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Edited Transcript of CPE earnings conference call or presentation 5-Nov-19 2:00pm GMT

Q3 2019 Callon Petroleum Co Earnings Call

NATCHEZ Nov 10, 2019 (Thomson StreetEvents) -- Edited Transcript of Callon Petroleum Co earnings conference call or presentation Tuesday, November 5, 2019 at 2:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* James P. Ulm

Callon Petroleum Company - Senior VP & CFO

* Jeffrey S. Balmer

Callon Petroleum Company - Senior VP & COO

* Joseph C. Gatto

Callon Petroleum Company - President, CEO & Director

* Mark Brewer

Callon Petroleum Company - Director of IR

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Conference Call Participants

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* Brian Kevin Downey

Citigroup Inc, Research Division - Director

* Derrick Lee Whitfield

Stifel, Nicolaus & Company, Incorporated, Research Division - MD of E&P and Senior Analyst

* Duncan Scott McIntosh

Johnson Rice & Company, L.L.C., Research Division - Research Analyst

* Gabriel J. Daoud

Cowen and Company, LLC, Research Division - Senior Analyst

* Neal David Dingmann

SunTrust Robinson Humphrey, Inc., Research Division - MD

* William Seabury Thompson

Barclays Bank PLC, Research Division - Research Analyst

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Presentation

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Operator [1]

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Good morning, and welcome to the Callon Petroleum Company Third Quarter 2019 Earnings and Operating Results Conference Call. (Operator Instructions)

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

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Mark Brewer, Callon Petroleum Company - Director of IR [2]

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

During our prepared remarks, we'll be referencing the earning 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, disclaimers and important disclosures included on Slide 2 and 3 of today's presentation. We will make some forward-looking statements during today's call that refer to estimates and plans as well as reference our previously announced acquisition of Carrizo Oil and Gas, Inc. Actual results could differ materially due to the factors noted on these slides and in our periodic SEC filings. We'll also refer to some non-GAAP financial measures today, which we believe help to facilitate comparisons across periods and with our peers.

For any non-GAAP measures we reference, we provide a reconciliation to the nearest corresponding GAAP measure. You may find these reconciliations in the appendix to the presentation slides and in our earnings press release, both of which are available on our website. We incorporate those by reference for today's call. Following our prepared remarks, we will open the call for Q&A.

Please note that the topic for this call is our quarterly results, so we appreciate directing any questions on this call to the company's current and previous quarterly results and operational performance. We continue to firmly believe the announced merger with Carrizo is the right strategic move for Callon, but we would defer answering questions relating to the status of the transaction at this time. We're engaging extensively with our shareholders ahead of the special meeting vote on the merger with Carrizo and we look forward to having the opportunity to discuss issues in greater depth and address any questions during those conversations.

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

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Joseph C. Gatto, Callon Petroleum Company - President, CEO & Director [3]

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Thanks, Mark, and we appreciate everyone joining us today. Yesterday afternoon, we released our third quarter results, which demonstrated the strength of our operations and progression towards highly efficient scaled development that's producing tangible improvements in capital efficiency.

We see a unique opportunity to make additional gains in capital efficiency with our pending acquisition of Carrizo, which will accelerate our timeline for sustainable free cash flow, improve returns on capital and further our efforts to strengthen Callon's financial position.

We are excited to hit the ground running on our integrated development plan and reap the benefits from the strategic combination of 2 talented teams and high quality asset bases.

I'll start on Page 4 by revisiting our introductory slide from our February outlook earlier this year. Entering 2019, our message was clear to investors. This year we would focus on harvesting asset value through increased pad development and cycle time reductions. We would seek to optimize margins and increase our operational flexibility. Through thoughtful capital allocation, we would minimize the outspend and moderate growth. And from the longer term perspective, we would seek to balance the preservation of longer term reinvestment opportunities with our near term return profile.

This approach would advance our goal to generate sustainable free cash flow from a model driven by leading capital efficiency coupled with differentiated cash margins and a resilient growth profile supported by strong well productivity and a maturing decline profile.

As we look back at our activity and accomplishments during 2019, we have stuck exactly to that road map. Our shift to scale program development while operating within a reduced budget relative to 2018 has driven records levels of capital efficiency across the portfolio as we've expanded our deployment of larger projects from the Midland Basin to the Delaware Basin earlier this year.

Our margins remain among the strongest in the industry and have been furthered by our success in reducing cost on acquired properties in the Delaware Basin and leveraging the infrastructure investments we've made in earlier years. In addition, the optimization of the portfolio through the sale of almost $300 million in assets year-to-date allowed for the redemption of high cost preferred stock, reducing our cost of capital and simplifying our capital structure.

We firmly believe that the strategic combination of Callon and Carrizo will meaningfully increase the impact of these initiatives through an increased critical mass of development activity and infrastructure in the Delaware Basin, operating and corporate cost reductions and an expanding set of asset optimization and rationalization opportunities.

In sum, we'll be a stronger company with an advantage in cost of supply to improve our competitive position as the unconventional oil and gas business matures. We have honored our promises and delivered exceptional performance as a result.

As we look forward to 2020, the opportunities for shareholder value creation are expanding greatly as we continue to execute our strategy across a larger asset base and have a lot to benefit through thoughtful scaled operations.

I'm going to let Jeff start us off with the operational update for the third quarter. Jeff?

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Jeffrey S. Balmer, Callon Petroleum Company - Senior VP & COO [4]

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Thanks, Joe. Execution during the third quarter continued to exceed expectations with our capital efficiency benefiting from 2 significant large pad developments, one each in the Delaware and Midland basins.

We saw lower operating costs as the optimization project that we kicked off in the first quarter of this year was completed during the early portion of the third quarter. We also saw additional benefits from the increased utilization of our recycling facilities and changes to our chemical treatment programs.

Alongside these operational accomplishments, we continued to grow production per share and lower our lease operating expense per share versus the same period of 2018, while maintaining robust operating margins. At the bottom of this slide, you can see that cost reduction efforts, and both the Delaware and Midland basins benefited significantly from the execution of larger pad development projects.

Flipping to Slide 6. We can take a closer look at the initial results of these larger pad development and demonstrate how they've shown very positive early performance. Through the first 90 days of production, the Rag Run mega-pad wells have averaged roughly 1,000 barrels of oil per day equivalent with approximately an 80% oil cut.

We utilized a slightly more conservative choke methodology with this pad, which you can see in the upper right-hand chart. And this is something we expect to employ more broadly with future concepts of this size in the Delaware. We believe that while it slightly reduces the Peak IP rates, it better manages pressures and results in better productivity for the well from about 6 months till the end of the life of the well.

In the Midland Basin, we recently placed on production a 7-well pad in the Fairway asset area in central Howard County. The project included 3 lower Sprayberry wells and 4 Wolfcamp A wells from 2 pads. These wells directly offset historical producers in the immediate vicinity and we're very pleased to say that they're tracking right alongside the previous vintage wells.

It's important to understand that much of what we've been able to accomplish this year has come from the transition to a more optimal development methodology that drives benefits from greater scale and continuous deployment of drilling and completion teams to more concentrated projects. The efficiency gains have resulted in faster drilling cycle times and increased completion stages per day, both of which saves significant capital dollars.

The less visible benefit to shareholders is the preservation of future drilling locations and improved project level returns as a result of optimal development timing, well design and leveraging of our infrastructure investments that we've done for the past few years.

At this point in time, I'd like to hand over the call to Jim for the next few slides.

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James P. Ulm, Callon Petroleum Company - Senior VP & CFO [5]

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Thanks, Jeff. Slide 7 provides a quick overview of the current and future financial benefits our shareholders enjoy as a result of our focus on creating leading margins, which are on display in the bottom portion of this slide.

Our methodical approach to hedging, which we have consistently employed over time, has allowed us to secure the great majority of our current oil production volumes in 2020 at very attractive prices with additional protection for our limited gas volumes as well.

With recent spikes in the commodity, we were able to act quickly and add some attractive positions in the fourth quarter of this year as well, which should come in handy given some of the market volatility as of late.

You can see in the table in the upper right portion of the slide that we have diversified our crude oil pricing through marketing and transport agreements that provide us the opportunity to better control physical movements and improve realizations in an increasingly complex oil market. We will continue to evaluate opportunities like these across the entire commodity portfolio.

Page -- on Slide 8, I think it's important to revisit the strategic financial objectives that we laid out for the market earlier this year. There were 4 key areas that we felt would advance value for shareholders as we saw progress in each relative area, and those were fairly straightforward: number one, increase our cash flow return -- or, excuse me, our cash return on invested capital; number two, begin generating free cash flow; three, reduce our leverage; and four, focus on long term sustainable returns.

Each of these critical points is well supported by our strategic acquisition of Carrizo and ultimately results in a more investable, creditworthy and robust economic vehicle for shareholders of both companies. We will benefit from the stronger field level economics available from a more capital efficient development plan from shedding noncore assets and unlocking additional value through other monetizations along with accelerating absolute debt reduction, while still retaining the scale necessary to receive the credit market benefits and lower our overall cost of capital for the company. We feel strongly that these benefits are what can make Callon a highly differentiated investment option amongst the current peer companies.

Turning to Slide 9. There's good reason to believe that our team can execute this strategy and create those financial outcomes. We have exhibited a history of acquiring assets and employing our operational expertise to reduce cost, improve well results and create value for shareholders.

With this particular transaction, we are already starting off with high quality assets in Eagle Ford and Delaware, which is part of a broader program that will benefit from increased scale and can be optimized within a capital allocation program that utilizes SIMOPS consistently throughout the Delaware. Data sharing and employing best practices will only further enhance well results, something that we have seen in the positive impact we have made on the acreage acquired in May of last year from a prior operator.

We have already seen an uptick in well productivity as exhibited on the upper right hand graph. But more importantly, we have utilized our field level practices and high quality infrastructure investments to drive down operating costs, resulting in much improved EBITDAX margins versus the prior operator.

At this point, I'm going to turn the call back over to Joe.

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Joseph C. Gatto, Callon Petroleum Company - President, CEO & Director [6]

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Thanks, Jim. In our previous presentations regarding the Carrizo acquisition, we outlined many of the statistics on Page 10. But I wanted to take the opportunity to reiterate just how differentiated our future is after the combination of these 2 companies.

The doubling of the core Delaware footprint and combined total Permian inventory of high quality locations that are well suited for our mega-pad development model provide an enviable runway of opportunity for any Permian operator. We also more than double our production base while preserving a high oil content and a leading cash margin profile.

In addition to supporting immediate free cash flow generation in 2020, this cash flow base will enable us to overlay large scale development in a more meaningful way, especially in the Delaware Basin, and benefit from the undeniable capital efficiencies that accompany repeated activities and economies of scale and manufacturing mode. Sustained scale development will build upon itself over time and lead to a steadily improving free cash flow profile, driving a step change in our ability to drive shareholder value from near term leverage reduction and other opportunities for capital returns in the future.

And looking at the aggregation of these metrics and what it means for Callon as a commodity producer, our corporate breakeven is reduced from $55 on a standalone basis to $50 in 2020, with further improvement into 2021 as our development model matures. To put simply, this will provide investors greater clarity regarding corporate durability through commodity market fluctuations. This structural shift also enhances what's truly important to our shareholders, that being returns on capital that are competitive with other industries.

I've talked to several benefits of our pending transaction and wanted to summarize how these will manifest in terms of real dollars and ultimately improve free cash flow generation. We've clearly identified $100 million to $130 million of annual run rate cash synergies from 2 primary buckets: cash G&A, which accounts for approximately 1/3 of that total amount, and the efficiencies generated from increased large project development with simultaneous operations in the Permian Basin, which comprise balance.

The cash G&A synergies alone represent over 25% of our current equity value, providing a solid base for immediate per share accretion. On top of that, we have demonstrated capital efficiencies from larger project sizes combined with reduced cycle times.

Starting with our Delaware program in 2020 and expanding to the broader Permian over time. This is an incremental $400 million of NPV, is not dependent on improvements in well productivity or the ability to lengthen laterals on the combined footprint. These opportunities are real, as we have proven in prior acquisitions, as are benefits from shared water infrastructure and the refinancing savings. But these aren't captured in our primary synergy buckets and provide upside to our estimates.

Slide 12 breaks out the operational synergies in more detail. The key takeaways here are clear. Our base level synergies are not about direct acreage overlap. While you do need contiguous footprints to overlay scale development and leverage centralized infrastructure, which both of our companies possess in the combined Delaware business, we're unlocking incremental value from an expanded capital program that reaches the critical mass to run multiple rigs and frac crews on a sustained repeatable basis.

After similar projects in the Midland Basin over the last several quarters, we demonstrate the D&C capital savings component in our recent Rag Run project in the Delaware Basin that developed 6 wells using 2 frac crews and simultaneous operation, a decrease of over 15% per lateral foot from where we started the year. This is relative to the 5% to 8% level we needed to hit our target operational synergies for this bucket of savings.

Another key benefit is reduced production downtime. With more wells drilled as parents and larger project sizes, future production disruptions from offsetting children -- frac operations are eliminated and revenue isn't deferred.

Key to our future and that of our industry is developing organizations that have the operational flexibility and financial strength to manage commodity price volatility and generate consistent results over time. Our pending combination with Carrizo more than doubles our proved reserves and production base and provides a tremendous amount of operational flexibility on a footprint of 200,000 net acres and 2 premiere shale plays.

On Slide 13, we've highlighted the elements of our resulting financial strength. The clear advantages of being a larger, stronger entity have already been recognized by the credit agencies in their recent comments. We've also provided some comparative credit statistics in the appendix that illustrate the improvements in our credit profile.

We are combining entities with similar leverage metrics as we stand here today and clearing a path for meaningful pro forma improvement on that front through absolute debt reduction, driven by a dramatically improved free cash flow profile.

With this improved credit outlook, we'll have the ability to improve our cost of capital through opportunistic refinancings.

And as we've already announced, we are also progressing asset monetization opportunities from multiple sources that will create additional near term debt reduction opportunities and further advance our leverage target below 2x.

I'll finish up by turning to Slide 14. To summarize, we've continued to execute the plan we provided to investors at the outset of the year. Callon has evolved over the past few years from a prudent acquirer of top tier acreage positions to a capital efficient operator that can effectively turn those top tier assets into cash flow and corporate level returns.

We understand that to compete with other investable opportunities both within and outside our sector, we must create durable returns that exceed our cost of capital. To that end, we have taken action to optimize our capital structure, protect our cash flows from commodity fluctuations, and continue to proactively align our executive compensation programs with investor focus areas as our company matures.

We have been clear in our strategy and our focus as evidenced by several examples on this page. We've also been clear over the last 2 years that consolidation was coming. And we are going to evaluate our options from a position of strength to maximize shareholder value. Our Board and management team firmly believes that our pending acquisition advances all of our stated objectives and positions Callon as a stronger company for the future.

We also believe that shareholders recognize that the Carrizo transaction represents a unique opportunity to unlock additional value from our Permian asset base and improve our all-in cost of supply as a commodity producer.

Despite a challenging equity market sentiment that casts a negative shadow on our industry, we ask all of you and our shareholders to acknowledge the compelling strategic logic of this transaction and vote your support in the coming days.

That's going to conclude our prepared remarks. I'll turn the call back over to Mark here briefly.

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Mark Brewer, Callon Petroleum Company - Director of IR [7]

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Thanks, Joe. At this time, we're going to go ahead and move forward with Q&A and open the line for questions. Please remember that the topic for this call is the company's current quarterly results and as such, we'll ask that all questions on this call be directed to Callon's current and previous quarterly financial and operational performance. Thank you.

Operator, would you please open the line for Q&A.

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Questions and Answers

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Operator [1]

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

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Neal David Dingmann, SunTrust Robinson Humphrey, Inc., Research Division - MD [2]

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Joe, I was looking at that Slide 6, particularly the bottom right there that shows the Midland large pad outperformance. Given the continued outperformance you're seeing -- I see that Wolfcamp 7-well pad as well as the 5. Really what's interesting is the outperformance versus the parent-child offset. Could you talk about maybe multi-zone pads and kind of what size pads you're targeting there?

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Joseph C. Gatto, Callon Petroleum Company - President, CEO & Director [3]

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Sure. And actually, I'll let Jeff start off on that.

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Jeffrey S. Balmer, Callon Petroleum Company - Senior VP & COO [4]

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Yes. One of the nice things about that is that was a multi-zone pad. So there was a 3-well development kind of on the left hand side of the section, with a 4-well development on the right hand of the section. Each bucket of those, the 3 and the 4, had an existing well drilled back in 2015, if memory serves me correctly. And those parent wells are in the primary zone of the Wolfcamp A. So we offset 2 wells off of that primary zone and then also went above it to the Lower Spraberry. And so, you see a multi-zone stack development program that's more efficient. It eliminates the use -- or the creation of future child wells.

We did do a little bit of a different completion design on them, where the interior wells were a little softer in their design, a little bit less water, so we wouldn't negatively affect the existing parent well, and then kind of got after the wells on the outside. So that's a good example of a thoughtful application of design changes and acknowledging that some depletion would have occurred on the existing wells. And it's a modest blueprint for what we plan on doing going forward anytime that we do have a situation where we want to do stack development in an area that has existing parent wells.

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Neal David Dingmann, SunTrust Robinson Humphrey, Inc., Research Division - MD [5]

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Great details. And just one last follow up. Could you just talk what you're thinking sort of early next year for just further cost reductions? Particularly, I'm curious on LOE as you get more in development mode.

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Jeffrey S. Balmer, Callon Petroleum Company - Senior VP & COO [6]

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Sure. We -- the main thing that we're trying to do is just maintain focus. I really do like the progress that the team has made throughout 2019. There's a whole number of things that have contributed to our performance, and I think these are -- without going into specific detail on any of them, the things that we've done very well we can continue to do better. So whether it is -- we mentioned the chemical program, with getting improvements on the ESP runtime. So our submersible pumps, the longer that they're in the wells and the better that they perform, the lower the cost is from having to go in and pull those.

We've had pure workovers on our historic vertical wells, which tend to be the lower producers, but are still reasonably costly to go in and workover and pull the tubing. We've performed items on power reliability with the 2 substations that we put in play: one in the Delaware Basin and then one in Howard County. That gives us repeatable cheap power, especially when there's fluctuations due to weather or from the overall service company that's providing that.

So those are the focus areas for us going forward, to continue to hit the high ticket items. And we continue to see opportunities, while I'm still very proud of what we've accomplished so far this year.

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Operator [7]

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The next question is from Gabe Daoud with Cowen.

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Gabriel J. Daoud, Cowen and Company, LLC, Research Division - Senior Analyst [8]

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I guess starting with the rig cadence on well count legacy footprint. You have forwards today and I think for '20 you are just picking up a couple of (technical difficulty) Could you maybe just talk about timing on those rig additions and if -- depending on when you add them and just the cadence today if that's enough to grow volume sequentially in 1Q '20?

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Joseph C. Gatto, Callon Petroleum Company - President, CEO & Director [9]

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Yes. We've provided some guidance, Gabe, around our combined 2020 profile that still stands out there in terms of target production growth over the next couple of years, what that means for free cash flow. So while we had previously provided some guidance around Callon on a standalone basis early in the year, we obviously have an integrated plan that we'll be putting in place towards the end of this year. So it's not really an apples-to-apples discussion.

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Gabriel J. Daoud, Cowen and Company, LLC, Research Division - Senior Analyst [10]

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Okay. Got it, Joe. And then just a follow-up. I guess just back to the Howard County 2 co-development projects. Can you just remind us if both the 7 and the 5 well projects are spaced at 10 wells per section in the A? And then overall how you think about spacing in Howard amongst the 3 zones, the Wolfcamp A, the B and the Lower Spraberry?

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Jeffrey S. Balmer, Callon Petroleum Company - Senior VP & COO [11]

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Sure. The well spacing was a little tighter than 660 on these, but not in full development, which is a little unusual in that in my mind you'd kind of start with 660 and tend to be a little bit wider than that going forward, especially when you have an existing parent well.

We -- this is good rock and good geology, and I think in rare instances you can close in and go a little bit tighter in certain circumstances. We took advantage of this, and I think you can see it in the early well results. However, in normal practice when you're in a situation where you have parent wells in place and you're trying to optimize the development program, that's probably a little tighter than you would want to go. But a lot of it depends on the density of the well system that you're putting in. So every well matters.

If you're in a stack development program, you want to be thoughtful about that. But if you have great geology and you're really only targeting one zone and you're doing it all at first in a kind of virgin rock, to maximize the recovery and the value of the wells you would contemplate going a little bit tighter.

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Operator [12]

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The next question is from Derrick Whitfield with Stifel.

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Derrick Lee Whitfield, Stifel, Nicolaus & Company, Incorporated, Research Division - MD of E&P and Senior Analyst [13]

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Perhaps for Jeff. From a bigger picture perspective, I know you have experience with large scale development based on your time at Encana. If I recall correctly, the Rag Run represents one of the first set of Callon wells with control flowback. Do you have a view on the potential EUR uplift associated with control flowback in general? And separately, is this a concept that would apply in the Midland Basin?

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Jeffrey S. Balmer, Callon Petroleum Company - Senior VP & COO [14]

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Yes. That's a great question. I do believe there's a lot of things that roll into the EUR. The question in there -- generally speaking, what our data would suggest is you get a crossover at about 6 months. So the slower back are more conservative choke methodology. While, by the way, it also decreases the erosion or degradation of sand cutting through your facility. So there's some operating expense and facilities maintenance benefits from a slightly more conservative choke methodology. It does provide an opportunity for greater EUR post kind of the 6 months.

What that number is, I don't have a clear vision of that. It's fairly substantial the data would suggest as you go through time. But I don't want to apply a percentage to it at this point in time.

There are applications within the Midland Basin -- it tends to be lower pressure and your water effects have a little bit more of a strong effect on the preliminary flowback. So within the Midland basin, for instance, if you put a lot of water into the system, generally speaking, you're going to want to try to remove that a little more quickly than you would in the Delaware, which already has a lot of water in it.

So there definitely could be some benefits within the Midland Basin. It really depends on the fluid system that you're in, how much depletion and voidage has already occurred within that system from the existing parent wells, and then what your design is. If you put a lot of water into a system, you want to, roughly speaking, remove it a little more quickly because it's a lower pressure system.

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Derrick Lee Whitfield, Stifel, Nicolaus & Company, Incorporated, Research Division - MD of E&P and Senior Analyst [15]

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That makes sense. And then staying with you, Jeff, for my follow up. Referencing Slide 9. Could you comment on the design tweaks that have led to your 10% improvement in well performance versus the previous operator?

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Jeffrey S. Balmer, Callon Petroleum Company - Senior VP & COO [16]

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I'm just catching up with you. There's a number of things to think about it. From a design change perspective, what we're trying to do is look at the -- what we think is going to give us the best well for the least amount of money. And when we can go in and make changes to the design profile, whether it's our stage length, the number of perf clusters per stage, the type of sand we're using, the volumes of how much water we're putting down on a barrels per minute standpoint, all of that utilizing some data analytics and modeling, we have a proprietary predictive model that's allowed us to have well performance that's amongst the best in the basin.

I don't want to share too many of the specific details of it because it would kind of be giving away the farm a little bit. But we do recognize that we've made some significant improvements within the overall design and the outcomes are pretty evident in what we've been able to do from a production standpoint.

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Operator [17]

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(Operator Instructions) The next question is from Brian Downey with Citigroup.

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Brian Kevin Downey, Citigroup Inc, Research Division - Director [18]

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One for perhaps Jeff or Joe. Looking back at Slide 5, clearly impressive reductions in well cost per foot as you transition to larger pads. I'm just wondering how should we think about further runway into 2020 on the well costs, whether that's on well design and efficiency or maybe if there's anything to capture on the service pricing side?

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Jeffrey S. Balmer, Callon Petroleum Company - Senior VP & COO [19]

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Yes, both of those are opportunities I think. When you look at the specific well cost components of it, we are relentless in our efficiency -- our quest for efficiencies, whether that's from drilling the perfect well to making our crews more efficient on the completion side.

As you've seen, we had mentioned and highlighted a Midland Basin system where we had record setting performance on the number of stages per day. And part of that is processes, part of that is consistent crews, which is again a benefit of having a larger operation with -- the Callon and Carrizo merger gives us the opportunity to have both of those.

But there is also some opportunity from -- on the side of working with people who you get win-win situations with from a contractual standpoint, where, if we're more efficient and -- as a partnership we both benefit from that. So I think going forward, we continue to look for opportunities to leverage both the physical operations and then the contractual partnerships that we have with folks.

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Joseph C. Gatto, Callon Petroleum Company - President, CEO & Director [20]

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Yes. And if you think about 2020, like I said, we've put out some directional guidance on that on a combined basis that was relatively a flat CapEx guide adding together our 2019 programs. And that doesn't reflect any deflation in the market. It does not reflect continued improvement that Jeff had said. It does reflect obviously a structural change in our development that we benefit from a capital efficiency standpoint.

But there are going to be more opportunities for us to drive down costs here as we move forward. We've shown it in this quarter. And Carrizo's announcement last night, you should have seen that they highlighted that as well. So you take a lot of momentum from the combined companies, put them together, you have best practices, and then overlay a larger development model to even get incremental savings. It's pretty powerful. And that's excluding any of the potential deflation.

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Brian Kevin Downey, Citigroup Inc, Research Division - Director [21]

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Got it. That's helpful. And then as my follow up, you touched on the spacing on the larger pads. But just curious. Has anything changed on your go-forward approach on co-development from a flow unit selection itself over time, particularly in the Delaware? Is it still A's and B's for now or anything else you plan on adding to that stack?

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Joseph C. Gatto, Callon Petroleum Company - President, CEO & Director [22]

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Yes, that's the primary bread and butter. That's exactly right.

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Operator [23]

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The next question is from Will Thompson with Barclays.

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William Seabury Thompson, Barclays Bank PLC, Research Division - Research Analyst [24]

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Joe or Jeff, as it's been noted, the Rag Run D&C efficiencies are ahead of pro forma expectations despite this being your first Delaware mega-pad to-date. What specifically drove the outperformance? How repeatable is that? And how much of the benefit came from cost deflation, which has been a consistent theme so far this earning season?

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Jeffrey S. Balmer, Callon Petroleum Company - Senior VP & COO [25]

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Sure. The cost inflation really wasn't a large component of it. Anytime that we can do the same thing for a better deal, we're certainly going to take advantage of it. But really the well performance on the larger pads and this one specific, it was a combination of having the repeatable crews, applying learnings both from the drilling and completion side, making design changes to the completion crews to make them more efficient, work-in-process improvements. So the physical movement of our operations on location were well coordinated with consistent crews. And once you get running in that setup, it just builds on the day before. Everybody wants to do a little bit better. And really the group got into a wonderful groove regarding that.

As I mentioned, we did some modest design changes. So we modified some of the interior wells in reflection of the value of decreasing some of the initial capital investments while still maintaining a very robust production profile. And if you added that all together, what it created was a terrific outcome on the cost side.

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Joseph C. Gatto, Callon Petroleum Company - President, CEO & Director [26]

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Yes. And outside of just the D&C cost per foot, we pick up the benefits of cycle times, right, to do a 6-well pad with one frac crew as a longer cash conversion cycle. So that's a benefit outside of the incremental CapEx you can pick up. But certainly, the cycle times and that impact on returns and what we've highlighted on Page 12 also in terms of the production profile. Deploying more of the mega-pad concept is going to reduce or eliminate the amount of children that you have to come back and frac and knock good parent wells offline.

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William Seabury Thompson, Barclays Bank PLC, Research Division - Research Analyst [27]

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It's helpful color. And then it was mentioned the redemption of Callon's preferred stock, reducing cost of capital and plans for opportunistic refinancing. Remind me, is it fair to assume that the priority will be to redeem Carrizo's preferred shares? Would that -- would you look to use the revolver to refinance those? Any color there would be helpful.

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James P. Ulm, Callon Petroleum Company - Senior VP & CFO [28]

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Sure. I think we've said from the beginning that the current intention is a voting agreement and that to the extent that we're unable to get a voting agreement, we have plenty of capacity underneath a newly completed RBL. There's obviously cost of capital savings when you're using a little over 3% debt relative to the 8% and 7-8s of the preferred. But we've not changed our thinking in terms of where we stand on that right now.

Ultimately, I think that is one of the first places we would look. They also -- we will have in the maturities deck an 8 1/4% security that's $250 million. That's a pretty logical place to get further cost to capital benefits as well. But no real update there beyond the remarks I just made.

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Operator [29]

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The next question is from Dun McIntosh with Johnson Rice.

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Duncan Scott McIntosh, Johnson Rice & Company, L.L.C., Research Division - Research Analyst [30]

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On Slide 9, you highlight pretty strong improvement on the Ward County acquisition. I was wondering if you could -- are those co-developed wells? And kind of what's been one of the driver to that uplift, particularly on those assets? Is it targeting? Is it more on the engineering standpoint? Any color there would be good.

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Jeffrey S. Balmer, Callon Petroleum Company - Senior VP & COO [31]

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Yes. This is on the top right hand side?

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Duncan Scott McIntosh, Johnson Rice & Company, L.L.C., Research Division - Research Analyst [32]

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Yes, Jeff.

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Jeffrey S. Balmer, Callon Petroleum Company - Senior VP & COO [33]

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Yes. Dun, some of those are standalone and some of those are co-developed.

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Joseph C. Gatto, Callon Petroleum Company - President, CEO & Director [34]

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Yes. And I think -- Jeff had addressed some of this a little earlier in terms of there's been a lot of things that we've done differently. We've changed some completion designs, refined some targeting. The data set that is represented by the previous operator, the average I think is about 9 wells over 4 or 5 years.

So there was some tweaking going on. We were in a position given the learnings that we had stepping into the Delaware in 2017 to overlay what we've been -- what we were learning, because we were very focused on that area. So out of the box, we were able to overlay some learnings and then enhance that with some completion design tweaks. We've done some subsurface modeling that helped with some of the performance as well.

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Operator [35]

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This concludes our question-and-answer session and the conference has also now concluded. Thank you for attending today's presentation. You may now disconnect.