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Callon Petroleum (CPE) Q2 2019 Earnings Call Transcript

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Callon Petroleum (NYSE: CPE)
Q2 2019 Earnings Call
Aug 07, 2019, 9:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:


Operator

Good day, and welcome to the Callon Petroleum second-quarter 2019 earnings conference call. All participants will be in a listen-only mode. [Operator instructions]. After today's presentation there will be an opportunity to ask questions.

[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.

Mark Brewer -- Director, Investor Relations

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'd 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 two and three 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 & Gas, Inc.


And 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 the earnings press release, both of which are available on our website.

We incorporate this by reference for today's call. Following our prepared remarks, we will open the call for Q&A.And with that, I'd like to turn the call over to Joe Gatto.

Joe Gatto -- President and Chief Executive Officer

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 within an increasingly discerning energy-market landscape. Our recent advances toward optimal scale development and the pruning of non-core assets have progressed our corporate-capital efficiency and free cashflow goals.

Our timeline of achieving these goals will be further accelerated with the highly creative 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 and 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 were 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 cost 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 utilized a simultaneous operation of two completion crews to increased efficiency and reduced-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've outlined for the combined Callon-Carrizo Delaware plan.

This project was also the first time we've been able to use virtually all the available recycled water volumes in our system. We used 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 six 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 seven wells in the Midland basin that will be placed on production later in the third quarter. We still have four rigs running very efficiently across various asset areas and while we will 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. The sets us up to remain at or below our capital-budget range for 2019 with activity level 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 inefficient 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 this year by focusing on four 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 the developmental model that optimizes the value of our multizone inventory. Combination of our two 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 improve 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 have 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 non-core acreage monetization efforts in a meaningful water infrastructure modernization opportunity will clear a path to improve 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 timeline 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 long-term development value of our combined inventory. By merging these two 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 cashflow-breakeven price below $50 as we also preserve the quality of your 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 benefits of a strong base of production and 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 two premier US 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 nine, we have seen wide variations in the assessment of well results and acreage quality in the southern Delaware base and due to differences in data sources and varying well, vintages and landing zone pits. We 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 scribed 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 among the top five operators in this region over the past two years, competing favorably relative to some of the more prominent names in the industry.

The summary of public data results align well with our own extensive diligent work then incorporate proprietary data, providing us with a high level of comfort, we are combining two well established areas into a cohesive core Delaware position.At this point, I would like to turn the call over to Jeff.

Jeff Balmer -- Chief Operating Officer

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 have broken 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 a 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 HVP activity and mitigates effects of broader scale-offset-frac impacts, and shortens recovery times to restore production. As I'll cover shortly, we see higher synergy potential and 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 costs 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 worth noting that we accomplished this with one of the two completion crews being activated just for this project, we believe there would have 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 in our perspective 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 overtime 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 the combined company. And with that, I'd like to hand the call over to Jim.

Jim Ulm -- Chief Financial Officer

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 three-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 control our physical oil flows, we have added a new agreement to cover 5000 incremental growth 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 toward 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've 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 breakeven is 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.

Joe Gatto -- President and Chief Executive Officer

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, there remain the guideposts for our management team. Optimizing our asset development to maximize returns is a critical driver for our business model. Working to sustainably generate a growing level of free cash flow that can organically reduce leverage is paramount in building a sustainable business in the 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 supply and not the marginal cost of supply. Our combination clearly advances each of these mandates and creates a differentiated investment in the mid-cap oil and gas sector. With that, that's going to conclude our prepared remarks.

Operator, would you please open the line for questions?

Questions & Answers:


Operator

We will now begin the question and answer session. [Operator instructions] And our first question today comes from Gabe Daoud with Cowen. Please go ahead.

Gabe Daoud -- Cowen and Company -- Analyst

Hey. Good morning, Joe. And good morning, everyone.

Joe Gatto -- President and Chief Executive Officer

Hey Gabe.

Gabe Daoud -- Cowen and Company -- Analyst

I guess, Joe, maybe just starting with the Rag Run pad, I guess that kind of bodes well for potentially capturing that the synergies you've laid out related to the Carrizo transaction? Could you, I guess, maybe just talk a little bit about how that shapes 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?

Joe Gatto -- President and Chief Executive Officer

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 put together and the underlying thesis with the Carrizo transaction. But if you remember, we've seen this before, right, we've employed simultaneous operations in the Midland Basin, and that 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 and more capital intensive business is very meaningful. So we're very pleased as Jeff will talk about it, I think we even see some additional upside from where we are on that first mega-pad in the Delaware.

Jeff Balmer -- Chief Operating Officer

Absolutely. I was very encouraged with 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 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 we'll 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.

Gabe Daoud -- Cowen and Company -- Analyst

Thanks Jeff. It's great color. And then just 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 in capex? How should we think about that split for 3Q and 4Q?

Joe Gatto -- President and Chief Executive Officer

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 started 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 toward unlocking the program we've been building toward, right.

This large scale development in the Delaware and the broader Permian is really starting to kick 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 or probably close -- on a Boe-basis down close to 10%. On an oil -- relative to the second quarter, on an oil basis will be doing a couple percentage points better than that, right? Because the Ranger assets were 50% or so 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 pad, we've talked about those seven wells toward 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.

Gabe Daoud -- Cowen and Company -- Analyst

Great. Thanks, Joe, that's helpful. Thanks, guys. Good job.

Joe Gatto -- President and Chief Executive Officer

Thanks.

Operator

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

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

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

Joe Gatto -- President and Chief Executive Officer

Thanks Derrick.

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

Perhaps for Joe, referencing your free cash flow comments on page six, how much of your improvement in cash flow breakeven do you attribute to lower base decline versus cost synergies?

Joe Gatto -- President and Chief Executive Officer

We are picking up a bit of an improvement on the combined PDP to client profiles. As we sit here at 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 the majority of this going to come from the costs synergies, but the PDP component and a more mature asset-base overall is not a small part of that as well.

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

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 disposal 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 access is approaching what you're having on page four of your PowerPoint, would you consider monetizing some of that given the valuation of those assets at present?

Joe Gatto -- President and Chief Executive Officer

Yeah. 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 got to be mindful of the peak water volumes that will be utilized by 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 spent a lot of money 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 a 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 an opportunity to get people's attention, is only going to be increased with the combined footprint.

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

That makes sense. Very helpful. Thanks for your time.

Joe Gatto -- President and Chief Executive Officer

Thanks Derrick.

Operator

And our next question comes from Neal Dingmann with SunTrust. Please go ahead.

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Good morning, all. Joe, 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 your view of the -- your multi zone potentially relatively tighter pads has changed in this environment, not only with just with investor comments but with the lower pricing.

Jeff Balmer -- Chief Operating Officer

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, 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 can squeeze in a little bit more, if you're only going to 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 stalking 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, we are very much aligned with the majority of the spacing comments that have come out.

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Great detail, Jeff. And then just my question, I think I know the answers, but I want to just double check. In regards the operational plans, 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 or bringing in multi rigs or spreads. I'm just wondering how're you sort of playing out or is it just more or less businesses normal?

Joe Gatto -- President and Chief Executive Officer

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

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Very good. Thanks, guys.

Operator

And our next question comes from Brian Downey with Citigroup. Please go ahead.

Brian Downey -- Citi -- Analyst

Good morning. Thanks for taking the questions. 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? Seemed like that really helped LOE in the second quarter.

Joe Gatto -- President and Chief Executive Officer

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 you know, we were transparent and declare that, hands off to the field teams in the contract partnership.

So we were able to bring in to methodically work through all 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.

Brian Downey -- Citi -- Analyst

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

Joe Gatto -- President and Chief Executive Officer

Yes. Those numbers, Brian that the 1% to 2% are really from a structural benefit of reducing frac bashing and downtime and recovery time. So we have 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 that there's nothing specific in that 1% to 2% uplift, that's just again very simple primary synergy around structural change in how we developed asset base.

Brian Downey -- Citi -- Analyst

That's helpful. That's it.

Operator

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

William Thompson -- Barclays -- Analyst

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

Mark Brewer -- Director, Investor Relations

Hey, well, this is Mark step in and Jeff is coughing there. So the real quick, the PD&P stuff is not downtime stuff, that stuff it'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 work over or field maintenance, whatever it is.So a portion of that obviously is attributable to what is either been proactively shut in to protect against frac bashing or what is blatantly affected by frac activity hours or offset partners and that 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 the aerial extent we're going to have less impact and also from a planning perspective, be able to route 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.

William Thompson -- Barclays -- Analyst

That's helpful Mark, thanks. And then maybe to make sure I was thinking about it correctly. Can you spend some time like spend a minute going through the mechanic system ops, sounds like you're running two fracs per pad -- two fleets, sorry, excuse me per pad. And I think you're doing deeper 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?

Joe Gatto -- President and Chief Executive Officer

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 out 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 up front and get in place. Generally speaking, what you -- we could outline is for instance, if we're going to do a system of six-wells-on-a-pad basis, we would come in with two independent drilling rigs that are relatively side by side kind of if you've got a good arms, getting hit them with 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 words, 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 that our 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 two frac crews. And again, if you had a chance to be out on location, it's impressive when you run multiple frac crews at 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 on boarded 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 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 there 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 reduce zipper frac, that's an excellent point.

We think it creates a more complex-competing-fracture system. And then when the fracture 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 bring in at least to 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 flow back ready to go. But that's a reasonable outline of how we perform the simultaneous operations.

William Thompson -- Barclays -- Analyst

Helpful. Thank you.

Operator

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

Kashy Harrison -- Simmons Energy -- Analyst

Good morning, everyone. And thank you for taking my question.

Joe Gatto -- President and Chief Executive Officer

Good morning, Kashy.

Kashy Harrison -- Simmons Energy -- Analyst

Yeah, good morning. 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 tweak 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 crude prices go down and how are you going to protect the asset in the event of a downturn?

Joe Gatto -- President and Chief Executive Officer

Yeah. Let me start with that and then I'll turn it over to Jim. But from a high-level perspective, we've talked 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.

Jeff Balmer -- Chief Operating Officer

Yeah. 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 our 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 which you would expect for this time of year we will be looking to increase that over the coming months.

Couple weeks ago we did a 3000 barrel a day swap at $56 a barrel and will 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 will continue to look at it very closely, we will look at it on a benchmark basis, we will look at it on an individual differential basis and will put together a cohesive program that will continue to help us mitigate that risk.

Kashy Harrison -- Simmons Energy -- Analyst

Got it. That's helpful. And then my out my follow-up question on page seven, you highlight the pro forma approved valuation, budget status, higher SEC price tag. I was wondering if you just help us think through what that GDP valuation would look like at more conservative prices, say $50, $55 if you have that sensitivity available?

Joe Gatto -- President and Chief Executive Officer

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 were 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.

Kashy Harrison -- Simmons Energy -- Analyst

That's very helpful. Thank you that's it for me.

Operator

And our next question comes from Sameer Panjwani from Tudor, Pickering and Holt. Please go ahead.

Sameer Panjwani -- Tudor, Pickering and Holt -- Analyst

Hey, guys, good morning.

Joe Gatto -- President and Chief Executive Officer

Good morning, Sameer.

Jeffrey Balmer -- Senior Vice President and Chief Operating Officer

Good morning, Sameer.

Sameer Panjwani -- Tudor, Pickering and Holt -- Analyst

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

Joe Gatto -- President and Chief Executive Officer

We have not used them yet. They are 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 in the longevity needed to maintain that partnership, but it's certainly something that we are taking a look at.

Sameer Panjwani -- Tudor, Pickering and Holt -- Analyst

OK. That's helpful. And then circling back to I guess there was an earlier question about how things would look at lower commodity prices. And I'm just trying to get a sense of how you think about prioritizing growth versus free cash flow and the preliminary budget you put out? Is that fair to use down to $50 a barrel-free cash flow or should we expect to generate free cash flow via lower activity levels should prices be lower?

Joe Gatto -- President and Chief Executive Officer

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 providers is critical, so that obviously something that we benefit from in a very meaningful way very tangible way to combined entity.In terms of the free cash flow versus growth, I think we have already spoken volumes about how we think about that, as Callon on a stand-alone basis, obviously, we had bit of a higher trajectory. But these combined entities, we are giving up a little bit of production for free cash flow and that is something as we move forward to navigate through pricing cycles that you'll continue to see from us.

Sameer Panjwani -- Tudor, Pickering and Holt -- Analyst

OK. Thank you.

Operator

And our next question comes from Noel Parks with Coker Palmer. Please go ahead.

Noel Parks -- Coker Palmer -- Analyst

Can you hear me?

Joe Gatto -- President and Chief Executive Officer

Yes, we can here you Noel. Please go ahead.

Noel Parks -- Coker Palmer -- Analyst

OK. Great. I was wondering, did you have any participation in an increase of operated drilling over the past year or two prior to starting on the deal?

Joe Gatto -- President and Chief Executive Officer

Nothing of known, no.

Noel Parks -- Coker Palmer -- Analyst

Ok. 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 positions? Does that get easier with the deal significantly?

Joe Gatto -- President and Chief Executive Officer

Well, certainly with expanded footprint or opportunity set for either monetization or trades and continue to core up like we've done on our footprint is expanded tremendously. In eastern [inaudible] and through Ward County, we have a substantial, continuous 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, 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.

Noel Parks -- Coker Palmer -- Analyst

Great. And if there -- I guess looking at the -- just the housekeeping question. Looking at the accounting going forward, you made a decision whether the combined companies are going to use two stream accounting versus three stream for the product mix?

Jeffrey Balmer -- Senior Vice President and Chief Operating Officer

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.

Operator

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

Joe Gatto -- President and Chief Executive Officer

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 any follow up questions but again, appreciate the time and look forward to updates as we move along in the course of the year.

Thanks again.

Operator

[Operator signoff]

Duration: 49 minutes

Call participants:

Mark Brewer -- Director, Investor Relations

Joe Gatto -- President and Chief Executive Officer

Jeff Balmer -- Chief Operating Officer

Jim Ulm -- Chief Financial Officer

Gabe Daoud -- Cowen and Company -- Analyst

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Brian Downey -- Citi -- Analyst

William Thompson -- Barclays -- Analyst

Kashy Harrison -- Simmons Energy -- Analyst

Sameer Panjwani -- Tudor, Pickering and Holt -- Analyst

Jeffrey Balmer -- Senior Vice President and Chief Operating Officer

Noel Parks -- Coker Palmer -- Analyst

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