Logo of jester cap with thought bubble.

Image source: The Motley Fool.

Callon Petroleum (NYSE:CPE)
Q1 2019 Earnings Call
May. 07, 2019, 9:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:


Operator

Good morning, and welcome to the Callon Petroleum first-quarter 2019 earnings and operating results conference call. [Operator instructions] Please note this event is being recorded. A replay of this event will be available on the company's website for one year. I would now like to turn the conference over to Mark Brewer, director of investor relations.

Please go ahead.

Mark Brewer -- Director of Investor Relations

Thank you, operator. Good morning, and thank you for taking the time to join our conference call today. 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 earning 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 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 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 can 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 our prepared remarks, we will open the call for Q&A. With that, let's turn the call over to Joe Gatto.

Joe Gatto -- President and Chief Executive Officer

Thanks, Mark, and good morning, everyone, joining us today. Our first-quarter 2019 earnings results and operations update was posted yesterday after the market close and highlights our operational efficiency gains, steady evolution of the multi-well, multi-interval development and capital discipline. We've delivered on our promise of thoughtful capital allocation to drive sustained value creation and have also made progress reducing our capital intensity through rationalization of our asset base, including our previously announced agreement to divest our Ranger assets that brings forward value from less competitive inventory and importantly, streamlines operations. Our path to reaching sustainable free cash flow generation and achieving our leverage goals remain clear. We're already ahead of our schedule employing larger project concepts which will allow us to improve cycle times for our largest pads expected around midyear, accelerating capital conversion in the second half and into 2020.

With an improved outlook for oil prices relative to our $50 per barrel per planning deck, we now expect to achieve free cash flow generation as early as the third quarter of 2019 at current strip prices. Let me jump then on Slide 3 with an overview of quarterly results and activity. Production was ahead of our expectations on solid well performance despite reduced completion activity as we build out our DUC inventory. Our delineation efforts are paying dividends with solid performance from Middle Spraberry well in the Monarch area and positive early time results from our first 2nd Bone shale -- Spring shale well in the Delaware. Late in March, we began flow-back on our first five-well Wolfcamp A padded WildHorse, marking our first-half section development project on this portion of our asset base. Larger projects like this have become a normal course for our business, and we are benefiting from tangible efficiencies which generated 20% reduction in average drilling and completion costs compared to our 2018 average.

While all these are great data points, I think it's important to focus less on what makes for a strong quarter, but right around what makes for a strong long-term outlook underpinned by sustained investment fundamentals. The near-term performance objectives that management and the board have developed are firmly rooted in longer-term mandates that will increase corporate level returns through sustainable life-of-field development, and ultimately create shareholder value through balanced production and free cash flow growth. The four primary tenets are: Increase our cash return on invested capital and maintain above our cost of capital; allocate capital to support sustainable free cash flow generation under conservative pricing assumptions; utilize our free cash flow generation to reduce leverage in the near term; and explore other options for enhancing shareholder returns over time; and manage for the long term preserving the economics of our inventory in our high standards as an environmentally responsible operator. We firmly believe that this provides the strategic framework for not only a highly successful oil and gas business, but a successful business. Importantly, these aren't aspirational goals, we have meaningfully progressed on all of these elements and are positioned to further advance over the course of 2019. Turning to Slide 4, we've summarized our incentive goals for 2019 which squarely align with the long-term tenets of the business.

Over the past five years, Callon grew rapidly through both acquisitions of high-quality assets and substantial organic increases in production of reserves which established a critical mass of operations. These initiatives proved valuable on reaching where we stand today, but our forward trajectory as a more mature Permian operator requires a different focus to be successful and sustainable program development. Over the last two years, we evolved our corporate incentive metrics to align with the key drivers of shareholder value as Callon in the broader unconventional resource industry matures. As you could see on this page, there is a consistent theme of replacing growth-oriented metrics with those focused on corporate returns and capital efficiency. Moving to Slide 5, you can see a similar inflection point that has occurred in operational maturity.

Our shift to large pad development has led to a change in the way we manage activity, requiring DUC building that was a key focus for the first quarter. Efficiencies in capital savings that we are capturing from the transition to larger-scale development is shown on the bottom left-hand corner. These structural reductions in drilling and completion costs have been an important element in improving the return profile of our larger projects. At less than $1 million per thousand lateral feet, which includes a significant amount of Delaware drilling activity this quarter, we expect a significant uptick in capital productivity as we complete our DUC build and move to a steady-state model of multi-well pad development. On that note, our efficiency improvements, especially on the completions front, have allowed us to pull forward activity to the first half of the year.

This will shift the timing of capital spending from a previously expected balance between the first and second half of the year to more of a 60-40 split. It will not change our operational capital budget for the year, which remains firm at $500 million to $525 million as these efficiencies will limit the usage of our second completion crew and not increase our pace of capital deployment. In addition, our second-half spending will be reduced as we drop from six rigs to four rigs later this quarter. At this point, I'm going to turn the call over to Jeff.

Jeff Balmer -- Chief Operating Officer

Thanks, Joe. Moving to Slide 6, we were very active with the drill bit during the first quarter, drilling 21 gross wells during the period, many of which are associated with our large-scale developments both in the Midland and Delaware Basins. As Joe mentioned, we expect to release two rigs by midyear and bring in the second completion crew to help with our larger projects for a shorter period of time than previously planned due to the high level of completion efficiency that we have delivered with one crew. Our gross stages per day are up over 25% compared to the first quarter of 2018 and this has resulted in savings in overall completion costs, but also it's brought forward capital into the first quarter. In addition, we saw more non-consents from our non-operated partners earlier in the year with the downturn in commodity and prices late last year, and that resulted in slightly higher spending on various projects but also contributed to slightly more net lateral feet for the year which you can see in the chart on the upper right-hand portion of the slide.

This non-participation trend is abated, of course, as prices gained ground during the quarter and we believe it's unlikely to continue. We also participated in three high-interest, non-operated wells in the first quarter, and this spending represents over 50% of our firm non-op budget for the year. Once we exhaust that portion of the budget, we will not participate in much additional non-op activity for the year, but we don't believe that we'll be faced with any material amount of non-participation based on what we currently know about our partners' plans. On the lower half of this slide, you can see that capital deployment between the basins was relatively balanced. Some of this results from the shorter lateral lengths and lower completion costs associated with portions of the Midland Basin assets.

To the right, we've provided a breakdown of zone targeting by project with Wolfcamp A consolidating the majority of activity during the first four months of the year. Moving to Slide 7, we're very proud of how our Delaware program is evolving and the consistent and measurable improvements we're seeing in operational efficiency and the associated well reforms. To date, we've seen significant performance improvement in our wells as we continue to grow our knowledge of the area and gather data on what techniques or designs are providing the best overall outcomes. Again, I want to stress the importance of marrying both cost savings efforts with thoughtful well design to create the best final product. A very simple but relevant example has been our drilling team's ability to significantly reduce the need to change out BHAs or bottom hole assemblies. Given the relative depth of the Wolfcamp A in our portion of the Delaware, the need to trip out a hole and replace these essential pieces that can cost upwards of an entire day, during which we gain zero ground but incur significant cost.

The drilling team working with our vendors has been able to manage around this common issue resulting in significantly lower nonproductive days on site and ultimately reducing our well costs. These types of thoughtful changes, coupled with the continued shift to larger and multi-well designs, helps us drive more cost out of the system and create consistent repeatable results. Flipping over to Slide 8, here's a quick visual of just a few of the broader concepts and developments from this year's program. Starting in the upper right-hand corner, you can see that we have significant development ongoing in our WildHorse area with the recent completion and flow-back of our first five-well Wolfcamp A pad, which is currently performing above expectations. We've benefited from strategic trades that have allowed us to block up the position in our Sidewinder area where we will have multiple projects this year.

Our push toward maximizing resource recovery is reflected in our multi-interval development that were employed in this area during 2019 and beyond. Moving down to the Monarch area, our recent test of the Middle Spraberry as part of a multi-interval, multi-pad project has performed well and provides a good base of knowledge as to how we might improve co-development of the various economic zones in this area. We also will be utilizing full-section development of a single interval as part of our development program at Monarch over the coming months. Over the Delaware, we've provided two visuals of the largest pad concepts we will be employing during this year's program with a six-well co-development of the Upper and Lower Wolfcamp A and a five-well development involving the 2nd Bone Spring shale, Upper and Lower Wolfcamp A and Wolfcamp B. We will continue to move activity throughout the acreage position with wells in what we refer to as the river tracks and also a couple of tests involving Wolfcamp A and B co-developed areas. One of the most important aspects of this year's program will be the data and learnings that allow us to optimize the long-term development capacity and program designs to achieve the goals that Joe featured earlier in his presentation. And with that, I'd like to hand the call over to Jim.

Jim Ulm -- Chief Financial Officer

Thanks, Jeff. Looking at Slide 9, the relevance of our strong operating margins and the effect it has on our EBITDA growth over the past few years is obvious. A three-year compounded annual growth rate of 53% is one of the primary reasons we are in a position to reach a state of sustainable cash flow neutrality in the near term. If you look at the chart in the top right corner, you can see that our focus on managing operating cost has helped preserve our strong margins despite a greater than 20% decline in realized prices between the comparable periods.

The chart directly beneath also provides a visual perspective of how we have amplified our EBITDA growth from roughly $120 million in 2015 to just over $430 million last year. Revenue growth from increased production is the primary driver, but reducing unit operating costs is the lever that allows for outsize growth over that period. There were a number factors that go into creating those cost savings and the operational efficiencies that drive them. Over the past few years, we have overhauled our ESP management program and are seeing longer run times, reducing the number and frequency of work-overs required and improving field uptime.

We have made tremendous strides forward in our recycling program, and are not only reducing capital and operating cost with our improved program, but we are reducing disposal volumes and completion needs from local sources. Our focus on managing transport via affective pipeline tie-ins with proven operators has improved reliability, reduced operating costs and removed significant truck traffic from local roadways. Our substation build-outs and shift to grid power has eliminated the need for numerous diesel generators and improved our power reliability. And shifting to dual fuel rigs has not only reduced cost, but provided a positive environmental effect. Across the board, we are seeking to mitigate environmental and community impacts, but at the same time, drive enhancements to shareholder value. We will have more on these efforts soon with the forthcoming rollout of our ESG and sustainability program.

On Slide 10, we've provided a standard outlook on financial positioning which remains very solid. I will say it again, we are looking to generating free cash flow by the fourth quarter, and with current strip prices, we forecast we can be there as early as the third quarter. Our recent non-core asset sales are bringing forward value through monetization, as well as reducing some drilling obligations in 2020 that can now be replaced with more capital-efficient projects. We expect to close the Ranger sale in June, and we will provide an update on guidance at that time. We also recently completed our Spring borrowing base redetermination, which was affirmed at $1.1 billion and contemplated the removal of our associated Ranger reserves and production.

This speaks volumes to the quality of our remaining core assets and their value. All of these factors are important in contributing toward our achievement of reducing our leverage below 2 times net to debt -- excuse me, net debt-to-adjusted EBITDA in the near term. Leverage is the metric with the highest rating in our overall compensation program for 2019. Focusing now on risk management, our hedging plans have not really changed since they are derived from our belief that when market conditions allow, we have a responsibility to secure a floor in operating margins and retain as much upside as possible. That's been well reflected in our execution over the past few periods with puts -- and put spreads creating effective floors at attractive oil prices and allowing for participation in a rising price environment. Natural gas has been a bit of a different story with swaps employed to combat the relative weakness in the commodity, although the actual gas production accounts for very little of our revenue base with the flat NGL value driving the bulk of our non-oil revenue.

As we look toward 2020, the current backwardation in the oil curve has made it a bit less attractive to reach for longer-dated hedge positions, so we will continue to be patient and systematically add to our hedge position as the market provides liquidity at reasonable prices. One topic that has emerged as of late relates to oil gravity and the needs of refiners. As you can see in the lower right-hand graph on Slide 11, one of our banks has provided an overview of our relative oil gravity versus our peers. The simple takeaway here is that Callon's API gravity places us in a bucket of highly desirable crude producers in the Permian and should mitigate any risk of quality reductions. Moving to Slide 12, we have previously disclosed our agreement to add 15,000 gross barrels per day of firm transport to the Gulf Coast markets and the associated sales agreements that cover production that is tied to Brent in MEH pricing. We've also entered into an agreement for an additional 10,000 gross barrels per day of sales to Gulf Coast markets which is covered by firm transport and carries water-borne pricing very close to Brent pricings, but does not rely upon export for sales.

We are currently evaluating additional attractive opportunity to diversify our portfolio as early as the 2020 time frame. The reason we continue to push forward with these efforts is both for physical risk mitigation and the ability to enjoy advantaged pricing within these markets. Looking at the example on the bottom of the slide, you can see that based upon first-quarter pricing, we would have enjoyed roughly 13% upside on nearly 50% of our production were these agreements already active. To be clear, that's only using WTI-based pricing which does not account for the new push impact to the differential applied this past quarter, which led Midland pricing below WTI for the duration of the quarter. We believe this type of proactive portfolio management will provide us additional upside, while reducing pricing and transport risk as our production base continues to gradually increase. At this point, I would like to turn the call back over to Joe.

Joe Gatto -- President and Chief Executive Officer

Thanks, Jim. Slide 13 should look familiar to those of you who've been following the Callon story. It's been our closing slide for a few months now and represents our stated goals to the market as we entered 2019. I believe our results and the progress we've made show how our team is achieving these goals rapidly and with great success.

Execution and safety are still paramount and underpin our ability to achieve the rest of our goals. Jeff and his team are continuing to progress our efforts toward maximizing resource capture and mitigating parent-child impacts across the portfolio. Our past investments in infrastructure have demonstrated our dedication to social and environmental responsibility and will support our leading cash margins and drive our progress toward sustainable free cash flow generation. Our operational program highlights our commitment to the capital budget and advances us to free cash flow generation later in the year. Our work in the 2nd Bone Spring shale and Middle Spraberry, along with our various co-development concepts, drive ongoing organic expansion and preservation of our inventory.

And finally, non-core asset monetizations have reduced our capital intensity with several future opportunities for more activity on this front. At this point, that concludes our prepared remarks. Operator, I turn it over to you to open the line for questions, please.

Questions & Answers:


Operator

[Operator instructions] And our first question comes from Brian Downey of Citigroup. Please go ahead.

Brian Downey -- Citi -- Analyst

Great. Good morning. Thanks for taking my questions. Maybe I'll start with a question for Jeff.

In the release, in the slide deck, you said the improvement in average gross stages completed per day and continue the solid -- show solid and consistent drilling efficiencies on Slide 7 there. Could you comment on anything incremental you're doing maybe on the completion side? I know you'd mentioned less stripping out and bottom hole assemblies on the drilling side. But anything further you're doing there and what runway you see on both those fronts beyond the move to larger pads?

Jeff Balmer -- Chief Operating Officer

Sure. Yes. Thank you very much for the question. The way that we've approached drilling and completion, obviously, two different operations, but very similar in how we've approached them and that what we apply what we call a limiter theory so we look at all the ways, all the different pieces that combine the operational job that -- what we have at hand, whether it be moving pipe, people on location, the design of it, and then down to the actual physical processes on how we hook things up, whether to use different frack or what stages that we do in sequence with each other.

And what that's allowed us to do is identify areas for improvement. And without going into that the details upon that, what that allows you to do is kind of give yourself a true measure of -- you spend 15 or 20 extra minutes per job doing something that we could be doing concurrently with something else to make progress and you look for opportunities to eliminate those types of nonproductive times. And also what we've been able to do is apply some modest design changes in some of the development programs that we've had. For instance, you probably heard me say this before, if you're doing an interior well on a large-scale development, perhaps that well doesn't need as much sand and water as all the wells that are bouldering in on the other side.

So those are some of the opportunities that we've been able to capitalize on and have seen really remarkable improvements in the last six months, give or take, in an already pretty good program.

Brian Downey -- Citi -- Analyst

Great. That's helpful. And then given the Middle Spraberry and 2nd Bone shale delineation, could you provide any thoughts you have on that inventory, addition potential on how you you currently see those early results affecting your views on optimal co-development and zone mix over the medium term?

Jeff Balmer -- Chief Operating Officer

Yes. That's another really good question. It's pretty early right now. I like both of the wells so far. Anytime that you go into a new zone like that, you have to be thoughtful about your first -- the first results that you get out of that, and obviously there's a few folks that have done similar projects. But I -- what I doubt is that you drilled our best well yet out there.

So we'll look at what we've done, how we completed it, where we've targeted it, how the well declines over time, what types of lifting mechanisms look the best. And then do an assessment of the viability of that -- each of those zones as in economic targets. Certainly, there's some beneficial areas when you're doing those developments concurrently with other wells. There is some cost savings associated with that, both on the drilling and on the frack side.

So that makes the targets even more attractive. It's probably too preliminary to go down the inventory road right now with either of those two zones.

Brian Downey -- Citi -- Analyst

Excellent. I appreciate it. Thanks, everyone.

Operator

Our next question comes from Neal Dingmann of SunTrust. Please go ahead.

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Good morning, guys. Nice quarter. Joe, my first question, just looking at your operational efficiencies, it's definitely notable you've got an improvement that you're all seeing, especially I think you, in the prepared remarks, talked about dropping a rig previously now quicker than previously projected. So aware that you'll don't have the 2020 guidance out, I'm really just wanting in broad terms how you are thinking about up your -- the upcoming year's growth and free cash flow, especially if these efficiencies remain strong as they appear to be now?

Joe Gatto -- President and Chief Executive Officer

Yes. Thanks, Neal. So good observation. Obviously, we're happy with the efficiencies we're seeing.

I mean, as I've mentioned, these are structural and really linked to the nature of how we're tackling the asset base with larger pad developments. But I'd say, in large part, we expected to do this. We have seen the benefits from large pad development previously in Midland Basin as we're employing it across the larger swath of our acreage, we're seeing that flow through. But obviously, we're not going to be satisfied with where we are.

We hope to drive more as time goes on. And that certainly has good implications for 2020. You know we're not going to bake that in at this point, but certainly, we're off to a good start in delivering on our large pad development program. Let's talk about 2020. We've mentioned some outlooks for this in the past.

We have talked about double-digit production growth and being at free cash flow neutral for the year around $52.50. We are going to be losing some cash flows from Ranger, obviously. If you do the simple math and take those cash flows out, that is offset by paying down debt and potentially preferred issuance. That makes back some of it, but we still have a little bit of work to do to get back that $52.50 and we have a couple good ways to do that.

One is on Ranger -- removing Ranger, we remove some drilling obligations that we have down here in 2020, which gives us a little bit more operational flexibility to move to more capital-efficient areas on our asset base. We've talked about some of the pricing uplifts that we expect to get from our marketing arrangements as we move to our -- our pricing points away from Midland. We're looking at some more of those and those should continue to help our price realizations in 2020. And finally, we've made a -- it's not a huge number, but roughly $50 million of acquisitions in minerals rights over the last couple of quarters that will be folded into our program and provide an uplift. So as we look at 2020, you add all that together, we're hoping we could provide some more formal guidance on that year, we're probably close to where we started before divesting Ranger.

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

OK. Great. And then just secondly, just looking at the PoPs, I'm just wondering is your -- I just want to double check, is your net lateral PoP feet in each half of this year is the same as it was in your initial budget? Really, I'm just looking -- I think it's the chart on -- it's on Page 5 here. And it looks to me like it's the same, but I just want to double check that the lateral feet PoP in each half of this year is the same as what you were previously thinking about. Thank you.

Mark Brewer -- Director of Investor Relations

Hi, Neal. It's reasonably the same. There's some small nuances there. I think we are seeing a slight compression of the schedules.

So what you'd probably see is a slight shift forward in the actual completion schedule due to the time these are going to come on. They'll come on a little earlier but it's a little earlier in the third quarter, it doesn't necessarily cross over into the second quarter.

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

OK. But it looks like then, Mark, what, for the -- each half, it looked to be relatively the same, just a little shift on timing results?

Mark Brewer -- Director of Investor Relations

Yes. No, from the actual PoP standpoint, yes. From the completion timing, you have a slight shift forward, which intra-quarter, it's not going to show itself on that chart, but it is a little bit ahead of its schedule.

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Very good. Thank you all.

Operator

Our next question comes from Derrick Whitfield of Stifel. Please go ahead.

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

Good morning to all. Congrats on the strong quarter and update.

Joe Gatto -- President and Chief Executive Officer

Thanks, Derrick.

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

Perhaps for Joe. M&A has been a topic of increasing interest among investors. Based on your background and the strength of your operations, could you share your views on the merits of zero premium mergers among the mid-caps to create advantage for pro forma companies with scale on material over at synergies?

Joe Gatto -- President and Chief Executive Officer

Look, it's a pretty topical time to be asking that question. If you look historically and look at M&A in the space, a lot of it's been driven by adding inventory for large part in terms of giving more of a runway to companies and putting companies together adds more of a runway. What we're seeing now in the unconventional space is a little bit different. Certainly, companies like ourselves have a lot of inventory to work with, so your case is around -- really around synergy, you point, and some are a little more tangible than others in terms of G&A, although this is a people business and you can't approach a deal and say, we're just going to take all the G&A out and everything's going to be good.

We all need good people, companies our size going forward, to get into softer synergies in terms of well, just because we're bigger, we're going to get all the scale efficiencies. And there might be some places that are a little bit more tangible than others, but I think we all need to be thoughtful about when we're thinking about combinations, what those synergies are going to be versus just saying, well, we're bigger, we're going to be better. We always say that better is better and being focused on the operations. There's no question that there's a critical mass that you need to be efficient and have a good vendor relationships.

We think we're squarely there at this point but that doesn't mean that there can be opportunities for combination to get real operational synergies. And pulling some of the concepts that we're doing on a larger asset base, I think, is a more reasonable thesis.

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

Very helpful. And perhaps for Jeff, as my follow-up, and this is really responding to an earlier question and his response. How much lower could you drive cost per foot and your limit various estimates?

Jeff Balmer -- Chief Operating Officer

Got you.

Joe Gatto -- President and Chief Executive Officer

We're all looking at Jeff.

Jeff Balmer -- Chief Operating Officer

Yes, I know. I guess I'll approach that, too, and invoke we're never satisfied so that the wonderful thing about working with this team is once you reach a new bar, you're going to set another one that's a little bit higher. And what Callon has been able to do is be one of the premier producers and developers in the Permian Basin, and that comes from a large number of very easily identifiable variables and cost, of course, and efficiencies is one of the big drivers of that. And so I would anticipate that we're going to continue to make some progress on there.

The one item, of course, that's very important is that we've achieved that here in the first quarter and now we need to maintain that throughout the rest of the year. So that will be the focus for making sure that what we have done and accomplished is carried through, and as we get into different well mixes and move a little bit more into the Delaware in the back half, those operational items can shift a little bit and we need to just make sure that we're paying attention to the top to bottom cost efficiencies and safety programs that we're really focused on. But I would anticipate that our team is going to continue to focus on making those cost savings happen.

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

Very helpful. Thanks for your time.

Jeff Balmer -- Chief Operating Officer

Thank you.

Operator

Our next question comes from Brad Heffern of RBC Capital Markets. Please go ahead.

Brad Heffern -- RBC Capital Markets -- Analyst

Hey, good morning, everyone. I was just hoping you could give an update on your thoughts on spacing right now. There's been a lot of talk about both up-spacing and down-spacing it in various parts of the Permian. So however you'd like to attack it, maybe by region or just more broadly?

Jeff Balmer -- Chief Operating Officer

Sure. Each of the variables that comes into spacing and stacking plays a pretty good component into it. So you've got the timing of the wells that are put in, the vintage. You have the number of targets both vertically and horizontally.

And then you have what the completion design is going to be. We really like what we've done so far from a spacing and stacking perspective. I've used this word before, this phrase of a thoughtful development program. So within what we've done, you'll see variances within the different reservoirs based upon where we are and the maturity level of those development programs.

So for instance, in areas where we've got existing developments, you may see some modest changes and opportunities where we applied different spacing and stacking there versus when coming to a more greenfield or virgin reservoirs where we may have an opportunity to be a little bit more aggressive or are working with the co-development programs that we've been discussing throughout the last year or two.

Brad Heffern -- RBC Capital Markets -- Analyst

OK. Thanks. And then, Joe, you talked about the minerals acquisition that you've done over the past couple of quarters. Can you just talk about what the decision points are as far as going out and acquiring those? Is it just the knowledge that you have over where you're going to be drilling next? And then has it made a meaningful difference in terms of the corporatewide NRI?

Joe Gatto -- President and Chief Executive Officer

It's certainly a space that's attracted a lot of attention from private capital. I think you hit it pretty well. I mean we should have a asymmetry of information which puts in a position to look at minerals opportunities on our existing leasehold and we have a good view of the next three to five years of development where we're going to be focused so we can put a pretty high hurdle on the cost of capital just because -- given the opportunity set that we have, the high bars for any sort of acquisition at this point. As you know, minerals do drive a lot of value.

So we're going to stay focused on it. Now that being said, there's a lot of times that we don't win every deal, which is interesting given our cost of capital relative to private operators and the fact that we know when we're developing the asset. But that's gives you some indication that there's spots that it's just going to get away from you and you can't chase it. You've got to be disciplined in terms of acquiring it.

In terms of the broader uplift, you're going to see more of that over the next year or 2. In terms of introducing that more, we've been assembling more of a minerals position on both sides of the platform for the last year or so. So it hasn't shown up quite yet, but as we get into 2020, I think you're going to see more of that in that NRI uplift that we'll talk about a little bit more once we put that 2020 plan pro forma in place.

Brad Heffern -- RBC Capital Markets -- Analyst

Thanks.

Operator

Our next question comes from Gabe Daoud of Cowen. Please go ahead.

Gabe Daoud -- Cowen and Company -- Analyst

Hey, good morning, guys. Maybe just following up on a little bit on the prior question. Maybe specifically in Howard County, can you just talk a little bit about multi-interval co-development across the Lower Spraberry, Wolfcamp A, Wolfcamp B. Just thoughts around spacing with those three zones over the next couple of projects. And then finally there, how do you guys think about the zones beyond those three, specifically the B and Wolfcamp C given results from one of your peers?

Jeff Balmer -- Chief Operating Officer

Sure. Just taking a few notes to make sure I can answer the question in a robust manner. The -- similarly to what I had mentioned before, we don't have a one-size-fits-all development program that says we won't come out and declare that the Wolfcamp A gets x amount of wells and the Wolfcamp B gets y amount of wells in those areas. So again, there's a number variables that come into play out there that the B has potential, the Wolfcamp B, and it -- to some extent, there are some nomenclature considerations where we may call the Wolfcamp C, what somebody else calls the Wolfcamp B, etc., but there is opportunity to co-develop through Lower Spraberry, Wolfcamp A, Wolfcamp B certainly, and we'll be investigating those items to unfold again.

Being thoughtful about it, but also trying to do -- including development programs in where we also gain the operational efficiencies of having larger scale pads as opposed to single-well operations.

Gabe Daoud -- Cowen and Company -- Analyst

Thanks, Jeff. That's helpful. And then as a follow-up, I guess, it looks like you're ahead of schedule here on the DUC inventory build. Could you maybe just comment on what you think the optimal level of DUC inventory is that it seems to support larger pad sizes as you move through '19 and into '20?

Jeff Balmer -- Chief Operating Officer

Well, I think it's what we're doing. Kind of the proof is in the pudding that we've got a rig out there doing two, three maybe the maximum will four wells per rig. And we have a nice flexible contract that's a win-win with a primary vendor so they can come in and give us some assistance while we need to work out that backlog of inventory. So I don't see any real changes relative to what we got in the ground and the program that we have in place, which is going to be relatively consistent with what I think we're going to go forward to into 2020.

Gabe Daoud -- Cowen and Company -- Analyst

Great. Thanks, Jeff.

Jeff Balmer -- Chief Operating Officer

Thank you.

Operator

Our next question comes from Mike Kelly of Seaport Global. Please go ahead.

Mike Kelly -- Seaport Global Securities -- Analyst

Hey, guys. Good morning. Mark, I was hoping to get just a better sense of how we should think about production and capex for the second quarter. And I know you've got kind of a few variables at play here if you could complete these larger pads, I think you mentioned in the press release you have a bit of production shut in for that as well in the Delaware. So just trying to get a little bit straightened away on those key metrics for the second quarter. Thanks.

Mark Brewer -- Director of Investor Relations

Yes. For the second quarter, obviously, we haven't -- we don't give quarterly guidance. All those have been our annual guidance. We know we owe everyone an update on post-Ranger once we get that closed.

But broad strokes, yes, we are on the tail end of the Delaware optimization efforts. That's a little bit of a headwind. But obviously, we'll lose some barrels from the Ranger sale in June when we expect that to close. And we're running one cracker at this point.

And -- well, we won't see the impact of that until early the third quarter. So if you add all that up, that's something that's relatively flattish to down a little bit in terms of volumes. Capex, given that we are -- most of it, the quarter, to be running the six rigs and we're coming down to four later in the quarter, should be somewhat similar to where we were in the first quarter. We talked about 60% of the capital being spent in the first half versus 40 in the second half.

We spent roughly 30% or thereabouts in the first quarter. So that's backing into the math there for you.

Mike Kelly -- Seaport Global Securities -- Analyst

Appreciate that. Switching gears to the productivity gains that you've seen in the Delaware. I just want to get a sense what you think is really the biggest driver of that in that? Also curious on the sustainability of those gains and if we're sitting here at the end of 2019 and we look at those -- the the average for 2019 wells being compared to 2018, do you think there's really the ability to see wells this year be 40% better than what you've seen in '18 and '17? Thanks.

Mark Brewer -- Director of Investor Relations

I think that it's exciting when you look at the well productivity improvements out there that the Delaware is a less mature basin both from within Callon's portfolio and then across everybody's portfolio. And when you look at the opportunity to make meaningful impacts like this, it's extremely exciting. If it's sustainable? I sure hope so. I think if you go into larger full developments where you're maximizing recovery and optimizing value, you'll see some of the same, similar things probably that you saw on the Midland Basin or there was the well productivity when the wells begin to talk to each other a little bit and it'll flatten down a little bit.

But I do think that there is optimization that can occur on the completion designs, on targeting, the spacing and stacking. So the opportunity in the remainder of 2019 and beyond is very positive right now.

Mike Kelly -- Seaport Global Securities -- Analyst

Great. Thank you.

Operator

Our next question comes from Kashy Harrison of Simmons Energy. Please go ahead.

Kashy Harrison -- Simmons Energy -- Analyst

Good morning, and thanks for taking my questions. So Joe, this year you budgeted your capital program based on $50 oil and you received the benefit of higher oil prices. If you think about the medium term or the next several years, do you see yourself effectively sticking to a, call it, a $50 to $55 pricing range? Or do you think that as you get closer to each budgeting season, you would predicate that budget for the strip of that year in question?

Joe Gatto -- President and Chief Executive Officer

I think we're pretty square early on what we outlined a $50, $55 world. That's pretty much what the back of the curve continue to tell us and our views of what really the long-term marginal costs of supply is in the day. So if we do better than that that's great, right? We have some leverage to take down beyond that. There are some other initiatives that we can look at to return capital to shareholders or look at expanding from an A and B perspective, we're talking about minerals, there's all sorts of things in terms of value-adding initiatives.

But in terms of where we're going to budget, there won't be any change at $50, $55 because you've got to think about the long-term fundamentals. And what we've seen over last few years, we can see volatility move pretty quickly, we still think it's going to come back in that $50, $55 range. But if you budget for a higher price, then you're subject you having to pull back activity if you want to maintain your free cash flow goals, we want to have a more steady state of measured growth over time and be able to walk through those cycles without people looking at us and saying, "Well, when are you going to lay down activity?" If we budget those ranges, I think we're in better shape to outline the longer-term value proposition.

Kashy Harrison -- Simmons Energy -- Analyst

Yes. That makes sense. And then second one for me. Just great work, to use your term, rationalizing the portfolio with the recent Ranger divestiture.

I was wondering if you could discuss maybe any other assets within your portfolio where you can accelerate value to shareholders, maybe on the water side of the equation the market does seem to be heating up. So is there anything in your portfolio that you're seeing that could be a way up in terms of monetization?

Joe Gatto -- President and Chief Executive Officer

Sure. A couple of key buckets. One is going to be around non-operated, non-core acreage in the Delaware is probably a pretty big piece of an opportunity set there. If you look at our map, there's some acreage that we picked up.

There's some really nice sections, but they're just one section. Now if we don't see a way to build that out a little bit more, we're never going to be able to get capital efficient from a full cycle standpoint that's going to make sense and probably makes better sense in someone else's hands is an outright monetization or a storage candidate. So that's probably a decent pool there. But as you mentioned, the water business, it's certainly one that we continue to evaluate.

It's not something that we will rush into just because the market is clamoring for it. It really is going to be thoughtful because we've spent a lot of time and money in really being proactive on this part of the business that has paid dividends in terms of reliability, economics and environmental responsibility that I don't think people appreciated. And so as we sit here today, we have a valuable asset. What we won't do is just monetize it in the near term for the expense of long term.

We've put these assets in place for the liability in our operations and that's going to be first and foremost on the list. But that being said, I think over time, there'd be some opportunities to take some capital out of that business and still preserve our objectives.

Kashy Harrison -- Simmons Energy -- Analyst

Thank you.

Joe Gatto -- President and Chief Executive Officer

Sure.

Operator

Our next question comes from Tim Rezvan of Oppenheimer. Please go ahead.

Tim Rezvan -- Oppenheimer -- Analyst

Good morning, folks. I appreciate you all laying out the discretionary compensation numbers in the slide deck, and I wish really all companies did that. I wanted to push on the leverage topic as it has significant weighted at 15%. Joe, can you kind of walk through specifics on what those bogeys are that management incentivized to hit this year?

Joe Gatto -- President and Chief Executive Officer

Yes. So Tim, we haven't given those specifics, just how that interplays with guidance and things like that, but I can tell you -- and Jim mentioned this in terms of our longer-term goal the next several quarters as we get leverage below 2 times back. That's not going to be next quarter. Obviously, Ranger is a first step toward that.

I think staying disciplined and taking cash flow to the balance sheet as we get in the later part of this year, the next year will be important. But at this point, Tim, that's all we can we can talk about now. Jim, do you want to add to that from your standpoint, but we haven't disclosed the actual metrics at this point.

Jim Ulm -- Chief Financial Officer

We haven't disclosed it, and as Joe is saying, there's a range of different metrics there. The one that we'll be focused very natural on is how do we get that leverage down to a place that we're more comfortable with. We've said less than 2 times, and frankly, our ability to do that will also help tie into the sustainable free cash flow model that Joe's referring to earlier.

Tim Rezvan -- Oppenheimer -- Analyst

OK. Thank you. I appreciate this comment. And then if -- as a follow-up, the comments you gave on the uplift, you will be getting from the FT. If we think about crude prices and spreads staying where they are, do you anticipate your un-hedged realizations to be kind of 100% or more of WTI next year? How should we think about kind of that -- it's a margin game and it seems to be really impactful on kind of 2020 realizations?

Jim Ulm -- Chief Financial Officer

It is, Tim, and that's a very good question. I was sitting and thinking during the call as we talk about different objectives. One of the things that Joe mentioned early on was doing what we can to help improve price realizations. We talked about being conservative in our budgeting in the $50 to $55, but the hedging and the price point diversification will hopefully help us realize prices above those levels and move us closer to free cash flow.

So as we stand right now, we have a good hedging position in 2019. We'll opportunistically look to add to that and we're starting to layer in 2020. And that will involve a whole range of WTI, Brent and other places. I guess the last observation I would make there is as we're also more on liquid points should have better price discovery as we think about hedging and so it'd be an integrated approach that will hopefully give us additional revenue into that cash flow calculation we've been talking about today.

Tim Rezvan -- Oppenheimer -- Analyst

OK. Thank you for those comments.

Operator

Our next question comes from Sameer Panjwani of Tudor, Pickering & Holt. Please go ahead.

Sameer Panjwani -- Tudor, Pickering, andHolt-- Analyst

Hey, guys, good morning. You mentioned a guidance update coming in June, but given the efficiencies you're seeing, is there a chance we could see your 2019 capital budget trend lower as savings go through? Or could we see incremental wells placed on production this year while leaving the overall budget unchanged?

Mark Brewer -- Director of Investor Relations

Hey, Sameer. This is Mark. I think there's always that hope that we could achieve that. I think with only one quarter behind us, it's probably a little early to kind of lean in that direction.

We do provided a guidance range of $5 million to $525 million on operational capital front. I think you saw what we spent was roughly 30%. I think we're pretty comparable that our our goals are very achievable. As with anything else, if we do everything that we're supposed to, I think theres always some upside on the table, but I wouldn't -- I don't think we're in a position to make any call on that at this point in time.

Sameer Panjwani -- Tudor, Pickering, andHolt-- Analyst

OK. And then secondly, as you progress to free cash flow later on this year and into 2020, obviously, the marketing agreements play a pretty big role in terms of enhancing the margins. But can you walk through the uplift you expect for some of your other initiatives like the water system build out and the Delaware optimization project?

Jeff Balmer -- Chief Operating Officer

I'm sorry, were you looking for efficiencies or cost saving? Just let me double check to make sure I'm clear on your question.

Sameer Panjwani -- Tudor, Pickering, andHolt-- Analyst

Yes. So cost savings in terms of enhancing the margins.

Jeff Balmer -- Chief Operating Officer

Sure. Yes, the recycling program that we have in the Delaware is fantastic. It's already well advanced. That was one of the very attractive things about coming over to Callon, which was how seriously this chain takes, not just the cost items but the environmental responsibility side of things.

So that's going to continue to be a focus area for us. So we had mentioned here in Slide 6 that we've got an additional rollout of a treatment plant that's in our kind of southeastern asset zone in Delaware that, combined with this new pond that we have, that will add another 350,000 barrels of storage. The plant have to be able to deliver -- the two areas are called Lober and Lasso. So we'll be able to deliver recycled water to complete all those new wells for some of the new acquisition down in what we call the river tracts.

It's got a 14-inch buried line. So it gives us the flexibility of moving recycled volumes both north and south between the whole asset. So when we look at the infrastructure that we had in place and what was added into that, we'll continue to see what's already a good recycling program increase. And you're probably getting a $0.50 to $0.75 a barrel savings for every barrel that you can reuse.

Sameer Panjwani -- Tudor, Pickering, andHolt-- Analyst

OK. That's helpful. Thank you.

Operator

Our next question comes from Will Thompson of Barclays. Please go ahead.

Will Thompson -- Barclays -- Analyst

Hey, good morning. Just a follow-up on the capex cadence. Typically, capital efficiency has been a good thing, but given The Street seems to be quite sensitive on front-end loaded capex budgets, maybe help us understand what gave you confidence that Callon won't run hot on the capex budget in the second half of the year? And if I recall correctly, you had planned to add a second dedicated completion crew in the second half of the year. It sounds like maybe you can now complete the program with one crew, maybe backfill that with a spot crew and any additional color there would be helpful.

Joe Gatto -- President and Chief Executive Officer

Yes, that's exactly right. We talk about bringing in the second completion crew to help with the larger pads and running simultaneous operations. So when we're moving to larger pads, we're not giving up cash conversion cycles. But you're right.

I mean, we're still bringing back a second crew, which was bringing back for less period of time just given how efficient we have been that first crew. So we're using those efficiencies from the first crew to reduce our need for a second crew versus accelerating capital allocation during the course of the year.

Will Thompson -- Barclays -- Analyst

And then is it fair to -- the completions are being been -- is it fair to assume that the completion efficiencies are being driven by the increase in the per fracks aided by larger pad development? And if I recall it correctly, you got some pricing concessions for your frack crew provider late last year. I guess is it fair to assume that the 50% sequential gain in D&C cost per thousand feet is simply being driven by more aforementioned efficiency gains and therefore, more structural than typical?

Joe Gatto -- President and Chief Executive Officer

Those are all 100% true statements. There's also improvements that we got on the water which we had highlighted a little bit, realizing the usage of local sand, and then modifications to the design, the actual designs on the wells. But yes, everything that you said was a -- is a big driver that adds to the overall cost reductions and combined with the overall efficiency gains.

Will Thompson -- Barclays -- Analyst

OK. And then one more quick one for me. I think you exited 1Q with 21 gross DUCs. How should we think about the appropriate documentary per rig as you transition to larger pad development?

Joe Gatto -- President and Chief Executive Officer

Let me double check and make sure I understand the question.

Will Thompson -- Barclays -- Analyst

Yes. I mean I'm just trying to get a sense of like what a normalized inventory per rig should be as you move to larger pad development.

Joe Gatto -- President and Chief Executive Officer

Sure. Yes. Like I mentioned a little bit previously, you'll see that kind of ebb and flow with this, so we build up a little bit of a DUC inventory for two reasons. The first one is to make sure that all the learnings that we're uncovering as the older wells are on production and giving us data, we can make sure that we translate those into actual improvements when we go in and basically complete the wells. And then also it the makes us efficient on our existing completion operations so we don't have to pull on a crew, run them for a little bit, drop them, bring them back a month later, run them for a little bit, and drop them.

That creates operational inefficiencies and safety considerations also.

Will Thompson -- Barclays -- Analyst

Thank you.

Operator

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

Joe Gatto -- President and Chief Executive Officer

Thank you. And again, thanks for everyone joining today. Hopefully, got an impression that we made a lot of strides this quarter in setting the stage for executing on larger pad and more efficient developments. Clearly, we're delivering on the plan out of the box here in 2019.

A lot of attention around savings. I'm glad we had a lot of chances to talk about that here today because it is important, and more importantly, that these are more structural in nature. And in addition to capturing the resource in the right way from co-development of benches but capturing the resource savings is really going to add up to where we want to be in terms of a growth company. They're delivering double-digit production growth and generating free cash flow for the long term.

So again, appreciate the interest, and we'll look forward to catching you next quarter. Thanks.

Operator

[Operator signoff]

Duration: 61 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

Brian Downey -- Citi -- Analyst

Neal Dingmann -- SunTrust Robinson Humphrey -- Analyst

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

Brad Heffern -- RBC Capital Markets -- Analyst

Gabe Daoud -- Cowen and Company -- Analyst

Mike Kelly -- Seaport Global Securities -- Analyst

Kashy Harrison -- Simmons Energy -- Analyst

Tim Rezvan -- Oppenheimer -- Analyst

Sameer Panjwani -- Tudor, Pickering, andHolt-- Analyst

Will Thompson -- Barclays -- Analyst

More CPE analysis

All earnings call transcripts