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Edited Transcript of CPE earnings conference call or presentation 7-Aug-19 1:00pm GMT

Q2 2019 Callon Petroleum Co Earnings Call

NATCHEZ Aug 13, 2019 (Thomson StreetEvents) -- Edited Transcript of Callon Petroleum Co earnings conference call or presentation Wednesday, August 7, 2019 at 1:00:00pm 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

* Gabriel J. Daoud

Cowen and Company, LLC, Research Division - Senior Analyst

* Kashy Oladipo Harrison

Simmons & Company International, Research Division - VP and Senior Research Analyst of E&P

* Neal David Dingmann

SunTrust Robinson Humphrey, Inc., Research Division - MD

* Noel Augustus Parks

Coker & Palmer Investment Securities, Inc., Research Division - Senior Analyst Exploration, Production and MLP’s

* Sameer Hyderali Panjwani

Tudor, Pickering, Holt & Co. Securities, Inc., Research Division - Director of Exploration and Production Research

* 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 Second Quarter 2019 Earnings Conference Call. (Operator Instructions). Please note, this event is being recorded. A replay of this event will be available on the company's website for one year.

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

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

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Thank you, operator. Good morning, and thank you, everyone, for taking the time to join our conference call. With me this morning are Joe Gatto, 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 earnings results presentation we posted yesterday afternoon to our website, so I encourage everyone to download the presentation if you haven't already. You can find the slides on our Events and Presentations page located within the Investors section of our website at www.callon.com.

Before we begin, I'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 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'll open the call for Q&A. And with that, I'd 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, as always, good morning, everyone joining us today. Yesterday, after the market closed, we released our second quarter results, which demonstrate the strong operational results, prudent financial decisions and strategic portfolio management necessary to differentiate company performance with an increasingly discerning energy market landscape. Our recent advances towards optimal scale development and the pruning of noncore assets have progressed our corporate capital efficiency and free cash flow goals.

Our time line to achieving these goals will be further accelerated with a highly accretive combination between Callon and Carrizo. We'll have a deep inventory of combined well locations that will compete for capital and be well positioned to capitalize on technical advances from a combined knowledge base. We will also have improved capital efficiency from large-scale pad development and balanced cash conversion cycles, translating into one of the highest recycle ratios in reinvestment efficiency metrics in the industry.

These benefits will be very impactful to our combined Delaware Basin position of approximately 90,000 net acres as the Permian continues to be the key growth engine for the future.

Starting on Slide 4, our second quarter performance highlighted the strength of our operations with sequential production growth in a quarter in which we divested nearly 4,000 BOE per day of production. Despite challenging natural gas and NGL pricing, we are also able to grow EBITDA measurably from the first quarter, which is supported by a 4% reduction in our lease operating expenses for the quarter.

Our leverage ticked down from the first quarter with the closing of our sale of the Southern Midland Basin assets. And in July, we completed the redemption of all of our outstanding cumulative preferred stock, eliminating an annual dividend of more than $7 million and reducing our overall financing costs.

Our field-level capital efficiency continues to improve with the final D&C costs for our classic pad in central Howard County coming in below $600 per lateral foot, coupled with strong well performance relative to our past results and other offsetting activity.

Towards the end of the quarter, we shifted our focus to the completion of our first Delaware mega-pad, which, importantly, utilize a simultaneous operation of 2 completion crews to increase efficiency and reduce cash cycle times.

As we've emphasized previously, increased use of this model is made possible within a larger entity and is a clear strategic benefit of the Carrizo merger.

Our execution of this Delaware mega-pad ultimately delivered an overall cost per lateral foot that was lower than the D&C target required to generate the 2020 well cost synergies we have outlined for the combined Callon-Carrizo Delaware plant. This project was also the first time we've been able to use virtually all of the available recycled water volumes in our system.

We use over 1.6 million barrels of treated volumes during completion operations, greatly enhancing the economics of projects like this in the Delaware while also significantly reducing our environmental impact related to saltwater sourcing and disposal. This recycling system has recently been upgraded to handle up to 60,000 barrels of produced water per day, effectively doubling the capacity of our current operations in the area.

You can see on the top of Slide 5 that our drilling program, which started the year running 6 rigs, has provided us with a significant backlog of ready-to-complete locations, which we will begin to work through in the second half of the year.

With our one dedicated crew and a second temporary crew having completed the Delaware mega-pad, the second crew has been released, and our single dedicated crew is now working on a series of 7 wells in the Midland Basin that will be placed on production later in the third quarter.

We still have 4 rigs running very efficiently across various asset areas. And while we'll work through some of our DUC backlog in the second half, we will enter 2020 with plenty of inventory on that front.

Our capital spending was below forecast, primarily due to our solid operational efficiency gains from larger project concepts and sustained utilization of a dedicated completion crew. As a result, previous expectations of a second quarter operational CapEx spend similar to the first quarter level of $155 million were handily beat in the second quarter by over $20 million. This sets us up to remain at or below our capital budget range for 2019 with activity levels stepping down in the second half of the year after building out the DUC backlog in the first half of 2019.

On the bottom chart, you can see our steady progress to corporate free cash flow generation that is still on track to occur in the second half on a Callon stand-alone basis as our structural capital reductions and strong cash margins combine to highlight an efficient development model, a model that will be enhanced and expanded and used with our combination with Carrizo.

Slide 6 provides a good backdrop to revisit the goals we laid out back in February and how our recently announced transaction with Carrizo advances each of those initiatives in 2020 and beyond.

We started the year by focusing on 4 key areas that we firmly believe will create significant value for investors over time: improving our cash return on capital invested, generating sustainable free cash flow, using that free cash flow to reduce our leverage and focusing on the optimization of our core portfolio with a developmental model that optimizes the value of our multi-zone inventory.

Combination of our 2 high-quality asset bases and complementary teams provides a foundation of improved scale and scope to deliver on these goals for many years to come. Both companies have sector-leading operating margins, which, coupled with the model of consistent, larger-scale development, will contribute to improved returns on capital invested. To that point, we see a clear path to a cash return on capital invested in excess of 15% in 2020, comparing favorably to other industries.

Utilizing the more mature Eagle Ford asset base to organically fund Permian operations under our maintenance capital mode will support the continued advancement of SIMOPS and full field development concepts across the combined core Delaware position and the broader Permian footprint.

This framework for capital allocation will direct more investment to an efficient Permian development machine, reducing our cash flow breakeven price to roughly $50 in 2020, with increasing strong cash flow generation in 2021 and beyond.

As we've consistently stated, our immediate use of free cash flow will be to advance our deleveraging efforts. This accelerated organic free cash flow, coupled with a greatly expanded opportunity set for noncore acreage monetization efforts and a meaningful water infrastructure monetization opportunity, will clear a path to an improved capital structure in the near future.

As part of the dramatically improved free cash flow outlook, we will also be positioned to evaluate other returns of shareholder capital on a shorter time line after achieving our deleveraging goals.

One final point on our pending acquisition of Carrizo, and one of the most important aspects of the transaction, is the ability to optimize the long-term development value of our combined inventory. By merging these 2 companies, we are creating a vehicle that can effectively compete in a lower commodity price environment without the need to high-grade near-term target zones at the expense of other zones that are left behind for less efficient future development after the passage of time.

By broadly employing simultaneous development operations on a consistent basis across the portfolio, we will reduce cycle times and costs and drive our free cash flow breakeven price below $50 as we also preserve the quality of our inventory life for multiple zones.

Slide 7 provides a high-level view of the combined entity in our focus activity areas. We will enjoy the benefit of a strong base of production in cash flow, which is currently above 100,000 BOE per day, with the black oil contribution approaching 70%. This robust base of maturing production will underpin double-digit growth targets and reduce capital intensity.

Despite this well-established position in 2 premier U.S. shale regions, the current enterprise of the company on a pro forma basis is only 10% above the combined SEC PV-10 reserve value for just PDP reserves at year-end 2018.

One of the critical elements that drives the intrinsic value of the combination is the breadth of high-return drilling inventory that both companies bring to the table.

On the top of Slide 8, we've shown the full complement of all well locations with IRRs above 25% fully loaded for drilling, completion and infrastructure costs, but without factoring in cost reductions from the operational synergies we've discussed.

The key takeaway here is that each of the core areas within the portfolio contributes solid economics and compete for capital. In addition, both Callon and Carrizo have delineated multiple zones within the Permian to understand the complexity and requirements to best maximize value from these areas.

Turning to Slide 9, we have seen wide variations in the assessment of well results and acreage quality in the Southern Delaware Basin due to differences in data sources and varying well vintages and landing zone picks.

We've put together a very clear and concise picture using publicly available data from reference sources to show an apples-to-apples comparison of well productivity in the Southern Delaware Basin in close proximity to our combined footprint.

You can see in the map on the left that we have focused on Wolfcamp A results since most operators currently regard this as their primary zone in this part of the basin. This group of well results is shown on both a cumulative distribution plot as well as in a summary chart in the bottom-right quadrant, which distills the information from the distribution plot down to the P50 result for each operator.

The analysis excludes prior operator results, which often are mistakenly ascribed to current acreage owners and typically were completed using older completion designs.

After plotting the P50 results, you can see that both Carrizo and Callon have been amongst the top 8 operators in this region over the past 2 years, competing favorably relative to some of the more prominent names in the industry.

This summary of public data results align well with our own extensive diligence work that incorporates proprietary data, providing us with a high level of comfort that we're combining 2 well-established areas into a cohesive core Delaware position.

At this point, I would like to turn the call over to Jeff.

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

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Thanks, Joe. In our previous acquisition presentation, we outlined a number of areas that we believe will contribute significant upside to our shareholders in the form of highly achievable synergies.

On Slide 10, we've tried to simplify some of these concepts into clear examples that should illuminate the viability of the goals we've set for ourselves.

We quantified our annual run rate for total synergies at $100 million to $125 million. We don't give ourselves credit for achieving all of this in year one. From our perspective, we feel comfortable with targeting somewhere between 50% and 75% of that annual goal for operational synergies in 2020, and we broke out exactly how we calculate those numbers within the ranges and what drives the specific synergy achievements in the first year of the combination.

On the G&A front, achieving $35 million in savings, which is at the low end of our targeted annual run rate, denotes a roughly 20% cut to the combined total G&A. From a drilling and completion perspective, we are targeting a 5% improvement in Delaware development costs under a sustained use of the new development model. Additionally, we're accounting for a 1% improvement in uptime for production from our Permian assets as we focus the operations on larger pad developments. This reduces HBP activity and mitigates effects of broader scale to offset frac impacts and shortens recovery times to restore production.

As I'll cover shortly, we see higher synergy potential in both of these areas as our development model is expanded across the Permian.

Flipping to Slide 11, you can see that our target D&C cost for Delaware development to achieve those previously stated synergies has already been surpassed in our very first mega-pad that we recently completed using simultaneous operations. It's worthwhile noting that we accomplished this with 1 of the 2 completion crews being activated just for this project. We believe there would've been incremental upside to the efficiency benefits if we've been able to utilize a second dedicated crew consistently throughout 2019.

You've heard us talk about the level of operational efficiency that you gain from consistent deployment and activity levels, as seen in the upper right-hand chart, and this most recent achievement on the Rag Run pad is indicative of the viability of D&C synergies and our prospective plan for 2020.

Much of this efficiency and cost savings comes from shipping to larger project development. And you can see, in the lower left-hand chart, that our program is expected to shift measurably in 2020 and 2021, which we expect will drive continued improvements in cost reduction and consistency.

While D&C savings are going to be a significant driver of value, the ability to reduce production downtime across our asset base will be another structural uplift from larger project sizes. A 1% increase in Permian field uptime, which is accomplished through reduced offset frac impacts by concentrating activity with larger projects in a single geographic location rather than moving about with smaller pad projects across an asset area, can generate roughly $10 million in incremental value in the first year. We expect to see this increase over time, increasing the incremental production impact to 1% to 2% of our total Permian production.

The ultimate cash flow impact of this operational synergy is enhanced due to the leading operating margins that will be preserved in a combined company.

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

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

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Thanks, Jeff. As we move forward, our philosophy of protecting cash flow has not changed. We continue to use price point diversification, coupled with appropriate hedging strategies, to ensure that commodity realizations and the underlying business value of those cash flows is adequately safeguarded.

Thus far, we have employed a combination of swaps and 3-way collars in 2020 that cover 12,000 barrels a day with a floor of around $65 a barrel. As we have in the past, we will continue to add hedges as the year progresses with the expectation of locking in positions that account for roughly 40% to 60% of our oil production.

As part of our continued strategy to diversify our oil pricing and to control our physical oil flows, we have added a new agreement to cover 5,000 incremental gross barrels, which will see first delivery in the second quarter of 2021. Much like our other agreements, these volumes do not rely upon export markets for movement, but are being sold into local refinery complexes.

On Page 14, you can see that we have continued to manage the business in a manner that will allow our shareholders to reap the benefits of seeing the business shift to organic and sustainable free cash flow generation. Along with these operational initiatives, we have advanced our strategic goals by continuing to monetize noncore assets like our Ranger property in the Southern Midland Basin and applying those proceeds towards debt reduction while also opportunistically reducing our financing costs as we did with the redemption of our 10% preferred stock.

We expect to continue leverage reduction, credit-enhancing activities in 2020 and see a meaningful opportunity to monetize additional noncore assets from the combined footprint.

We have also seen the credit agencies recognize our progress and were recently upgraded by Moody's and placed on positive credit watch by S&P. With our credit metrics improving, we will look for opportunities to reduce our longer-term cost of debt capital, which will ultimately benefit our combined shareholder base.

As we look forward to 2020 and beyond and see our cash flow breakevens dropping below $50 per WTI barrel, our prospects for meaningful capital structure transformation become a very tangible reality.

With that, I'd like to turn the call back to Joe.

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

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Thanks, Jim. I'd like to reiterate for everyone the goals that we shared at the beginning of the year prior to the announcement of our combination with Carrizo, they remain the guidepost for our management team.

Optimizing our asset development to maximize returns is a critical driver for our business model. We're working to sustainably generate a growing level of free cash flow that can organically reduce leverage that's paramount in building a sustainable business in this sector. Rationalizing corporate costs and monetizing assets that don't meaningfully contribute to the achievement of our other goals is a necessity. And as the shale industry matures, it is critical to be a low-cost provider of supply and not the marginal cost of supply.

Our combination clearly advances each of these mandates and creates a differentiated investment in the SMID cap oil and gas sector.

With that, that's going to conclude our prepared remarks. Operator, would you please open the line for questions?

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Questions and Answers

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Operator [1]

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(Operator Instructions) And our first question today comes from Gabe Daoud with Cowen.

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Gabriel J. Daoud, Cowen and Company, LLC, Research Division - Senior Analyst [2]

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I guess, Joe, maybe just starting with the Rag Run pad, I guess, that kind of bodes well for potentially capturing the synergies you've laid out related to the Carrizo transaction. Could you, I guess, maybe just talk a little bit about how that changed your confidence entertaining those synergies, and I guess how much, if at all, there could be some upside to the initial synergy targets that you laid out on the D&C side?

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

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Yes. I'll start out with that, Gabe, and then I'll turn it over to Jeff, get his views. But yes, we're certainly encouraged by this and bodes extremely well for the plan we've put together in the underlying thesis with the Carrizo transaction. But if you remember, we've seen this before, right? We've employed simultaneous operations to the Midland Basin. Now it was a little bit less of a capital-intensive endeavor. So it's a little bit of a different animal in the Delaware, but by the same token, the prize you're unlocking by getting more efficient on more capital-intensive business is very meaningful. So we're very pleased. As Jeff will talk about, I think we even see some additional upside from where we are on that first mega-pad in the Delaware.

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

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Absolutely. I was very encouraged with the results, both operationally from a timing perspective and also on the financial savings that we were able to achieve. And they go hand-in-hand, of course. The nice thing about that, that overall development is it's consistent with the program that we have of coming out and being thoughtful and getting the majority of the resource covered initially. So from a development perspective, as opposed to kind of drilling individual, trying to hit the home run wells and then suffering the consequences of coming back, the Rag Run pad was indicative of the type of development program that we have scheduled out independently within Callon and then will be even enhanced more significantly with the addition of the Carrizo assets. So top to bottom, I'm extremely happy with the performance so far with that setup

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Gabriel J. Daoud, Cowen and Company, LLC, Research Division - Senior Analyst [5]

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Jeff, that's great color. And then just a follow-up. Maybe just thinking about Callon stand-alone, can you guys maybe just give us a sense of, I guess, the back half of 2019 trajectory in terms of production and CapEx, how should we think about that split for Q3 and Q4?

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

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Yes, Gabe, I'll give you some high-level thoughts on that. Going into the third quarter, obviously, we're losing close to 4,000 BOE per day from the Ranger asset sale, which was relatively mature production, as you recall. And we really -- we're starting off in July with really no wells online until very late in the month, given that Rag Run focus. But what we're seeing now is turning towards unlocking the program we've been building towards, right? This large-scale development in the Delaware and the broader Permian is really starting to kick in, in mid-third quarter.

So you add all that up. Third quarter on a BOE basis, taking out the Ranger impacts and some of the back-ended activity are probably close -- on a BOE basis down close to 10%. On an oil -- relative to the second quarter, on an oil basis, we'll be doing a couple of percentage points better than that, right, because the Ranger assets were 50% or so of gas. We do see a strong growth profile coming late in the third quarter with the Rag Run pad continuing to ramp up. And the Midland pads, we talked about those 7 wells towards the back end of third quarter, what that does set us up for in the fourth quarter is a very strong quarter moving back to production levels that we had seen in the second quarter, but with a higher oil cut.

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Operator [7]

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And our next question comes 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 [8]

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Congrats on a strong quarter and update. Perhaps for Joe, referencing your free cash flow comments on Page 6, how much of your improvement in cash flow breakevens do you attribute to a lower base decline versus cost synergies?

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

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We are picking up a bit of an improvement on the combined PDP decline profile. As we sit here, Callon stand-alone, we've talked about post Ranger just around 40%. We'll do a little bit better than that on the combined asset base. But as we look at it, the majority of it is going to come from the cost synergies, but the PDP component and a more mature asset base overall is not -- a small part of that as well.

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Derrick Lee Whitfield, Stifel, Nicolaus & Company, Incorporated, Research Division - MD of E&P and Senior Analyst [10]

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Got it. Makes sense. And then perhaps for yourself, Joe, or Jeff, as I recall back from your acquisition marketing deck, you have about 450,000 barrels of permitted saltwater disposable capacity in the Delaware on a pro forma basis. Assuming a reasonable price environment and activity level, how much of that is required to support your operations over the foreseeable future? And if I could tack on one additional question, if the excess is approaching what you're highlighting on Page 4 of your power plant, would you consider monetizing some of that given the valuation of those assets at present?

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Joseph C. Gatto, Callon Petroleum Company - President, CEO & Director [11]

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Yes. In terms of what we have in terms of capacity, without getting a lot of specifics because there'll be some ups and downs depending on the cadence of bringing on some larger pads, and we've got to be mindful of the peak water volumes that will be utilized by the system, but that being said, there is going to be a fair amount of unused or latent capacity in the system that we think does present a great opportunity to monetize.

As we've talked about, though, we've spent a lot of money in the last couple of years to building a system that's reliable, having redundancy, allowing us to control our own destiny to move water volumes, and that's only going to be enhanced with the combined footprint in terms of what Carrizo brings to the table and as we interconnect those systems. So while we're looking at the monetization route, we do want to make sure that we are preserving a level of operational control that's going to allow us to run the business. We're not in the water business, but we do have an investment that we think there's significant value to unlock. And simply put that value potential and opportunity to get people's attention is going only to be increased with the combined footprint.

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Operator [12]

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And our next question comes from Neal Dingmann with SunTrust.

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Neal David Dingmann, SunTrust Robinson Humphrey, Inc., Research Division - MD [13]

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Jim, my first question, I think, for you or Jeff. Just curious to know, there's obviously a lot of scrutiny these days on the tighter spacing and just around the Permian. So my question is around, if you review of the -- your multi-zone potentially relatively tighter pads has changed in this environment, not only with -- just with investor comment, but with the lower pricing?

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

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This is Jeff. Generally speaking, we're aligned in what we've done in the past. What we're currently doing and what we're doing in the future is pretty well aligned with some of the comments that you've seen from other companies. I really like our spacing and our thoughtful approach and where we're at.

We kind of use the -- 660 would be a good starting point. There are areas where I think if the geology is really good and your value drivers suggest that you could squeeze in a little bit more, if you're only going to into, say, a single target, for instance, or one zone is significantly better than overlaying or underlying zones, you might think about going a little bit tighter. There's going to be areas in the Permian where 660 might be too tight and you might be a little bit more on the 800-plus range. And I think you've seen companies make those realizations. Our acreage position is set up very well to be able to do that on a continual basis going forward.

So while we still maintain the opportunity to do some variable testing on spacing and stacking, and, of course, then there's the time variable that comes in when you're coming in and setting in child wells next to a parent well, generally speaking, I'm -- we are very much aligned with the majority of the spacing comments that have come out.

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Neal David Dingmann, SunTrust Robinson Humphrey, Inc., Research Division - MD [15]

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Okay, great detail, Jeff. And then just my question, I think I know the answer. I just want to just double check. In regards to the operational plan in the next few months, just wondering, until the acquisition closes, any thoughts, Joe, as far as anything you might do differently as far as these larger pads are bringing in multi-rigs or spreads? I'm just wondering how you're sort of playing it out. Or is it just more or less business as normal?

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Joseph C. Gatto, Callon Petroleum Company - President, CEO & Director [16]

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Yes. No, we're going to continue to block and tackle for the rest of the year.

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Operator [17]

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And our next question comes from Brian Downey with Citigroup.

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

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I was wondering, on the Delaware optimization project, if you have any additional color on what you found versus original expectations heading into that project, and how you see that impacting production costs throughout the remainder of the year. It seemed like that really helped LOE in the second quarter.

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Joseph C. Gatto, Callon Petroleum Company - President, CEO & Director [19]

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It did, yes. That project has been completed. I'm very satisfied with the operational consistency that we've been able to achieve spot on relative to the impact, and we were transparent and declared that. Hands off to the field teams and the contract partnerships that we were able to bring in to methodically work through all of those projects. So it's -- we're in very good shape right now. Thanks for bringing that up. It's a feather in our cap and a shout-out to the operational teams in the field.

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Brian Kevin Downey, Citigroup Inc, Research Division - Director [20]

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Great. And then I'm curious if you see any similar potential on the Carrizo assets, how that correlates with the production uptime synergies that you quoted in the deck. Is that simply you have scale or do you see other brush optimization potential? I guess, what I'm getting at is, could you maybe give us some guidepost of what you're looking for, differentiating the quoted 1% uptime production uplift synergies versus the potential to expand that to 2% for the down the road that you quote?

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Joseph C. Gatto, Callon Petroleum Company - President, CEO & Director [21]

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Yes. Those numbers, Brian, the 1% to 2%, are really from a structural benefit of reducing frac bashing and downtime and recovery time. So we've not outlined any incremental or quantified any incremental benefits from other optimization around a combined program and taking best practices around artificial lift and things like that. They're not in there. We certainly would expect that there are going to be opportunities when we put together our collective heads to do things like that, but there's nothing specific in that 1% to 2% uplift. That's just, again, very simple, primary synergy around structural change and how we develop the asset base.

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Operator [22]

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And the next question comes from William Thompson with Barclays.

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William Seabury Thompson, Barclays Bank PLC, Research Division - Research Analyst [23]

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So maybe for Jeff. Regarding the production uplift synergy target, can you give us a ballpark of how much of your developed reserves is not producing at any given point due to try to mitigating offset frac hits? And looking at your reserve report in the 10-K, it shows about 4% of your developed proved oil was classified as not producing, so I believe some of this might be related to wells being completed, but not turned in line. So I'm just trying to get a sense on where we are today and where the opportunity is.

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Mark Brewer, Callon Petroleum Company - Director of IR [24]

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Will, this is Mark stepping, and Jeff is coughing there. So real quick, the PD&P (sic) [PDP] stuff is not downtime stuff. That's stuff that's waiting to be completed behind pipe. When we look at this, certainly, there's always a certain percentage of the available productive portfolio that is offline simply in need of workover or field maintenance, whatever it is. So a portion of that, obviously, is attributable to what has either been proactively shut in to protect against frac bashing or what is latently affected by frac activity, ours or offset partners, and thus has to be restored. So as we talk about tightening up into larger concentrated projects rather than having a more dispersed program with the smaller pads hitting multiple areas, we believe that from an aerial extent, we're going to have less impact; and also, from a planning perspective, to be able to reduce the time necessary to get those either proactively or affected wells back online. In addition, we're going to have the opportunity set because of the tighter cycle times to reduce the time component of how long that productivity is shut in.

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William Seabury Thompson, Barclays Bank PLC, Research Division - Research Analyst [25]

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Okay. That's helpful, Mark. And then maybe to make sure we're thinking about it correctly, can you spend some time -- spend a minute going through the mechanics of SIMOPS? It sounds like you're running 2 fracs per pad -- 2 fleet, sorry, excuse me, per pad, and I assume you're doing zipper fracs. It seems like you benefit from having dedicated crews versus spot crews and be able to deliver on SIMOPS. Any color there would be helpful.

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Jeffrey S. Balmer, Callon Petroleum Company - Senior VP & COO [26]

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Great. Yes, that's a fantastic question and something that I'm very proud of with the team that we've got. And I've been through this my entire career, and so it's something that is critical to the success of the operations coming forward, starting with the safety aspect of it. And you'll find that the logistics of having multiple crews on location, whether it's rigs or frac crews or drill crews, even coming down to the traffic patterns and who's in charge and what's the emergency plan, those are terrific items to address upfront and to get in place.

Generally speaking, what you -- we could outline is, for instance, if we're going to do a system of 6 wells on a pad basis, we would come in with 2 independent drilling rigs that are relatively side-by-side. Kind of if you've got a good arm, you could hit them with a baseball. And they're drilling fairly similar wells. One would be drilling on the east side. One would be drilling on the west side. We tend to stage the wells out, so that any operational learnings that we have from one rig are literally word-of-mouth at the coffee discussions in the morning, our kickoff meetings every morning. Our drillers can get together and share learnings on the side on what bit worse, what our mud systems are, where we're finding shallow water flows, anything that we have in consideration.

So those are enhanced on the drilling side. And you'll see almost across the board, better operational performance when rigs are side-by-side and when they're doing independent drilling.

Then you also get the benefits of being on location where that rig is drilling multiple wells off the same location. Everybody knows where they're going to show up to work the next morning. You're doing repetitive tasks as opposed to moving locations, starting up again and drilling a different well. When the rigs are finished with their drilling, we move off. We bring in 2 frac crews. And again, if you had a chance to be out on location, it's impressive when you run multiple frac crews at the same time. And it's the exact same thing.

Generally speaking, you're going to be in better shape if you have dedicated frac crews that are used to working with each other, understand the setup, have been onboarded fully on the safety and operational protocols that we have in place.

That being said, on the Rag Run pad, sticking with Schlumberger, of course, we've brought in a second crew that we were familiar with, but they came in and did a very solid job for us. And again, I think it's a testament to the safety protocols and taking your time and working through exactly what you need to be done. If they were working their full time with us all the time, which you'll see in the pro forma company going forward, much more often, we would absolutely believe that we would have additional synergies and increased efficiencies.

And we do zipper frac. That's an excellent point. We think it creates a more complex competing fracture system. And then when the fracs are finished, we move off, bring in multiple drill-out crews. Depending upon where the wellhead locations are and how far apart they are, notionally, you'd bring in at least 2 drill-out crews to come in, knock out the plugs. The facilities are already preset, so we just tie everything in, in a couple of days and get the flowback ready to go. But that's a reasonable outline of how we perform the simultaneous operations.

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Operator [27]

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And our next question comes from Kashy Harrison with Simmons Energy.

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Kashy Oladipo Harrison, Simmons & Company International, Research Division - VP and Senior Research Analyst of E&P [28]

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So maybe a question for Joe. So just looking at the broader macro right now, it feels like a very uncertain time just given the concerns around the global economy, trade policy tweaks and what have you. And so I was just wondering how you guys are thinking about risk management and the hedging strategy associated with the Carrizo acquisition just in case crude price -- like what are you going to do if crude prices go down? And how are you going to protect the asset in the event of a downturn?

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Joseph C. Gatto, Callon Petroleum Company - President, CEO & Director [29]

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Yes. Let me start with that, and then turn it over to Jim. But from a high-level perspective, we talk about risk management, hedging and -- both from a financial standpoint as well as physical risk management. But from an overall perspective, risk management starts with the asset base and the quality of assets you have and the operational flexibility you have within that. So the combined portfolio gives us a lot of optionality across different commodities as well as in terms of cycle times and things like that. So there's a lot more optionality that we have as a combined entity. But specific to your question, I'll let Jim talk about how we think about risk management.

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James P. Ulm, Callon Petroleum Company - Senior VP & CFO [30]

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Yes. I think Joe kind of laid most of it out. I would just come behind and say, listen, we'll be somewhere in the 40% to 60% range, as I mentioned earlier. As I look at it right now on a pro forma basis, we're at the lower end of that range, which is about what you would expect for this time of year. We'll be looking to increase that over the coming months. A couple of weeks ago, we did a 3,000 barrel a day swap at $56 a barrel, and we'll continue to layer in that position.

The primary goal of the risk management is to support the business objectives we have. And one of the most important things we've been talking about is the free cash flow, the sustainable free cash flow over the coming months. So we'll continue to look at it very closely. We'll look at it on a benchmark basis. We'll look at it on an individual differential basis, and we'll put together a cohesive program that will continue to help us mitigate that risk.

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Kashy Oladipo Harrison, Simmons & Company International, Research Division - VP and Senior Research Analyst of E&P [31]

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Got it. That's helpful. And then my follow-up question. On Page 7, you highlight the pro forma proved developed valuation, but is that a higher SEC price deck? I was wondering if you can just help us think through what that GDP valuation would look like at more conservative prices, say, $50 to $55, if you have that sensitivity available.

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Joseph C. Gatto, Callon Petroleum Company - President, CEO & Director [32]

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I don't have that there, but I would point out, while the benchmark pricing is higher, if you look back at '18, the differential for Midland embedded in that was $8. So if you look at it on a realized price basis, we're not too far off. I don't have -- it's probably fine-tuning from there to take that realized price versus where we are today. But again, you have to be careful with just looking at the benchmark TI versus what the realized price is. And obviously, Midland differentials are now swinging to a positive versus that minus $8.

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Operator [33]

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And our next question comes from Sameer Panjwani with Tudor, Pickering, Holt

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Sameer Hyderali Panjwani, Tudor, Pickering, Holt & Co. Securities, Inc., Research Division - Director of Exploration and Production Research [34]

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You talked a little bit about upside to synergies and well cost reductions. And one of the things some of your peers have been using is electric frac fleets. Have you started using these or have any plans to test them out in the near term?

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Joseph C. Gatto, Callon Petroleum Company - President, CEO & Director [35]

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We have not used them yet. They're certainly interesting. We have been investigating them. I think with the pro forma company, the size of the company that we will become makes that more of an opportunity simply because of the upfront investment and the longevity needed to maintain that partnership. But it's certainly something that we are taking a look at

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Sameer Hyderali Panjwani, Tudor, Pickering, Holt & Co. Securities, Inc., Research Division - Director of Exploration and Production Research [36]

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okay. Okay, that's helpful. And then circling back to, I guess, there's an earlier question about how things have looked at lower commodity prices. And I'm just trying to get a sense of how you think about prioritizing growth versus free cash flow. As in the preliminary budget you've put out, is that fair to use down to $50 a barrel even though there would be no free cash flow? Or should we expect you to generate free cash flow via a lower activity level should prices move lower?

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Joseph C. Gatto, Callon Petroleum Company - President, CEO & Director [37]

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Certainly driving that breakeven price down to $50 and below is a big focal point for us, right? As I said, in a maturing landscape, being the low-cost provider is critical. So that's obviously something that we benefit from in a very meaningful way, very tangible way as a combined entity. In terms of the free cash flow versus growth, I think we've already spoken volumes about how we think about that. As Callon on a stand-alone basis, obviously, we had a bit of a higher trajectory. But these combined entities, we are complement -- we're giving up a little bit of production for free cash flow. And that is something, as we move forward and navigate through pricing cycles, that you'll continue to see from us.

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Operator [38]

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And our next question comes from Noel Parks with Coker & Palmer

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Noel Augustus Parks, Coker & Palmer Investment Securities, Inc., Research Division - Senior Analyst Exploration, Production and MLP’s [39]

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Okay, great. I was wondering, did you have any participation in any Carrizo-operated drilling over the past year or 2, prior to starting on the deal?

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Joseph C. Gatto, Callon Petroleum Company - President, CEO & Director [40]

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Nothing of note, no.

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Noel Augustus Parks, Coker & Palmer Investment Securities, Inc., Research Division - Senior Analyst Exploration, Production and MLP’s [41]

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Okay. And I was also interested, with the combined position, are there going to be any changes, I guess, positive or negative as far as looking at land swaps, other consolidation of acreage on your position? Does that get easier with the deal significantly?

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Joseph C. Gatto, Callon Petroleum Company - President, CEO & Director [42]

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Well, certainly, with an expanded footprint, our opportunity set for either monetizations or trades have continued to core up like we've done on our footprint. It's expanded tremendously. In Eastern Reeves and through Ward County, we have a substantial contiguous footprint that will continue to core up around the prospective areas that we think are most beneficial. But yes, there's going to be more opportunities to do trades, do some noncore monetizations. And it's not necessarily because it's not good acreage. It's because if you think about -- the thesis here is overlaying a more efficient, larger development model. And so if you had a single section here or there that might be in a great area, putting a large model on that might not be the right model for us and get the right bang for our buck. So overall, we should see continued optimizing pruning of our asset base as well as some trades to continue to core up and lengthen laterals.

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Noel Augustus Parks, Coker & Palmer Investment Securities, Inc., Research Division - Senior Analyst Exploration, Production and MLP’s [43]

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Great. And is there -- I guess, looking at the -- this is just a housekeeping question. Looking at the accounting going forward, have you made any decision whether the combined companies are going to use 2-stream accounting versus 3-stream for the product mix?

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Joseph C. Gatto, Callon Petroleum Company - President, CEO & Director [44]

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What I would say is we're making very good progress moving down that path, and I would hope to be back in the near future with what our ultimate decision is

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Operator [45]

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And this concludes our question-and-answer session. I'd like to turn the conference back over to Joe Gatto for any closing remarks.

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Joseph C. Gatto, Callon Petroleum Company - President, CEO & Director [46]

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Thank you. And again, thanks, everyone, for joining in. I know there's a lot of calls going on this morning. So please reach out, and -- with any follow-up questions. But again, I appreciate the time, and look forward to updates as we move along in the course of the year. Thanks again.

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Operator [47]

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The conference has now concluded. A replay of this event will be available for one year on the company website. Thank you for attending today's presentation. You may now disconnect your lines at this time, and have a wonderful day.