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Callon Petroleum (NYSE:CPE)
Q4 2019 Earnings Call
Feb 27, 2020, 9:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:


Operator

Good morning, and welcome to the Callon Petroleum fourth-quarter and full-year 2019 earnings conference call. [Operator instructions] Please note, this event is being recorded. I would now like to turn the conference over to Mark Brewer, director of investor relations. Please go ahead.

Mark Brewer -- Director of Investor Relations

Thank you, Gary. Good morning and thank you for taking the time to join our conference call. With me this morning are Joe Gatto, president and chief executive officer; Dr. Jeff Balmer, 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 of today's presentation. We will make some forward-looking statements during today's call that refer to estimates and plans.

Actual results could differ materially due to the factors noted on these slides and in our periodic SEC filings. We'll also refer to some non-GAAP financial measures today, which we believe help 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.

Following prepared remarks today, we will open the call for Q&A. At this point, I'd like to turn the call over to Joe Gatto.

Joe Gatto -- President and Chief Executive Officer

Thanks, Mark. And as always, we appreciate everyone joining us today. Yesterday afternoon, we released our fourth quarter and full year results, which highlighted the operational efficiency of our fourth quarter activity and continued focus on driving down our cost structure to create consistent value through commodity volatility. As we discussed with the announcement of the transaction and now with formal 2020 guidance, the acquisition of Carrizo and integration of our development programs, improves our capital efficiency, lowers cash breakevens and provides more flexibility in capital allocation.

As a result, we've accelerated our time line to sustainable free cash flow, building upon our established trajectory into the end of 2019. Our integration efforts began on day one after the announcement of the combination, have proven fruitful as we have captured savings in both operations and G&A early in the year, positioning us to be well above our previously stated targets for 2020. The structural changes in how we operate and develop our assets will create durable savings that support our growing free cash flow profile, advance our absolute debt reduction and corporate return goals. Starting on Slide 3.

We had a very strong close to the year with stand-alone full year production at the high end of increased guidance for the year and total 2019 stand-alone capex of $501 million coming in at the bottom end of our guidance, which was lowered earlier in the year. In addition, stand-alone LOE came in just above $5.50 per BOE in the quarter, representing a decrease of 15% from the first quarter. At year end, we held over 500 million barrels of oil equivalent proved reserves with a PV-10 value of $5.4 billion. That compares to our current enterprise value of $4.4 billion based on average trading prices for February.

Our 2020 capital budget has been set at $975 million, which is well below previously communicated expectations and is a testament to the team's ability to identify opportunities to maximize operational and cost efficiencies and integrate our development plans into a more efficient, scaled model ahead of schedule. Callon's program is forecasted to deliver $100 million of free cash flow at $55 per barrel from average daily production of over 115,000 BOE per day, supported by our leading cash margins. You'll note that we are providing these figures on a three-stream basis, which is a new standard for Callon and a significant accomplishment that our finance and accounting team was able to deliver in a very short amount of time. Hats off to Jim, Greg and their respective teams for bringing that to fruition so early in the year.

Flipping to Slide 4. These four priorities were outlined over a year ago and have been advanced through our execution in the Permian and furthered by the Carrizo transaction. To begin, our return on capital invested is expected to meaningfully increase in 2020 with our new model of scale development driving synergy realizations and positioning Callon with top industry performers. A step change in free cash flow generation as our corporate breakeven cost of supply moves below $50 per barrel, an improved trajectory for gain free leveraging from both absolute debt reduction and credit metric gains it will be complemented by asset monetizations that are in process.

And a consistent long-term view for development of a substantial multi-zone resource base of the combined company that can be now efficiently codeveloped as part of a larger entity, improving near-term returns while preserving longer-term value. Our ongoing philosophy of blending near-term returns and longer-term value is a reflection of the responsible and proactive mindset ingrained in Callon's culture. Before we jump into the 2020 outlook, Slide 5 provides a visual history of our growth in the Permian. It has been driven by strong execution and a demonstrated ability to consistently deliver value from acquisitions.

On the top of the page, we've highlighted the consistency of our margins and cost management through commodity cycles, which has differentiated us from our peers. With a strong track record, we entered 2020 carrying a high level of confidence and our ability to meet and exceed our prior synergy targets as we identify additional areas for improvement throughout the organization and across all functions. We now stand with the Permian acreage position of almost 120,000 net acres and forecasted total production between 115,000 and 120,000 BOE per day in the upcoming year. The next page summarizes where we are today, a self-funded, high-margin oil growth company.

Callon's high-quality portfolio of assets can now be optimized through a balance of capital intensity, cycle times and returns to unlock a substantial Permian value proposition through thoughtful capital allocation and a consistent model for life of field development. So let's move to the tactical elements of 2020 plan on Slide 7. We entered the year with a drilled uncompleted inventory of over 60 wells as both companies reduced completion activity in the fourth quarter to prepare for larger projects. We were able to take advantage of this dynamic and integrate our combined plan sooner than anticipated since there was a relatively less independent Callon and Carrizo activity in motion during the fourth quarter, also allowing us to accelerate our DC&E synergies and immediately move to larger projects.

We're off to a strong start in the deployment of the integrated larger scale development model with over 20 wells placed on production in the last half of February from a 16-well project in the Eagle Ford, in a five-well co-development in the Delaware after initiating completion operations on both projects in early January. We are now building momentum in the Delaware as we approach the second quarter. The resulting impact will be strong double-digit sequential growth in the second quarter, which will carry through to the balance of the year as we move to more of a steady state of activity. 2020 will also incorporate our collective learnings from selective spacing tests in both the Midland and Delaware basins, with tailored up spacing in areas with previous development that Jeff will elaborate on here shortly.

While we are focused on the tactics for just one discrete year on this page, it represents the important initial step in executing our longer-term development strategy, one characterized by reduced rates of reinvestment to deliver growing free cash flow that will be sustained by thoughtful capital allocation and economies of scale. Let me be clear here. Our goal has been and will continue to be to maintain a long-term strategy to sustainably generate free cash flow while preserving our inventory value. We will continue to avoid the pitfalls of underinvestment in a high-return resource base.

Slide 8 summarizes the key operational and financial components of our 2020 outlook. As a reminder, all these data points are presented on a three-stream basis. And we've also provided some comparative data in the appendix to put 2019 results on a comparable basis. The collective teams worked hard to provide substantial reconciliation disclosure in the appendix as we understand the importance of transparency and communicating our achievements and forecasts.

To that end, we are forecasting approximately 7% comparable annual oil growth at the midpoint after adjusting for the Ranger divestiture on a capital budget that is was down approximately 10% from 2019 pro forma combined levels. As highlighted in the top left-hand chart, our capital efficiency for barrels of oil production added for $1 million of investment increases by an impressive 70%, including adjustments for our 2018 Southern Delaware bolt on and 2019 Southern Midland divestiture. This outlook incorporates our updated estimates for operational capital and corporate cost synergies, which compare favorably to our previous targets with year one operational capital synergies of over $45 million and G&A savings of over $35 million for a combined $80 million versus initial estimates prior to closing of $60 million to $65 million, which represents an increase of over 25%. At this point, I'd like to hand the call over to our COO, Jeff Balmer, who will kick off with some more detail on our 2020 program.

Jeff Balmer -- Chief Operating Officer

Great. Thanks, Joe. Slide 9 highlights some of the more important elements of our capital program for 2020. We've set a capital budget for the year of $975 million.

And much like last year, we will stick firmly to that number. As Joe just mentioned, we're running nine rigs and four completion crews to kick-start the integrated development plan, and for the full year, we expect to average between eight to nine rigs with three dedicated completion crews. We're expecting production to ramp up quickly through the second quarter, with an increasing number of larger projects placed online, driving an estimated 45% of our total production in the first half of the year. Our average project size will double relative to last year and is an important component of our strategy to drive efficiencies and optimize our resource capture.

As our development model matures through this year, the inventory of drilled, uncompleted wells completed early this year will be replenished with an increased weighting to the Permian Basin, providing flexibility and increasing our Permian activity into 2021. Here on Slide 10, we've put together an example of some of the critical elements of our plans to maximize the productivity and preserve value through our multizone co-development program. We've talked extensively about the need to pair certain zones together to recover resource efficiently and reduce future development issues. And that's something we'll continue to focus on this year.

After continuing to study well performance across the portfolio, we're up spacing in certain areas and employing some customized spacing to reduce unnecessary communication and avoid overcapitalizing projects across the assets. Another important element that we are continuing to watch carefully is the timing element of our program. We are keenly aware that allowing for too much time between completions can alter their recoverability in certain zones and ultimately result in less productive wells. Our program has accounted for this and seeks to manage that timing in the future.

In addition, drilling more parent wells and larger project designs will structurally mitigate this consideration to a large extent. So the implications of managing all these factors combined together is really fourfold. First, the obvious one is to reduce our well costs through co-development. The second is the compressed cycle times benefit us economically, and it also allows our crews to be more efficient.

Thirdly, better planning and consolidation of activity reduces the offset impact to historical production, both from a reach and timing perspective. And finally fourth, improved development timing can reduce the risk of poor well performance by managing the relationship between parent and child wells. On the next slide, Slide 11, we have a clear picture of the benefits from a capital program that utilizes simultaneous operations or sim-ops consistently throughout the Delaware. In the upper left-hand portion of the slide, we touch on some of the identified structural savings that became very durable in a program like this and drive significant capital reduction over time.

In the chart on the right, we've broken out the elements of what's helping to lower our Delaware well costs significantly year over year. Our realized cost savings from deflationary pressures combined with drilling and completion efficiencies that we captured over the course of 2019, produced over $150 per lateral foot of savings entering 2020, which gave us the starting point for our synergy scorecard. If you pair that with the synergy capture value that we have going forward, it adds significant value above what we estimated earlier last year, and you're rapidly getting down to some of the lowest cost per foot estimates for multi-zone development in this portion of the Delaware Basin. Moving to Slide 12.

The benefits that we've outlined are present across our entire asset base, and you can see this in the year-over-year cost improvements going back to 2018. The Delaware has witnessed the most dramatic changes, but that's somewhat related to the maturity of our operations in that area and the learning curve impacts in addition to our synergies. But looking across the board, we've continued to drive down costs in the more mature areas, such as the Eagle Ford, with an 8% increase from 2019, which further enhances the strong returns from this program, which has also benefited from the impact of larger-scale concepts over the recent quarters. Still, we are confident that there are additional gains to be made.

Better availability of local sand in that area moving forward should help and projects that are seeing additional timing benefits from an efficiency standpoint as project sizes continue to grow. In the Midland Basin, we continue to capture and swap for acreage in the Howard County area and have been able to extend laterals across this asset leading to lower well costs. In addition, changes to our completion design have allowed for productivity enhancements while simultaneously lowering completion costs. We also expect to see a slightly higher mix of activity in the Howard County area as opposed to Midland County this year as compared to 2019.

At this point, I'm going to turn the call over to Jim Ulm, our CFO.

Jim Ulm -- Chief Financial Officer

Thanks, Jeff. On Slide 13, you can see one of the critical elements of the Carrizo combination is the ability to drive meaningful free cash flow generation with a lower marginal cost of supply. You can see in the chart on the left, we forecast approximately $50 million of free cash flow at $50 a barrel with significant leverage to oil prices at $55 per barrel and above to drive additional cash for debt repayment. With regard to our contingent payments and receipts, 2020 marks the final year on an accrual basis that we may incur potential payments to third parties, and this is limited to $25 million.

We also have exposure to potential receipts if oil is above $60 per barrel in '20 and '21. Slide 14 shows that the business model we have built at Callon is predicated on using our operational expertise to drive strong margins from oily acreage and creating a trajectory of improving corporate-level return. You can see how we compare across the board on these critical areas against our peers. In the lower chart, we continue to screen as the leader among the group and EBITDA margins we generate, and we sit very favorably from a capital efficiency standpoint, something we would expect to continue to improve as our development program matures.

Managing the risk with what have proven to be volatile commodity prices is paramount to protect our cash flow and our ability to meet the goals Joe discussed earlier. We have continued to focus not only on diversifying our physical markets but in tailoring our hedging program to protect our oil prices at these various points. With over 70% of our first quarter oil volumes and 60% of the full-year volumes hedged at a floor of $55 a barrel, we feel very good about generating the level of cash flow and the types of returns that will advance our corporate goals. While gas accounts for a very small portion of our revenue, we have taken measures to protect realization in that area as well, focusing most recently on Waha basis swaps.

On Slide 16, over the course of the past year, we have taken numerous steps to bolster our financial position and optimize the value of our portfolio of assets. We were able to monetize over $300 million in non-core assets last year, and we are actively progressing efforts to generate another $300 million to $400 million this year between non-core asset sales and infrastructure monetizations. We've also talked a great deal about the benefits of our combination last year from a credit enhancement and liquidity standpoint. With our new $2.5 billion credit facility in place, we have ample liquidity, especially with a program that is projected to generate free cash flow at $50 a barrel.

In addition, upgrades by S&P and Moody's have placed us in a better position to opportunistically access the debt capital markets and further reduce our cost of financing. As we have no maturities over the next three years, we can be strategic and take advantage of market conditions to pursue these actions. Most importantly, we are actively pursuing an overall reduction in our outstanding debt and targeting a near-term debt metric of two times net debt to EBITDA by year-end 2020. At this point, I would like to turn the call back over to Joe.

Joe Gatto -- President and Chief Executive Officer

Thanks, Jim and Jeff, some very helpful commentary there. I'll pick back up on Page 17. Corporate sustainability is critical to our ability to compete among our industry peers and for investor interest across industries. We've incorporated this thinking into our operating approach as we have grown as a company over the last several years, spanning from areas such as deep saltwater disposal wells, water recycling, electrification projects and significant reductions in flaring.

We are also very proud of our achievements in fostering a safe work environment for our employees and vendors as evidenced by steady improvements in our reportable incident rate over the last two years, culminating with the 2019 rate at the top end of the industry. In addition, as managers of the business and stewards of investor capital, we must hold ourselves responsible for achieving positive outcomes that translate into shareholder returns. We've been proactive in evolving our short-term compensation metrics with the maturation of our business and introduce cash return on capital invested as one of the most highly weighted components last year. In addition, we recently added a TSR modifier for our long-term incentive program that reduces performance payouts if annualized TSR is below 5% and pays out at achieved performance levels if absolute performance is in the range of 5% to 10%.

Let me wrap up on Page 18 with a quick glance at what we've accomplished in just a few short years. Callon has evolved from a prudent acquirer of top-tier acreage positions to a capital-efficient operator that can effectively turn those top-tier assets and sustainable cash flow, competitive corporate level returns and per share growth across all key operational and financial metrics. While we are all proud of the team's operational performance and track record of integrating several impactful acquisitions, we remain focused on raising the bar of how we judge execution excellence to ensure continued differentiated performance for all of our stakeholders. We are off to a great start on our integration efforts, combining our operations into a singular development program to accelerate synergy value capture, and importantly, bringing together two organizations with united focus of delivering results in a safe and sustainable manner.

And to all of our employees on the call, I would like to once again express my deep appreciation to the entire Callon team for all of their hard work to achieve so much over the last two months since closing the transaction. I'm very excited to see what we can achieve together in 2020 and beyond. On that note, operator, will you please open the line for questions?

Questions & Answers:


Operator

[Operator instructions] Our first question is from William Thompson with Barclays. Please go ahead.

William Thompson -- Barclays -- Analyst

Hey, god morning Joe or Jeff. The slide deck mentioned expectations for a smoother production profile in 2021. I'm just curious if the long-term target is still 10% production growth with the Eagle Ford held flat, more or less flat at maintenance capex. Just help us understand how we can transition from the steep ramp through 2020 into 2021?

Joe Gatto -- President and Chief Executive Officer

Yes. We've talked about, obviously, with the acquisition over the next couple of years, a 10% type of headline growth rate. Yes, in 2020, we are ramping up relatively quickly. We did make the decision.

We could have put some single and two-well pads on earlier in the year to push production growth, but we obviously made the decision to do that in the most capital efficient manner, right, with larger-scale developments. We do have a bit of a ramp, but what we've talked about here over time is to get into a more ratable cadence of growth as we get to repeatable utilization of crews and deployment of frac crews and drilling rigs. So that will produce an outcome of, obviously, free cash flow growth and production growth over a longer period of time, and we are reducing our reinvestment rate in the business, offsetting that, and delivering production growth are going to be a function of a couple of things, right? It's going to be well productivity, continued capital efficiencies and moderating decline curves. Now over time, we can only push the limit so far on that.

So I would say, in the longer term, you will see overall production growth rates moderate a bit, but that will be with growing free cash flow generation.

William Thompson -- Barclays -- Analyst

And I think the deck also mentioned about 35% base decline on a BOE basis from January to January. Just understanding in terms of choke management and co-development. We've heard some of your peers talk about slower production ramps or obviously shallower base declines. I'm just thinking about in terms of how the implications could impact the production profile for the next two years?

Jeff Balmer -- Chief Operating Officer

Yes, the whole system is integrated together. So the way that we are putting wells online and going through our choke management process. Of course, it's captured in the full-year 2020 production profile and how it grows. Specifically to the wells that will be put online this year, we have incorporated some modifications to the way that we flow them back and that whether we call it slow back or pressure management or choke management, essentially it means that some of the initial IPs that potentially have been seen throughout the industry; we are generally going to avoid those because we see the longer-term benefits of the wells are maximized basically about 180 days, the cumulative production at 180 days.

A well that you take your time, flowing it back. The cumulative production at 180 days will be greater for a well that you take your time on a slow back versus a well that you open it wide open and allow it to maximize its production in the short term. Unfortunately, you would sacrifice the longer-term production by doing that. So the whole system is integrated with all these different components to it, but we are comfortable that we have the right flowback strategy in place.

William Thompson -- Barclays -- Analyst

Good. Thank you very much.

Operator

The next question is from Brian Downey with Citigroup. Please go ahead.

Brian Downey -- Citi -- Analyst

Morning. Thanks for taking the questions. First, perhaps, I'll start with a higher-level question for Jeff. So from Slide 10, it's clear that you've been thoughtful about the co-development and parent-child questions that are facing the industry.

I'm curious, given that you've been in your role at Callon for a little over a year now. If you have any key observations from development data you've seen in 2019. When you came out with the landing zone, co-development strategy you laid out there on the Slide 20, were there any specific surprises compared to your prior expectations on either the zone mix or configuration of those wells?

Jeff Balmer -- Chief Operating Officer

Yes, that's a great question. And this is probably one of my favorite slides I've ever seen in an investor deck because it does really represent a lot of technical detail, simplified into kind of a common sense, thoughtful approach, which I'm very encouraged that when I landed with Callon, we had already established that as a focus area. And then with the Carrizo integration, it was very similar in that. There was not a lot of degradation of the quality of the inventory due to mistakes that have been made by trying to drill unbounded home run wells.

And sometimes you have to drill those two to retain acreage in those items. So certainly, everybody has those. The discovery and the combination of the data, when we looked at some of the information that was available now through the combined companies really gave us a tremendous amount of insights and accelerated our learnings on all of the components that come into play within the development system, such as the distance between the wells both vertically and horizontally, the timing aspects of how long the well has been on production or how much voidage has occurred to that system. And how much of a detrimental effect will be realized when you put a well next door to it, and then also, there are some geological and geophysical properties that we were able to combine and take a look at that suggested some things that we weren't aware of, such as potential frac barriers, which might allow you to come back at a later time and drill more child wells that may not have such a negative implication if they're in completely different drainage systems.

So while the overall analysis remains kind of the same in the industry standards of it's better to get it all at once from a co-development, you don't want to wait too much, have too much time before you come in and drill your child wells. That's certainly something that I'm 100% in agreement with. The way that we're going about the program development out here is very thoughtful, and we have a great inventory in hand to continue that for many, many years.

Brian Downey -- Citi -- Analyst

Great. I appreciate that. And then, Joe, you'd mentioned the multiple asset monetization options to continue to progress. Could you just give us a reminder of where those currently stand both on the non-core properties? And then any updated thoughts around potential structure for the water infrastructure assets?

Joe Gatto -- President and Chief Executive Officer

Sure. Some of these have been in process going back to last year, a few, we kicked off earlier this year. So we have several things in various stages of progress. As it relates to the water midstream, as we've talked about, we're very much looking at that as a joint venture type of a partnership.

We're not looking to full fully monetize that and turn over the keys. It's a critical asset for us, and we're not looking for a sale leaseback that -- we monetize that asset and take back higher LOE, we are looking for more of a strategic partnership, and we've had some great dialogue. Not surprisingly, given where our assets are, people know that there's going to be a sustained development over time in that area. So we see a lot of interest there.

The other buckets, as we've talked about, the non-core Delaware and Eagle Ford packages. Also some non-op accreage and royalty packages out there. So the way we think about it is, let's have a lot of ways to be right. We have a target of $300 million to $400 million out there.

The projects I listed, if you added them all up, that would be in excess of that goal. So it's not like we have to get four or five of these done. If we can get a couple of them done, we'll get to our goals and that's critical in an environment like this, right? Some will -- some markets will get a little bit softer. There'll be some parts of those packages that will have sustained interest just given the nature of their profile.

So that is proceeding along quite well.

Brian Downey -- Citi -- Analyst

I appreciate the commentary.

Operator

The next question is from Neal Dingmann with SunTrust. Please go ahead.

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Good morning, Joe and Tim. My first question is on your activity. And I think you touched, Joe, around this a little bit already. In the release, you all suggest and talk about the materials second quarter production growth.

I'm just wondering, could you remind us potentially some of the pads that will contribute to this as certainly a large climb? And I'm just trying to get a sense, maybe a little bit of the earlier cadence this year to get a better idea?

Jeff Balmer -- Chief Operating Officer

Sure. And this is Jeff. The original kind of first quarter. As we mentioned, we're running four factories.

So you'll see a really nice ramp up toward the back end of the first quarter running into the second quarter. The second quarter and into the third quarter, you'll see the larger scale pad developments, primarily in the Delaware that will be coming online. And so these are the four-, five-, six-well development systems that will come on with a relatively large amounts of overall production. And they're put into the ground, again, with the progression of all the knowledge capture that we've made in 2019 relative to spacing and stacking and timing and those items.

So we feel very good about the production profile that we put forward.

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Got it. OK. Thanks Jeff. And then my second question really just on Slide 10, around the development optimization.

And really, what you'd mentioned earlier about the parent-child comment. Is this the driver, I guess. I'm wondering now when you decide on the total wells in a multi-zone pad? Or I know you kind of talked to the market in the past. A lot of this is this just based on just returns? Again, obviously, you're in a lower oil environment today than we were a month ago and a month before that.

And I'm just wondering, I guess, allowed is how this will change your thoughts about these multi-zone larger developments now that we're in a lower environment?

Jeff Balmer -- Chief Operating Officer

Sure. And that's a great question. But our company is planned on being successful at a low-price environment. And that's one way that we believe we're differentiating ourselves from other folks.

So the program that's in place does take that into account. Within a reasonable range of oil price outcomes, the development program would remain as it is, and there's two components of it. Obviously, the first one that you mentioned is spot on, which is driving value. So each well or each dollar that we spend has to have a dedicated, expected return on it.

But then the other one is maximizing the recovery of the systems. And so we don't anticipate going through and having to come back multiple years from now and having to drill infill wells to recover stranded hydrocarbons. So we try to combine both of those ideas in the overall program.

Jim Ulm -- Chief Financial Officer

This is Jim. I would put on top of that, obviously, is it will be coordinated in terms of how we think about risk management and hedging. We've obviously talked about diversifying our pricing points, but we will be very robust in our hedging and making sure that we have the ability to help protect that cash flow and continue the development program. You recall from my remarks earlier, we're really closer to 70% for the first half of the year and 60% for 2020.

We have followed a strategy in the past of layering in successive years, and we will continue to do that this year is the plan.

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Thanks Jim.

Operator

The next question is from Asit Sen with Bank of America. Please go ahead.

Asit Sen -- Bank of America Merrill Lynch -- Analyst

Thanks. Good morning. Just coming back to the PDP decline rate of 35%. And it looks like optically much better than some of your peers.

Could you update us on your maintenance capital of the combined company relative to, I think, the $450 million that you guys have talked about for CP stand alone?

Joe Gatto -- President and Chief Executive Officer

Yes, Asit this is Joe. Yes, as you point out the decline rate, I think we pointed that out is a differentiator and will continue to be one. And with the pressure management and strategy, I think that will add to that over time, especially if we get into more of a ratable pace of development, it will help as well. But in terms of a maintenance capital program.

This is always an interesting question because there's things that you can do if you wanted to high-grade all of your activity and go away from what Jeff had walked through, right? It's very central to our philosophy but maintaining our approach to developing the asset base for the long term, you're probably looking at a maintenance mode capital program of about $825 million to hold production flat.

Asit Sen -- Bank of America Merrill Lynch -- Analyst

Thanks Joe. And then entering the year, you have about 60 -- roughly 60 DUCs. What's the split of these DUCs between Eagle Ford and Delaware? And is this the normal level of DUC? I know you mentioned about shift over the next 12 months. Could you elaborate, please?

Jeff Balmer -- Chief Operating Officer

It's kind of roughly 50-50. There was a large pad in the Eagle Ford that just came online, 16 wells that Joe had mentioned that looks very good so far. But generally speaking, that's kind of the overall distribution of them.

Joe Gatto -- President and Chief Executive Officer

Yes. I mean, so as we go through the year, we will replenish that inventory, right, as we get, again, back to repeatable development, we will have a natural DUC inventory to give us operational flexibility. So exiting '20, you'd be looking at a bit over 60 gross wells, but the bias being a little bit more to the Permian at that point.

Asit Sen -- Bank of America Merrill Lynch -- Analyst

Thanks a lot.

Operator

The next question is from Gabe Daoud with Cowen. Please go ahead.

Gabe Daoud -- Cowen and Company -- Analyst

Hey, good morning, guys. Appreciate all the great detail so far. Joe, was hoping if we can maybe start in the Eagle Ford. That 16-well project, was there anything special going on there and do you anticipate future projects in the Eagle Ford being of that size? And then I guess, second part would just be, could you guys disclose, I guess, what the Eagle Ford did produce in 2019 or in '14-'19 so we could get a sense of trajectory in 2020 on that asset?

Jeff Balmer -- Chief Operating Officer

The 16-well project, I'll comment on that first, was a project that essentially took -- finished up a development hole, if you will, that was an opportunity where we had wells all around it. And we wanted to come in and kind of finish the cradle to grave program within that system. So of course, the Eagle Ford it's a single target. So kind of moving left to right and right to left, we put in a completion, a dual completion crews, so we could shorten the amount of time that some of the offset wells were impacted.

And so all those wells are now online and flowing back, and we've had the vast majority. I think the final two wells that were parent wells that were shut in, are also now back online and flowing. So overall, the system looks pretty good. And that is a pretty good representation of the types of projects that you'll see in the Eagle Ford going forward.

Joe Gatto -- President and Chief Executive Officer

And in terms of the production in the Eagle Ford, we talked about a maintenance-level production. So that's really what we're seeing. Last year, in the fourth quarter, it's got around 38,000 a day, 40,000 for the year in 2019, on average. So this year, as we talk about, we're looking at a similar 40,000-plus or minus for 2020 and after coming off of a lower point in the first quarter, there really wasn't any wells placed on production in the fourth quarter.

So you had a decrease in the first quarter. But with these types of projects coming on, we'll get back to some higher levels and average around 40,000 for the year.

Gabe Daoud -- Cowen and Company -- Analyst

Thanks guys. That's helpful. And just as a follow up, I guess, Jeff in the Midland Basin, you mentioned or I guess, you just mentioned overall the tweaking spacing here and there, but specifically in Howard, is the thinking that the Wolfcamp A is still developed on 10 wells a section and as you think about Midland County, the lower Spraberry, maybe about 13 wells section, which I think is historically how you guys were developing that zone. Just curious, I guess, if there's anything specific you could say to changes on spacing in the Midland Basin?

Jeff Balmer -- Chief Operating Officer

Yes, we're pretty consistent with our thinking in that, that if you're only going to go for a single zone, you could down space it relatively to the levels that you're seeing right now. Generally speaking, you'd see wider spacing prevalent across both Howard County and Midland County. So if you're moving into the 660 range would probably be a little bit more accurate unless you have very good geology, and you're doing all the wells at the same time across the system, which we have done before and had some very good success with it. The nice thing about the Howard County acreage that we have is that it was relatively greenfield.

So there is a lot of opportunity to come in and put in the correct initial development program right away so that we don't have the negative parent-child relationships or -- and we can kind of control our destiny through the proper density in that development program.

Gabe Daoud -- Cowen and Company -- Analyst

Thanks Jeff.

Operator

The next question is from Jeff Grampp with Northland Capital. Please go ahead.

Jeff Grampp -- Northland Capital Markets -- Analyst

Good morning guys. Another question on the asset sale front. Is it fair to think if you guys hit that $300 million to $400 million target along with the organic growth that you're expecting this year, does that kind of bridge you to that sub- two times leverage target in kind of a normalized, let's call it, $50 to $55 oil world? Is that a reasonable expectation?

Jeff Balmer -- Chief Operating Officer

Yes.

Jeff Grampp -- Northland Capital Markets -- Analyst

Got it. Easy enough. And then back on the PDP decline front, that 35% number over the next 12 months. Given that the asset base is still growing, does that moderate much if we roll that forward 12 months? Or how should we kind of think about that evolving given some of the development practices that you guys are incorporating?

Jeff Balmer -- Chief Operating Officer

I think it would be logical to assume it wouldn't change too, too much. When you're looking at a program that has a very solid foundation of over 100,000 BOE a day. The wedge program, is certainly a strong component of that but the base decline should be pretty solid overall. So I wouldn't anticipate major changes in that overall decline profile.

Jeff Grampp -- Northland Capital Markets -- Analyst

Understood. Perfect.

Operator

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

Kashy Harrison -- Simmons Energy -- Analyst

Good morning, everyone, and thank you for taking my questions. So my first question is for Joe. I hate to be the guy that reminds everyone about how crappy this market is, but clearly, we're in a challenging commodity environment given fears running COVID-19, the spots at $46, the hubs at $1.75, strips sub-50 through 2024. I appreciate that strategies are made in a week, and you all have obviously been very hard at this for two quarters now.

But can you help us think through what it would take for you to consider reducing activity? What would you need to see on the strip? Would we need to go sub-45? Just want to know how you think about the impact of the forward strip toward your activity moving forward?

Joe Gatto -- President and Chief Executive Officer

Yes, Kashy. A big part of this transaction,was to create a more scaled model to weather volatility that we're going to see like this, right? We've seen this over the last couple of years. Obviously, it's something that we manage not only with driving down our marginal cost of supply as well as what we do on the financial hedging front, right? So when you ask a question, is there a magic number that things change? When we get that question, you're only giving me part of the question, right? And we have to think about what happens to our cost structure. So when we have periods like this, we do have hedging that bridges us between different commodity price environments.

But if there is a sustained shift in the commodity price environment, that's going to be at $45 or below, certainly, we wouldn't be in a position to be generating meaningful free cash flow. And at that point, we would certainly look to change our plans and make sure that we were in a position where we were generating cash flow.

Kashy Harrison -- Simmons Energy -- Analyst

Got you. That makes ton of sense. So ultimately, just. It's all about the cash.

That makes sense. And then my next question -- sorry, go ahead.

Joe Gatto -- President and Chief Executive Officer

Yes. And again, just before you it's really hard to just say there's a magic number because we have to see where the cost structure could potentially go before you make a decision on how much to tailor the program. But I think the key point which you picked up is we would modify things if we saw we were not generating free cash flow.

Kashy Harrison -- Simmons Energy -- Analyst

That's very helpful. My next question is for Jeff. Again, I know it's obvious you guys are running extraordinarily hard to deliver on this plan. Just looking at the trajectory between Q4 '20 from Q1 '20.

It does, however, seem that, at least just looking at this industry over the last -- for the few years that I've been doing, which is not nearly as long as you, but just looking at the industry. Anytime there's a huge activity shift, it feels like there's generally challenges with cost control. And so I was wondering if you could maybe talk us through just some of your thoughts or controls or processes you have in place to make sure that you do, in fact, hit these DC&E targets that you've laid out in the presentation? And then maybe talk about any slack you've given yourself in the system just to take larger scale development into consideration?

Jeff Balmer -- Chief Operating Officer

Sure. That's a great question. The governance control on the cost structure is outstanding. So I anticipate that we will give a full review on every dollar that goes in and comes out of our environment.

But the nice thing about the combination of the two companies is that it's our same partnerships from a rig and completion service providers, as well as some of the cost structures that aren't quite as high dollar as the completion systems and the drilling side of things. But the idea behind combining the two companies at the beginning was to take the best practices from both companies, the best crews, the best synergy opportunities and combine those. And what we've seen so far already is that we have we have confidence that we're not only going to achieve the synergies that we thought we were going to and I'm speaking from an operational side, the G&A is also running right where we wanted it to be. But the operational synergies, we're going to overproduce what we had originally estimated.

And there are specific examples I could use such as our view of the chemical programs, where we can save money. We've made some improvements on our completion design, on our bit selection, on how we do drill-outs. All those items, you're already seeing some dollar savings at the bottom line that have been incorporated already within just the first two months of the combined company. So I feel very good that what we are planning on achieving, we will achieve, which will put us in the absolutely top-tier of the industry in a dollar per foot basis and from a capital efficiency basis.

I hope that, that answers your question. You had a comment on the back end of it that I'm not sure I fully addressed, but please let me know.

Kashy Harrison -- Simmons Energy -- Analyst

Yes. So the second part of my question was just you're moving that did answer my question, the first part of my question. The second part was just you're moving to larger-scale development in this year relative to last year. So I was just curious if there's maybe any slack in the forward guidance, just to take potential bottlenecks into consideration just from a planning process.

Jeff Balmer -- Chief Operating Officer

Yes, a very fair question. I don't anticipate any bottlenecks right now that the folks that we have working aren't just working with their heads down, we try to anticipate bottlenecks or squeeze points that might slow us down or cost us additional capital. And for the most part, putting together the two companies has allowed a larger degree of flexibility so that if we do anticipate a bottleneck or we see something that's going to come up, we can shift capital or activity into a different arena relatively quickly that will allow us to kind of take care of whatever the squeeze point is, move past it with very modest or no implications to the bottom line.

Operator

[Operator instructions] The next question comes from Sameer Panjwani with Tudor, Pickering, Holt. Please go ahead.

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

Guys, good morning. I guess, sticking with the theme of the last question. You talked about not anticipating any bottlenecks from a capital standpoint. But I guess, maybe on the production side of things, can you maybe quantify how much risking you are kind of baking in on the production side of things for these larger projects as you kind of shift to this new development design?

Jeff Balmer -- Chief Operating Officer

Absolutely. The way that we look at every project that we put in place is to take into account all the different variables that we have in place. So we take a look at the existing wells or the parent wells that we have, what each of the historic zones has produced, whether it's an unbounded well or a well that's had neighbors. Development programs that have been put in place historically, all at the same time or had variances put through.

And then we apply an appropriate level of risk. But really, the best way to describe it is we make a prediction of what we think each individual well is going to produce and then combine that into what the entire system is going to produce. So the forecast for each of the well systems or individual wells is accurate and that it takes into account all the different variables that each of the specific development programs needs to take into account. For instance, if you're going into a greenfield area that's not drilled up, and we put a certain level of spacing and stacking in a certain number of wells with a certain set of targeting sequences, that analysis would have a different level of outcomes than if you had to come into a system that had a series of parent wells already drilled into it and you were drilling offset into wells that were two years past the parent wells and were spaced at 660 feet or 800 feet away.

So each of the individual programs that we have has a specific process that we go through to allocate production.

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

OK. So it sounds like there's not necessarily maybe an increased level of risking that you're applying to 2020 program versus the 2019. It's just more, I guess, well specific or development project specific.

Jeff Balmer -- Chief Operating Officer

That's a very good way to put it. That's correct.

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

OK. OK, great. And then I guess the other thing I wanted to touch on was I wanted to make sure I understood some of the 2021 commentary correctly. I know you guys haven't put out guidance.

But I think when I kind of think about the 2020 program, I'm kind of backing into an exit rate of about 90,000 barrels a day of oil in order for you to hit your full year oil guidance. And I think what you mentioned was about 10% year-over-year growth in 2021, which would imply about 85,000 barrels a day of oil. So when I'm putting that together, it could imply exit-to-exit declines next year as the production profile smooths out. So I just want to make sure I'm not missing anything there.

And I'm thinking about all that correctly.

Joe Gatto -- President and Chief Executive Officer

Yes. We'll probably talk about math offline, but I think we've been consistent in terms of what we've put out there in terms of our expectations over the next couple of years. Obviously, the plan is getting kicked off this year in a strong way. And going into next year, we get some more ratable activity, get some more Permian bias to the program and feel like things will line up, as we've talked about, but we're not in a position to be talking about exit rates in 2021 as we sit here in February of 2020.

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

OK. OK. I guess, would it be fair to assume kind of to your commentary that we shouldn't expect a similar kind of Q1 to Q2, that kind of a jump in production, it should be more stable production in 2021, correct?

Joe Gatto -- President and Chief Executive Officer

That's correct. Yes. That's the point that we hopefully get across as you get into that more ratable activity that things smooth out a bit as you have just sort of repeatable utilization of crews and completion fleets going forward.

Kashy Harrison -- Simmons Energy -- Analyst

Got it. Thank you.

Operator

The next question is from Brad Heffern with RBC. Please go ahead.

Brad Heffern -- RBC Capital Markets -- Analyst

Hey good morning everyone. I just have a sort of an administrative question. You guys haven't historically reported this GP&T line. So I was wondering if you could walk through sort of the dynamics of what's going in there.

Is legacy Callon -- is the sort of pricing going to improve? Or is this just related to three-stream and NGLs? Or is it just related to the Carrizo operations? Any color there would be great.

Jim Ulm -- Chief Financial Officer

Well, I'll start, and then people can chime in. Obviously, one of the changes that Joe alluded to was that the three-stream treatment begins January 1 of '20. We attempted to kind of break that out for everyone to see for the 2019. So again, it does include we put kind of the straightforward LOE in there.

And then we've broken it out into the GP&T category and guided a range. Is there a greater detail you're looking for or what exactly are you looking for in the question?

Brad Heffern -- RBC Capital Markets -- Analyst

Yes. And I was just wondering if there's a dynamic where pricing is improving at the same time that GP&T line is getting added? Or if it's just something that's coming from Carrizo?

Jim Ulm -- Chief Financial Officer

Yes. Got it. So you will see higher revenue and then a zero EBITDA effect in the end.

Operator

This concludes our question-and-answer session. I would like to turn the conference back over to Joe Gatto for any closing remarks.

Joe Gatto -- President and Chief Executive Officer

Thanks, operator. Thanks, everyone for joining us on our first call as a combined company. As you can tell, we're off to a great start, and we look forward to talk to you in a couple of months on our progress. Thanks again.

Operator

[Operator signoff]

Duration: 58 minutes

Call participants:

Mark Brewer -- Director of Investor Relations

Joe Gatto -- President and Chief Executive Officer

Jeff Balmer -- Chief Operating Officer

Jim Ulm -- Chief Financial Officer

William Thompson -- Barclays -- Analyst

Brian Downey -- Citi -- Analyst

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Asit Sen -- Bank of America Merrill Lynch -- Analyst

Gabe Daoud -- Cowen and Company -- Analyst

Jeff Grampp -- Northland Capital Markets -- Analyst

Kashy Harrison -- Simmons Energy -- Analyst

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

Brad Heffern -- RBC Capital Markets -- Analyst

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