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Callon Petroleum Co
NYSE:CPE

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Callon Petroleum Co
NYSE:CPE
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Price: 35.76 USD 1.82% Market Closed
Updated: May 18, 2024

Earnings Call Transcript

Earnings Call Transcript
2018-Q3

from 0
Operator

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

I'll now turn the conference over to Mark Brewer. Please go ahead.

M
Mark Brewer
Callon Petroleum Co.

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 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 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 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.

J
Joseph C. Gatto
Callon Petroleum Co.

Thanks, Mark, and good morning, everyone, joining us today. Yesterday after the close, we provided our third quarter earnings release, which details 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 at Callon including the talented team he's 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 gain a proven leader who not only exemplifies the high standards that have earned us respect as a 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 and from me personally, I want to thank you for all that you've done for the company and wish you all the best in enjoying a well-deserved retirement and time with your family.

Our third quarter earnings release was 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 are positioned today and our priorities moving forward.

I'll move to slide 3 as the 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 invest 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 and 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 provided 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 fourfold and production is up more than sixfold since 2014 due to the efforts of a team that has doubled over that time, driven by the growth in our Midland operations office in 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 our long-term efficiency.

Importantly, with the changes in our organization over the last few years, we have 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 results that we believe drive shareholder value.

In general, we have moved from a bias towards 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 in which we experienced only minor gas takeaway curtailments.

While this (00:07:25) BOE per day goal is somewhat dependent on the timing of the plant's 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 13 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.

Garry 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 and 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 of free cash flow that is forecasted 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.

G
Gary A. Newberry
Callon Petroleum Co.

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 a 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 paired development and a variety of other pad concepts involving multi-interval pads exploiting 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 honed in our Midland operations our ability to drive faster cycle times and lower cost will translate to increasingly strong returns. Our asset development teams are working alongside our subsurface team led by James Hawkins, have undertaken a thorough review of industrial 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 at 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 had begun employing 100-mesh local sand in 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 and 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 100 feet below the 3rd Bone Spring interval. This well offsets current 3rd 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 a 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 what's to come. 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 on at a turning point in the program where we're 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 attract the same trajectory as the Casselman 16 pad, which is highly encouraging.

On the lower left insert, the Rendezvous Pad is showing roughly 17% outperformance against expectations to 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 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 are 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 that 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 have 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 have accomplished and, with Jeff joining the leadership team, I am 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.

J
James P. Ulm
Callon Petroleum Co.

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 2 times, a level we expect will begin to trend downward as we move towards a 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've raised our full-year production guidance at the midpoint despite expectations for 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 cost related to our second mega-pad 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.

J
Joseph C. Gatto
Callon Petroleum Co.

Thanks, Jim. I'm going to wrap up turning to slide 14 where we've reiterated our key objectives for the next few years. I'll 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 we'll 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 and 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.

Operator

We'll now begin the question-and-answer session. And looks like today's first question will be from Brad Heffern with RBC Capital. Please go ahead.

B
Brad Heffern
RBC Capital Markets LLC

Hey. Good morning, everyone. Joe, just following on the 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. Is the implication there that free cash flow sort of in the near to medium term is more likely to go into growth rather than return to shareholders or how do you think about that?

J
Joseph C. Gatto
Callon Petroleum Co.

Yeah, 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 over 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 outspend 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 in, both in near-term delineated zones and testing of other zones to expand organically.

What we're going to be doing through 2019 is continuing obviously to invest in the business, 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 and get – well, we need to get to that point first and operate at sustained basis.

B
Brad Heffern
RBC Capital Markets LLC

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.

J
Joseph C. Gatto
Callon Petroleum Co.

Yeah, we're obviously heading into the back of 2018, some good momentum going into 2019. We try to provide some guideposts as to where we are going as models for development in 2019, which are going to be pointed to larger pads and biased 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're governed by some of our cash flow goals. So, I think that's an easy one to say. Would also overlay that 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 DUC inventory to get prepared and give us the operational flexibility to execute in the right way on that program. But again, as you've 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.

B
Brad Heffern
RBC Capital Markets LLC

Appreciate the thought.

J
Joseph C. Gatto
Callon Petroleum Co.

Thank you.

Operator

Next question will be from Will Thompson with Barclays. Please go ahead.

W
William Thompson
Barclays Capital, Inc.

Good morning. Joe, you quoted 12.5% year-to-date improvement in the cycle times in the Delaware with sub 35-day drilling times in the application of simultaneous operations, which I presume it includes zipper fracs for these multi-well pads in the Midland. You've given some – you're gotten some obviously price concessions on your two-frac fleets with pricing visibility there. How should we think about well costs heading into 2019 with all those benefits?

J
Joseph C. Gatto
Callon Petroleum Co.

Yeah. There's certainly a lot of things to point to as we move into 2019. As we look at it today, yeah, there's 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 in 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. There's a lot of activity going on in the Permian: 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 in the next year.

W
William Thompson
Barclays Capital, Inc.

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 mega-pads and co-developed programs.

G
Gary A. Newberry
Callon Petroleum Co.

Yeah. 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 the – with the advent of technology, with the way we look at the way we're fracking wells, the way we look at the timeframe in which we need to come back and work on those wells, and 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've managed that quite well and continue to develop. I think the open pad results that were shown to you over and over again actually demonstrate 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.

W
William Thompson
Barclays Capital, Inc.

That's helpful color. Thank you.

Operator

Next question will be from Neal Dingmann with SunTrust. Please go ahead.

N
Neal D. Dingmann
SunTrust Robinson Humphrey, Inc.

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 the press release yesterday. Pioneer is now talking about the success of their Stackberry, I guess they call it. Gary, could you just talk about the potential overall for more co-development besides just the upper and lower Wolfcamp A that you see from how you experienced?

G
Gary A. Newberry
Callon Petroleum Co.

Yeah, 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. But hey, we're really excited about 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 stack 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 2 shale that we're in the process of drilling about to complete and frac some time 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 frac your 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.

N
Neal D. Dingmann
SunTrust Robinson Humphrey, Inc.

Yeah, I like that upside. And then, lastly, just looking at slide 7, I want to make sure, Joe, for you and the guys that I'm understanding this right. You talked about here the sort of hitting the point of efficiency gains. I'm just wondering overall when you look at that, I know you talked about sort of cost early on a 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 the upside to be and the efficiency gains through 2019.

J
Joseph C. Gatto
Callon Petroleum Co.

Yeah, Neal, again good question. Again, 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. And we actually see more to come. So, those efficiency gains through – it comes through with your 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 full wells now on the Delaware. And we've certainly adopted it in 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 timeframe in which we're executing on this work. We talked in the past 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.

G
Gary A. Newberry
Callon Petroleum Co.

And Neal, on page 7, as you pointed out some other benefits here. Obviously, moving to larger pads and scale I talked about is going to drive savings from some zipper fracs and obviously the scale from that type of development. But importantly, we 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. It should also provide some nice tailwinds for cost savings. So, overall, even with your headline, vendor metrics may move it up 5%, 10%, whatever it is, these other benefits are really going to be of benefit going forward. And that they're 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.

N
Neal D. Dingmann
SunTrust Robinson Humphrey, Inc.

Absolutely. Thanks, guys.

Operator

Next question will be from Irene Haas with Imperial Capital. Please go ahead.

I
Irene Haas
Imperial Capital LLC

Yeah. Hi. Gary, firstly, I want to – congratulations on your second retirement and hopefully this time it sticks. And it's been a real pleasure to see what you have done at Callon. It's been great. So...

G
Gary A. Newberry
Callon Petroleum Co.

Thank you, Irene. I'll take that as a compliment 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.

I
Irene Haas
Imperial Capital LLC

Great. Question on Delaware Basin. You guys are still relatively a newcomer. I just want to know how much truck traffic you have left in terms of all the oil truck, the wastewater, are they on site and certainly you're using more local sand. What's your preferred method of storage and transportation for the sand?

G
Gary A. Newberry
Callon Petroleum Co.

Yeah. Okay. Well, good questions, all again related to operational efficiency and planning for ramp and activity. But as far as oil goes, we're partnered there with a great company. We get connected to the oil transport immediately after what pads are coming on. So, we're essentially connected to pipelines right away. So, it's the Medallion pipeline system that we've been enjoyed in the Midland Basin. They're 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, we – the investments we made in water, the onsite disposal wells, the pipeline infrastructure that we kind of promise would be done by the end of the third quarter and that'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, but 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'll follow shortly with a 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.

I
Irene Haas
Imperial Capital LLC

And the sand, are they kind of trucked from the sand mine just in time or do you store it on location?

G
Gary A. Newberry
Callon Petroleum Co.

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 – if you're out in the Permian much, you'll see 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 a more efficient delivery system in January that we're excited about. They're 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.

I
Irene Haas
Imperial Capital LLC

Great. Thank you.

G
Gary A. Newberry
Callon Petroleum Co.

You're welcome.

Operator

Next question is from Kevin MacCurdy with Han (sic) [Heikkinen] (00:38:53) Energy Advisors. Please go ahead.

K
Kevin Moreland MacCurdy
Heikkinen Energy Advisors LLC

Yeah. That's Heikkinen Energy Advisors. Gary, thanks for the good detail on the (00:39:01) 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?

G
Gary A. Newberry
Callon Petroleum Co.

Yeah. WildHorse will be very similar. It's going to be – again, the way we've done WildHorse will essentially go with a limited change as far as the cycle time goes. It's still going to be three-well pads for the most part, two wells, two rigs drilling side-by-side. It's going to be co-development of multiple wells in the same zone and multiple wells in between the Wolfcamp A and the Lower Spraberry. So, it's still going to be very efficient just like the same efficiencies we've gained this year. We've done multiple simultaneous operations this year. We just haven't really talked about them much because it's our normal course of business. So, WildHorse will be essentially the same, unchanged, but 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.

K
Kevin Moreland MacCurdy
Heikkinen Energy Advisors LLC

Got you. And in Monarch, are we going to continue to see the mega-pads in 2019?

G
Gary A. Newberry
Callon Petroleum Co.

Yeah. 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 in combination with the Wolfcamp A, Wolfcamp B-type larger pad development. And 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 you even have to manage or worry about. So, we'll continue that throughout our entire portfolio going forward.

K
Kevin Moreland MacCurdy
Heikkinen Energy Advisors LLC

All right. Thanks for the color and we're going to miss you, Gary.

G
Gary A. Newberry
Callon Petroleum Co.

Hey, Kevin, I've really enjoyed the Heikkinen Conference. So, thanks for letting me be a part of that. That's a great conference. I appreciate that.

K
Kevin Moreland MacCurdy
Heikkinen Energy Advisors LLC

We appreciate it. Thanks.

Operator

Next question will be from Kashy Harrison with Simmons Energy. Please go ahead.

K
Kashy Harrison
Piper Jaffray & Co.

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?

J
Joseph C. Gatto
Callon Petroleum Co.

I think maybe the best page to point 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 in some infrastructure investments to make acquisitions more efficient, what we need to do there, we're in the 25%-ish or even more. It's sometimes – as 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 run – the sort of real-time type of investments and centralized tank batteries, flow lines, et cetera. But in terms of larger scale projects, they will start tapering off. I think the biggest thing that we'll be tackling next year will be integrating the water system and the acquired assets from the Delaware into our broader footprint in Spur. But again, that's not a huge capital item relative to what we'd do 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.

K
Kashy Harrison
Piper Jaffray & Co.

That's great color there. 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 POPs 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.

J
Joseph C. Gatto
Callon Petroleum Co.

Without getting too far in the details, this year our capital allocation was about 60% Midland, 40% in the Delaware. Next year, we'll probably start trending more towards 50/50.

K
Kashy Harrison
Piper Jaffray & Co.

Awesome. All right. Thanks again, and congratulations on a solid quarter.

J
Joseph C. Gatto
Callon Petroleum Co.

Thank you.

Operator

Next question will be from Derrick Whitfield with Stifel. Please go ahead.

D
Derrick Whitfield
Stifel, Nicolaus & Co., Inc.

Good morning, all, and congrats on a strong quarter and update.

J
Joseph C. Gatto
Callon Petroleum Co.

Thanks, Derrick.

D
Derrick Whitfield
Stifel, Nicolaus & Co., Inc.

Perhaps for Gary, referencing page 8 of your PowerPoint and specifically the Effie Ponder well, how does the performance of that well compare versus your pre-drill expectations?

G
Gary A. Newberry
Callon Petroleum Co.

Again, this well is performing quite well given where it's landed in relation to the 3rd Bone Spring's development. It's doing quite well. So, we're doing very, very well there. It's only 100 foot into the Wolfcamp Bay. 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.

D
Derrick Whitfield
Stifel, Nicolaus & Co., Inc.

That's great, Gary, and if you could remind me of the vertical separation between the Wolfcamp A and the 3rd Bone Spring in that area.

G
Gary A. Newberry
Callon Petroleum Co.

Yeah. 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.

D
Derrick Whitfield
Stifel, Nicolaus & Co., Inc.

All right. Thanks for the color, and great quarter, guys.

G
Gary A. Newberry
Callon Petroleum Co.

Thanks, Derrick.

J
Joseph C. Gatto
Callon Petroleum Co.

Thanks.

Operator

Next question will be from Sameer Panjwani with Tudor, Pickering, Holt. Please go ahead.

S
Sameer Panjwani
Tudor, Pickering, Holt & Co. Securities, Inc.

Good morning, guy. As you make the shift to slower growth and balancing cash flows, one of the benefits should be a shallowing and a PDP decline. So, 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 multiyear period?

J
Joseph C. Gatto
Callon Petroleum Co.

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, we're probably in the high 30% sort of base declines and with the acquisition and with, again, the maturation of our program moving towards the mid to lower 30s percent range now over time. Again, we really haven't provided that type of color. But as we get these assets integrated, we roll out our program which was 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.

S
Sameer Panjwani
Tudor, Pickering, Holt & Co. Securities, Inc.

Okay. Fair enough. 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.

J
Joseph C. Gatto
Callon Petroleum Co.

Yeah. That's a big range, but I'd say double digits is certainly something that we were 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 the 2019 first and then we'll be able to provide some of that color.

S
Sameer Panjwani
Tudor, Pickering, Holt & Co. Securities, Inc.

Okay. Thank you.

Operator

Next question will be from Noel Parks with Coker & Palmer Institutional. Please go ahead.

N
Noel Parks
Coker & Palmer, Inc.

Hey. Good morning.

J
Joseph C. Gatto
Callon Petroleum Co.

Good morning.

N
Noel Parks
Coker & Palmer, Inc.

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 your thinking is about what maybe 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 payback that implies before you get all the wells of the pad on line. So, do you have any thoughts on that?

J
Joseph C. Gatto
Callon Petroleum Co.

So, two questions there to address from a high level if you look at the map. In inventory, one of the 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 in that direction certainly in the Delaware. With the acquisition, allows us to lengthen laterals. We've been coring up in certain areas.

So, a lot of things we're doing in the Delaware are 10,000 foot. A lot we're doing in Midland are pushing towards 10,000 feet. So, need to be mindful of when you look at the inventory what that means on a net lateral feet.

Doing the math on our activity in 2018, we're 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's 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, I don't know, Gary, if you wanted to address the other couple points there.

G
Gary A. Newberry
Callon Petroleum Co.

Yeah, I'll just address 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 cycle 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 and a good way to think about it.

N
Noel Parks
Coker & Palmer, Inc.

Great, thanks a lot.

Operator

Next question will be from Ron Mills with Johnson Rice. Please go ahead.

R
Ronald E. Mills
Johnson Rice & Co. LLC

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 towards 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 you think you are from the delineation of the additional zones across your position.

J
Joseph C. Gatto
Callon Petroleum Co.

Yeah, Ron. In terms of delineation, we did test a couple zones in the C this year that turned about to be good tests on both Midland and Delaware Basins. Next year, and we're actually going to be starting at this year, is really the second Bone Spring, would be the one that I'd 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 design. 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're doing this year. It's just that we're 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 tackling four or five benches at a time.

R
Ronald E. Mills
Johnson Rice & Co. LLC

Great. And then just my follow-up is attack on to the inventory question. As you've tested some Wolf Camp C and you start to test the second Bone Spring, 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 added to that inventory?

J
Joseph C. Gatto
Callon Petroleum Co.

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. It's going to 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 Wolf Camp C can be added to that as we roll that out next year.

R
Ronald E. Mills
Johnson Rice & Co. LLC

Great. Thanks. And, Gary, I also want to just pass along my congratulations. And it is great working with you over the past 10-plus years.

G
Gary A. Newberry
Callon Petroleum Co.

Thank you, Ron. That means a lot. I remember the first day I stepped into this job, I had a phone call with you. So, man, I don't – it is a little scary, but thanks for all your support and thanks for all your help and all the questions that you've asked. It's made me think about how we move forward with this past acquisition. It's been an honor to be associated with you, guys. Thank you.

R
Ronald E. Mills
Johnson Rice & Co. LLC

Thanks.

Operator

Next question today will be from Phillips Johnston with Capital One. Please go ahead.

P
Phillips Johnston
Capital One Securities, Inc.

Hey, guys. Thanks. Just to follow up on the continued efficiencies. Your expected net pad count 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 out into 2019, the mix shift towards 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 pad count to move a bit higher as efficiencies more than sort of offset the effects of larger pads or are you thinking more of a sort of a flat to slightly lower pad count?

G
Gary A. Newberry
Callon Petroleum Co.

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'll 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 that's going to continue to grow as we reduce spud to TD cycle times in the Delaware and further improvement in the Midland Basin. So, we see upward potential there.

P
Phillips Johnston
Capital One Securities, Inc.

All right. Sounds good. And thanks very much, Gary, and congratulations.

G
Gary A. Newberry
Callon Petroleum Co.

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.

J
Joseph C. Gatto
Callon Petroleum Co.

Thanks, operator. Thanks, everyone, for joining and the questions. And once again, thank you, Gary. This is your last earnings call with us, will you come back for a – you have a guest appearance once in a while. But that's been great. And again, thanks, everyone, and thanks for the comments. Have a good day.

G
Gary A. Newberry
Callon Petroleum Co.

I'll call in every quarter.

J
Joseph C. Gatto
Callon Petroleum Co.

Thanks, operator.

G
Gary A. Newberry
Callon Petroleum Co.

Thanks.

Operator

Thank you, everyone. The conference has 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.