages. So I think that's a good way to do it, the good way to think about it.
Operator
Next question will be from Ron Mills with Johnson Rice. Please go ahead.
Ronald Mills -- Johnson Rice -- Analyst
Good morning. You may have mentioned a little bit on the co-development, but you've made a lot more progress in terms of testing additional zones faster, probably, than what I might have expected. Is 2019 going to be another year where you really continue to delineate some other zones and potentially move toward more of a cube style type development program in 2020 or is that something that pushes in the 2019? Just trying to get a sense as to where do you think you are from the delineation of the additional zones across your position?
Gary Newberry -- Chief Operating Officer
Ron, in terms of delineation, we did test a couple zones (inaudible) this year that turned out to be good tests on both Midland and Delaware Basins. Next year, we're actually going to starting it this year is really the Second Bone Spring would be the one that we had put in the delineation camp, although the amount of results that we're seeing around us are adding up quite quickly with some nice results there. So I wouldn't take it that we're moving into full cube type of designs because this is really going to be a tailored approach to larger-scale development where it makes sense for co-development.
And it also gives us a chance to take advantage of the synergies of larger pad designs. But in terms of delineation of new zones, it won't be really much different from what we are doing this year. It's just that we are applying our learnings from past drilling, where we think we need to co-develop zones, do some larger pad concepts, but it's not going to be a one-size fit all type of approach and the tackling four or five benches at a time.
Ronald Mills -- Johnson Rice -- Analyst
Great. And then just my follow up is a tack on to the inventory question. As you've tested some Wolfcamp C and you start to test the Second Bone Springs, when you think about your mid-teen type inventory, what is that current inventory based on in terms of zones and how many of these zones that you're testing can be additive to that inventory?
Gary Newberry -- Chief Operating Officer
We don't have a lot of that detail out there, right now Ron. We're in the process of refining that post-acquisition here and getting into 2019 can be something that we're looking to lay out with our 2019 plan to give you a refresh on all that our learnings around 2018, in terms of new zones, how we're thinking about tackling it going forward. But certainly the Second Bone and our views on the Wolfcamp C can be additive to that as we roll that out next year.
Ronald Mills -- Johnson Rice -- Analyst
Great, thanks. And Gary, I also want to pass along my congratulations and it was great working with you over the past 10 plus years.
Gary Newberry -- Chief Operating Officer
Thank you, Ron. That means a lot. I remember the first day I step into this job, I had a phone call with you. It is man huddle and visible scare. But thanks for all your support and thanks for all your help and all the questions that you've asked that has made me think about how we move forward with this asset position. It's been an honor to be associated with you guys. Thank you.
Operator
Next question today will be from Phillips Johnston with Capital One. Please go ahead.
Phillips Johnston -- Capital One -- Analyst
Hey guys. Thanks. Just a follow-up on the continued efficiencies, your expected net PoP counts for the year has increased to 50 plus from, I guess, the mid '40s earlier this year on an unchanged rig and frac crew count. Looking at into '19, the mix shift toward larger pads should extend cycle times, as you mentioned. So there's a little bit of a push and pull. My question is, in a scenario where you keep five rigs and two crews going throughout all of next year, would you expect your net PoP count to move a bit higher as efficiencies more than, sort of, offset the effect of larger pads or are you thinking more of a, sort of, a flat to slightly lower PoP count?
Gary Newberry -- Chief Operating Officer
Generally, our expectation is that we will become more efficient, cycle times will get shorter. They won't get longer with these larger pad concepts. And actually we still have upward momentum toward increasing the utilization of those five rigs program and fully utilizing the two frac crews that are dedicated to this and we would expect that's going to continue to grow as we reduce spud to TD cycle times in the Delaware and further improve it in the Midland Basin. So, we see upward potential there.
Phillips Johnston -- Capital One -- Analyst
All right. Sounds good. And thanks very much, Gary and congratulations.
Gary Newberry -- Chief Operating Officer
Thank you very much. Appreciate that. It means a lot, Phillips.
Operator
That will conclude today's question-and-answer session. I'll now turn the conference back over to Joe Gatto for any closing remarks.
Joseph Gatto -- President & Chief Executive Officer
Thanks, operator. Thank everyone for joining in the questions. And once again thank you, Gary. I guess, this your last earnings call with us. You can come back. We have a guest appearance once in a while. It's been great. And again thanks everyone and thanks for the comments. Have a good day.
Gary Newberry -- Chief Operating Officer
I'll call in every quarter.
Joseph Gatto -- President & Chief Executive Officer
Thanks, operator.
Gary Newberry -- Chief Operating Officer
Thanks.
Operator
Thank you, everyone. The conference is now concluded. A replay of this event will be available for one year on the company's website. Thank you again for attending today's presentation. And at this time. You may now disconnect.
Duration: 56 minutes
Call participants:
Mark Brewer -- IR Director
Joseph Gatto -- President & Chief Executive Officer
Gary Newberry -- Chief Operating Officer
Jim Ulm -- Chief Financial Officer
Brad Heffern -- RBC Capital -- Analyst
Will Thompson -- Barclays -- Analyst
Neal Dingmann -- SunTrust -- Analyst
Irene Haas -- Imperial Capital -- Analyst
Kevin MacCurdy -- Heikkinen Energy Advisors -- Analyst
Kashy Harrison -- Simmons Energy -- Analyst
Derrick Whitfield -- Stifel -- Analyst
Sameer Panjwani -- Tudor, Pickering, Holt -- Analyst
Noel Parks -- Coker Palmer Institutional -- Analyst
Ronald Mills -- Johnson Rice -- Analyst
Phillips Johnston -- Capital One -- Analyst
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