May 7, 2019
Operator
Good day, and welcome to the Callon Petroleum First Quarter 2019 Earnings and Operating Results Conference Call. All participants will be in a listen-only mode.
[Operator Instructions]. After today’s presentation there will be an opportunity to ask questions.
[Operator Instructions]. Please note that 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
Thank you, operator. Good morning and thank you all for taking 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 earnings results presentation we posted yesterday afternoon to our website, so I encourage everyone to download the presentation if you haven't already. You could find the slides on our Events and Presentations page located within the Investors section of our website at www.callon.com.
Before we begin, I'd like to remind everyone to review our cautionary statements and important disclosures included on slide two 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 helped to facilitate comparisons across periods and with our peers.
For any non-GAAP measures we reference, we provide a reconciliation to the nearest corresponding GAAP measure. You may find these reconciliations in the Appendix to the presentation slides and in the earnings press release, both of which are available on our website.
Following our prepared remarks, we will open the call for Q&A. With that, I'd like to turn the call over to Joe Gatto.
Joseph Gatto
Thanks, Mark, and good morning, everyone, joining us today. First quarter 2019 earnings results and operations update was posted yesterday after market close and highlight our operational efficiency gains, steady evolution in multi-well, multi-interval development and capital discipline.
We’ve delivered on our promise of thoughtful capital location 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 to bring forward value from less competitive inventory and importantly streamline operations. Our path to reaching sustainable free cash flow generation and achieving our leverage goals remain clear.
We are already ahead of our scheduled 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. Within improved outlook for oil prices relative to our $50 per barrel for planning deck, we now expect to achieve free cash flow generation as early the third quarter of 2019 at current strip prices.
Let me jump in on slide three 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.
A delineation efforts are paying dividends with solid performance from Middle Spraberry well in the Monarch area and positive early time results from our first, second Bone Shale, Spring Shale well in the Delaware. Late March we began flow back on our first five-well, Wolfcamp A pad and WildHorse marking our first-half section development project on this portion of our asset base.
Larger projects like this becoming normal course for our business. We are benefiting from tangible efficiencies which generated 20% reduction in average drilling and completion costs compared to our 2018 average.
[Audio gap] 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 balance production and free cash flow growth. The four primary tenants are increase our cash return on invested capital and maintain above our cost of capital, allocate capital to support sustainable free cash flow generation on the 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 or 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 period. Importantly, these aren’t aspirational goals.
We have meaningfully progressed on all of these elements and our position to further advanced over the course of 2019. Turning to slide four, we’ve summarized our incentive goals for 2019 which squarely aligned with the long-term tenants of the business.
Over the past five years talent grew rapidly for both acquisition with high quality assets and substantial organic increases in production reserves which establish a critical mass of operations. These initiatives proved valuable in 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 and the broader unconventional resource industry matures. As you can see on this page there’s a consistent theme of replacing growth oriented metrics with those focused on corporate returns and capital efficiency.
Moving to slide five, you can see a similar inflexion point that was occurred in operation maturity. Our shift to the large pad development has led to a change in the way we managed activity, acquiring DUC building that was a key focus for the first quarter.
The efficiencies in the capital savings that we are capturing from the transition to large-scale development has shown in the bottom left-hand corner. These structural reductions in drilling and completion costs have been an important element and improving the return profile of our larger projects.
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 completion 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 deficiencies will limit the usage of a second completion crew and not increase our pace with capital deployment.
In addition, our second half spending will reduce as we drop from fixed rates to full rates later this quarter. At this point, I’m going to turn the call over to Jeff.
Jeffrey Balmer
Thanks Joe. Moving to slide six, we’re 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 release two rigs by midyear and bring in the second completion crew to help with our largest 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 2018, and this is resulted in savings and overall completion costs, but also its brought forward capital in the first quarter.
In addition, we saw more non-consents from our non-operated partners early in the year with the downturn in commodity 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 gain ground during the quarter and we believe its unlikely that it will 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-budget for the year.
Once we exhaust that portion of the budget we will not participate in much additional non-activity for the year, but we don't believe that will be faced with a material amount of nonparticipation based on what we currently know about our partners plans. On the lower half of the slide you could see that capital the only between the basins was relatively balanced.
Some of these results from the shorter lateral lengths and lower completion cost associated with portions of the Midland basin assets. To the right, we’ve provided a breakdown of zone targeting by project with Wolf Camp A comprising majority of activities during the first four months of the year.
Moving to slide seven, we’re very proud of how our Delaware program is evolving and consistent and measurable improvements were seen in operational efficiency and the associated well results. Today 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 and 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 as been our drilling team's ability to significantly reduce the need to change out BHAs or Bottom Hole Assembles. Given the relative depth of the Wolf Camp A in all portion of the Delaware, the need to trip out of whole and replace these essential pieces that can cost upwards of an entire day during which we gain zero ground but incurs 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 study and ultimately reducing our well costs. These types of thoughtful changes coupled with a continued shift to larger multiwell designs help us drive more costs out of the system and create consistent repeatable results.
Flipping over to slide eight, 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 signal development ongoing in our Wildhorse area with the recent completion and flow back of our first five well Wolf Camp A pad which is currently performing above expectations.
We’ve benefited from strategic trades that allowed us to block up the position in our Sidewinder area where we will have multiple projects this year. Our pushed towards maximizing resource recovery is reflected in the multi-interval development that will employ in this area during 2019 and beyond.
Moving down to the Monarch area, our recent test of the middle Spraberry is part of the 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 coming months.
Over the Delaware we provided two visuals of the largest concepts we will be employing during this year's program with a six well codevelopment of the upper and lower Wolf Camp A and a five-well development involving the second Bone Spring Shale, upper lower Wolf Camp A and Wolf Camp B. We will continue to move activity throughout the acreage position with wells and what we refer to as the river tracks and also a couple test involving Wolf Camp A and B co-develop at Spur.
One 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 this presentation. And with that, I’ll like to hand the call over to Jim.
James Ulm
Thanks, Jeff. Looking at slide nine, 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 costs has help 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 from a $320 million in 2015 to just over $430 million last year. Revenue growth from increased protection is the primary driver, but reducing unit operating cost is the lever that allows for outsized growth over that period.
There are number of factors that go into creating those cost savings and the operational efficiencies that drive them. Over the past few years we've overhauled our ESP management program and are seeing longer run times reducing the number and frequency of work hours required and improving field uptime.
We've made tremendous strides forward in our recycling program and are not only reducing capital and operating costs with our improved program, but we are reducing disposal volumes and completion needs from local sources. Our focus on managing transport via effective pipeline tie-ins, with proven operators has improved reliability, reduced operating costs and remove 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 costs but provided a positive environmental effect. Across the board we're seeking to mitigate environmental and community impacts, but at the same time driving enhancements to shareholders value.
We will have more on these efforts soon with the forthcoming rollout of our ESP and sustainability program. On slide 10, we provided our standard outlook on financial positioning which remains very solid.
I will say it again we are looking at 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 affirm that 1.1 billion and contemplated the removal of all associated Ranger reserves and production.
This speaks volumes to the quality of all remaining core assets and their value. All of these factors are important in contributing towards our achievement of reducing our leverage below two times net-to-debt – excuse me, net debt to adjusted EBITDA in the near term, leverages the metric with the highest rating in our overall compensation program for 2019.
Focusing now on risk management; our hedging plans have not really change since they are derived from ability to win market conditions allow we have a responsibility to secure floor and 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 puts spreads creating affected floors at attractive lower prices and allowing for participation in the rising price environment.
Natural gas has been a bit of a different story. With swap [Indiscernible] to combat the relative weakness in the commodity, although the actual gas production accounts for very little of our revenue base with applied NGL value driving the bulk of our non-oil revenue.
As we look towards 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 patient and systematically add to our hedge position as the market provides liquidity at reasonable prices. One topic that has emerged as of 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 take away here is the 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 a firm transport to the Gulf Coast markets and the associated sales agreements that cover production that is tied to Brent and NEH 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 Waterborne pricing very close to Brent prices, but does not rely upon export for sales.
We are currently evaluating additional attractive opportunity to diversify our portfolio as early as the 2020 timeframe. The reason we continue to push forward with these efforts is both for physical risk mitigation and the ability to enjoy advantage 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've enjoyed roughly 13% upside on nearly 50% of our production where these agreements already active. To be clear, that’s only using WTI-based pricing which does not account for the mid cush impact of the differential applied this past quarter, which let minimum pricing below WTI for the duration of the quarter.
We believe this type of portfolio management will provide us additional side 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 the Joe.
Joseph Gatto
Thanks, Jim. Slide 13 should look familiar to those of you who been following the Callon story.
Its been our closing slide for few now and represents our stated goals to the market as we enter 2019. I believer our results and the progress we’ve made show how our team is achieving these goals rapidly with great success.
Execution safety is paramount and underpin our ability to achieve the rest of our goals. Jeff and his team are continuing to progress our efforts towards maximizing resource capture in mitigating parent-child impact across the portfolio.
Our past investments and infrastructure have demonstrated our dedication to social and environmental responsibility and will support our leading cash margins and driver 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 second 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 monetization has reduced our capital intensity with several future opportunities for more activity on this front.
At this point that concludes our remarks. Operator, I’ll turn it over to you to open the line for questions please.
Operator
We will now begin the question and answer session. [Operator Instructions] And our first question comes from Brian Downey and Citigroup.
Please go ahead.
Brian Downey
Great. Good morning.
Thanks for taking my questions. Maybe I’ll start with the question for Jeff.
In the release of the slide deck, you cite the improvement in average growth stage is completed per day and continue to show solid and consistent joint efficiency on slide seven there. Can you comment on anything incremental you are doing maybe on the completion side?
I know you’d mentioned less tripping out and Bottom Hole Assemblies on the drilling side, but anything further you’re doing there? And what runway you see on both those front to be on the move to larger pads?
Jeffrey Balmer
Sure. Yes.
Thank you very much for the question. The way that we approach drilling and completion, obviously two different operations, but very similar and how we approach them and that we apply what we call limiter theory.
So we look at all the ways -- all the different pieces that can bind in the operational job that we have at hand, whether it would 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 we zipper [ph] frac or what stages that we do and sequence with each other. And what that’s allowed us to do is identify areas for improvement and without going into the details upon what that allows you to do is kind of give yourself a true measure.
We spend 15 to 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 is apply some modest design changes in some of the development programs that we had.
For instance and you probably heard me say this before, if you’re doing an interior well on a large-scale development perhaps that that well doesn't need as much sand and water as all the wells that are ordering it 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 and already pretty good program.
Brian Downey
Great. That’s helpful.
And then given the Middle Spraberry and Second Bone Shale delineation can you provide any thoughts you have on inventory addition potential on how you can really see the early results affecting your views on optimal codevelopment and zone mix of medium-term?
Jeffrey Balmer
That’s another really good question. It’s pretty early right now.
I like both of the wells so far. Any time that you go into a new zone like that you have to be thoughtful about your first results that you get out of that and obviously there’s a few folks that have done similar projects, but what I doubt is that we’ve drilled our best well yet out there.
So we’ll look at what we’ve done. How we completed it.
Where we targeted it? How the well declines over time?
What types of lifting mechanisms looked best? And then doing assessment of the viability of that -- each of those zones has an economic target.
Certainly there's some beneficial areas when we’re doing the developments concurrently with other wells. There are some cost savings associated with that both on the drilling and on the frac 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
Excellent. I appreciate.
Thanks everyone.
Operator
Our next question comes from Neal Dingmann of SunTrust. Please go ahead.
Neal Dingmann
Good morning, guys. Nice quarter.
Joe, my first question, just looking at your operational efficiencies it's definitely notable of the bottom improvement which you all seen especially I think in prepared remarks, talk about drop in the rig previously now quicker than previously projected. So, where that you all don't have the 2020 guidance out?
I’m really just wanting in broad terms how you are thinking about up here that upcoming year’s growth and free cash flow especially if these efficiencies remain as strong as they appear to be now?
Joseph Gatto
Yes. Thanks Neal.
Good observation. Obviously we’re happy with the efficiencies we’re seeing.
As I 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 expect do this.
We had seen the benefits from large pad development previously in Midland basin as we’re employing it across a larger swap of our acreage. We’re seeing that flow through, but obviously we’re not going to be satisfied where we hope to drive more as time goes on and that’s certainly good implications for 2020.
We’re not going to bake that in at this point, but certainly we’re off to a good start and delivering on our large pad development program. To talk about 2020, we’ve mentioned some outlook for this in the past, we have talk about double-digit production growth and being a free cash neutral for the year around $52.50 we are to be losing some cash flows from Ranger obviously.
If you do simple math and take those cash flows out that is offset by paying down debt and potentially preferred issuance that 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, we’re removing Ranger. We removed some drilling obligations that we have down there 2020, which gives us a little bit more operational flexibility to move more capital efficient areas on our asset base.
We’ve talked about some of the pricing uplift that we expect to get from our marketing arrangements as we move to 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 – its not a huge number, but roughly $50 million of acquisitions minerals rights over the last couple of quarters that will be folded into our program and provide and uplift. So as we look at 2020 we add all together.
We’re hoping as we provide some more formal guidance on that year we’re probably close to where we started before divesting Ranger.
Neal Dingmann
Great. And then just secondly, just looking at the PoPs, and just want to double check, is your net lateral PoP feet in each half of this year the same as it was in your initial budget really I was just looking at the chart on – its on page five here.
It looks to me like it's the same. But I just want to double check that the lateral feet PoP in in each half of this year is the same as what you were previously think about?
Thank you.
Joseph Gatto
Hi, Neal. It’s reasonably the same.
There are some small new ounces there. I think we had seen a slight compression of the scheduled.
So what you probably see a slight shift forward in the actual completion scheduled due to the time those are going to come on. They’ve come on little earlier but it’s little earlier in the third quarter, it doesn’t necessarily crossed over into the second quarter.
Neal Dingmann
Okay. But it looks like then for the each half it looks to be relatively this same or just a little shift on timing results?
Jeffrey Balmer
Yes. No.
From the actually PoP standpoint, yes, from the completion timing you have slight shift forward, which intraquarter it’s not going to be show itself on that chart but it is little bit ahead of schedule.
Neal Dingmann
Very good. Thank you all.
Operator
Our next question comes from Derrick Whitfield of Stifel. Please go ahead.
Derrick Whitfield
Good morning to all. Congrats on the strong quarter and update.
Joseph Gatto
Thanks Derrick.
Derrick Whitfield
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 in the mid-caps that create advantage pro forma companies was scale on material over at synergies?
Joseph Gatto
Look, it’s a pretty topical time to asking like that question. If you look historically and look at M&A in the space, a lot of its been driven by adding inventory for large part in terms of giving more of a runway to companies and putting companies together have more of a runway.
What we’re seeing now in the unconventional space, it’s a little bit different. Certain companies like ourselves have a lot of inventory to work with, so if -- your pieces around the deals are really around synergies, we point to some are little bit more tangible than others in terms of G&A.
Although this is a people business and you can approach a deal and say, we always going to take all the G&A out and everything, it would be good. We all need good people, companies our size going forward.
So you get into softer synergies in terms of well just because we're bigger we're going to get all these 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 is a critical mass that you need to be efficient and have good vendor relationships. We think we're squarely there at this point, but that doesn't mean that there couldn't be opportunities for combinations to get real operational synergies, employing some of the concepts that we're doing on a larger asset base, I think a more reasonable pieces.
Derrick Whitfield
Very helpful and perhaps for Jeff is 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 limiter theory assessments?
Jeffrey Balmer
Got you.
Derrick Whitfield
We’re looking at Jeff.
Jeffrey Balmer
Yes. I guess I'll process it two ways.
We're never satisfied. So 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 their premier producers and developers in the Permian Basin and that comes from a large number of very easily identifiable variables and cost of course, inefficiencies is one of the big drivers of that. 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'll be a focus for making sure that what we've done and accomplished is carry 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 – on those cost savings happen.
Derrick Whitfield
Very helpful. Thanks for your time.
Jeffrey Balmer
Thank you.
Operator
Our next question comes from Brad Heffern of RBC Capital Markets. Please go ahead.
Brad Heffern
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 in various parts of the Permian. So how would you like to attack it maybe by region or just more broadly?
Jeffrey Balmer
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 designs are going to be.
We really like what we've done so far from the 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 reservoir based upon where we are in 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'll apply different spacing and stacking there versus when we come into a more greenfield or Virgin reservoirs where we may have an opportunity to be a little bit more aggressive or work into the co-development programs that we've been discussing throughout the last year or two.
Brad Heffern
Okay Thanks. And then Joe you talked about the minerals acquisitions 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 be drilling next?
And then has it made a meaningful difference in terms of the corporate wide NRI?
Joseph Gatto
It's certainly a space that's attracted a lot of attention from private capital. But I think you hit it pretty well.
I mean we should have a symmetry of information that puts us 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 at a cost to capital, just because given the opportunity set that we have, high bars for any sort of acquisitions at this point. But as you know minerals do drive a lot of value.
So we're going to stay focused on it. Now that being said, there is 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 gives you some indication that there's spots that it's just going to get away from 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 two in terms of introducing that more. We've been sampling 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're getting to 2020 I think you're going to see more of that and that NRI uplift that we'll talk about a little bit more once we put that 2020 plan more formally in place.
Brad Heffern
Thanks.
Operator
Our next question comes from Gabe Daoud of Cowen. Please go ahead.
Gabe Daoud
Hey, good morning guys. Maybe just following up a little bit on the prior question, maybe specifically in Howard County, can you just talk a little bit about multi-interval codevelopment across the Lower Spraberry, Wolfcamp A and Wolfcamp B just thoughts around spacing with those three zones over the next couple of projects, and then further how do you guys think about zones beyond those three; specifically the Dean [ph] and Wolfcamp D given results from one of your peers?
Jeffrey Balmer
Sure. Just taking a few notes to make sure I can answer that question in a robust manner.
Similarly to what I’ve 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 Wolfcamp B gets Y amount of wells in those areas. So again, there's number of variables that come into play out there.
The Dean has potential of Wolfcamp B and to some extent there's some nomenclature considerations where we may call the Wolfcamp C. what somebody else call as a Wolfcamp D et cetera.
But there is opportunity that co-develop through Lower Spraberry, Wolfcamp A, Wolfcamp B certainly and we'll be investigating those items going forward. Again being thoughtful about it, but also trying to do -- putting development programs in where we also gain the operational efficiencies of having larger scale pads as opposed to single well operations.
Gabe Daoud
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 to continue to support larger pad sizes as you move through 2019 and into 2020?
Jeffrey Balmer
Well, I think it's what we're doing and kind of the proof is in the pudding that you get a rig out there doing two, three maybe the maximum would be four wells per rig and we have a nice flexible contract that's a win-win with our primary vendor. So they can come in and give us some assistance when we need to work off that backlog of inventory.
So, I don't see any real changes relative to what we've 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
Great. Thanks Jeff.
Jeffrey Balmer
Thank you.
Operator
Our next question comes from Mike Kelly of Seaport Global. Please go ahead.
Mike Kelly
Hey, guys. Good morning.
I was hoping to get just a better sense how we should think about production in CapEx for the second quarter. I know you've got kind of a few variables in play here as you could complete these larger pads.
I think you mentioned in the press release, the 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.
Joseph Gatto
Yes. For the second quarter obviously we haven't -- we don't give quarterly guidance, so, well, this is been our annual guidance.
We know we owe everyone an update on post Ranger once we get that close. But broad strokes, yes, we are on the tail end of the Delaware optimization effort.
So it's a little bit of a headwind. Obviously we'll lose some barrels from the Ranger sale in June when we expect that to close and we're running on cracker [ph] at this point.
And we won't see the impact of that until really the third quarter. So you add all that up that does that to something that's relatively flattish to down a little bit in terms of volumes.
CapEx given that we are -- for the most of 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 a roughly 30% or thereabouts in the first quarter so that's just back into the math there for you.
Mike Kelly
Appreciate that. Switching gears to the productivity gains into the Delaware, just want to get a sense what you think is really the biggest driver of that.
And that also curious on the sustainability of those gains and if we're sitting here at the end of 2019 and we look at the average for 2019 wells compared to 2018 do you think there's -- this is really the ability to see wells this year be 40% better than what you've seen in 18 and 17? Thanks.
Jeffrey Balmer
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.
Is it sustainable? I sure hope so.
I think if you go into larger full fold developments where you're maximizing recovery and optimizing value you'll see some of the same similar things probably that you saw in the Midland Basin where that were well productivity, when the wells begin to talk to each other a little bit and it'll flatten out a little bit. But I do think that there's optimization that can occur on the completion designs targeting the spacing and stacking.
So the opportunity in the remainder 2019 and beyond is very positive right now.
Mike Kelly
Great. Thank you.
Operator
Our next question comes from Kashy Harrison of Simmons Energy. Please go ahead.
Kashy Harrison
Good morning and thanks for taking my questions. So, Joe, this year you budgeted your capital program based on $50 oil and you've received the benefit of higher oil prices.
As 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?
Joseph Gatto
I think we're pretty squarely on what you outline, $50, $55 world. That's pretty much what the back of the curve continues to tell us and our views of what really the long term marginal cost of supply is at the end of 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 shareholders or look at expanding from an A&D 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 yet.
$59, $55 because we got to think about the long term fundamentals and what we've seen over the last few years. We can see volatility move pretty quickly.
We still think it's going to come back on a $50, $55 range. But if you budget for a higher price than you're subject to having to pullback 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 you’re going to lay down activity.
If we budget if those ranges we think we're in better shape to outline the longer term value proposition.
Kashy Harrison
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 behave as you said.
Are there -- is there anything in your portfolio where you're seeing that could be a lay up in terms of monetization?
Joseph Gatto
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 we picked up, there's really nice sections, but there is just one section. And 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 as an outright monetization or tray candidate.
So that's probably a decent pool there. But as you mentioned the water business is 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 – its going to be thoughtful because we spent a lot of time and money and really being proactive on this part of the business that has paid dividends in terms of reliability, economics and environmental responsibility.
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 expensive long term. We put these assets in place for reliability in our operations and that's going to be first and foremost on the list.
But that being said I think over time as we miss some opportunities to take some capital out of that business and still preserve our objectives.
Kashy Harrison
Thank you.
Joseph Gatto
Sure.
Operator
Our next question comes from Tim Rezvan of Oppenheimer. Please go ahead.
Tim Rezvan
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 that the leverage topic. I see it has significant weight at 15%.
Joe, can you kind of walk through specifics on what those bogeys are that management's incentivized to hit this year?
Joseph Gatto
Yes. So, we haven't given the 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 over the next several quarters as we get leverage below two times. It's not going to be next quarter.
Obviously, Rangers is a first step towards that. I think staying disciplined and taking cash flow to the balance sheet as we get in the later part of this year and next year will be important.
But at this point that's all we can we can talk about. Jim, if you want to add to that from your standpoint, but we haven't disclosed the actual metrics at this point.
James Ulm
We haven't disclosed it and it's just saying there's a range of different metrics there, the one that we'll be focused very much on is how do we get that leverage down to a place that we're more comfortable with. We've said less than two 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
Okay. Thank you.
I appreciate this comment. And then if as a follow up the comments that you gave on the uplift, you will be getting from the FT.
If we think about crude prices and sprite staying where they are, do you anticipate your unhedged realizations to be kind of a 100% or more of WTI next year? How should we think about kind that because it’s a margin game and it seems to be really impactful and kind of 2020 realizations?
James Ulm
It is and that's a very good question. I was sitting there 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've talked about being conservative in our budgeting in the $50 to $55, but the hedging and the price 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 brands and other places. I guess the last observation I would make there is those are also more liquid points should have better price discovery as we think about hedging.
And so it'll be an integrated approach that will hopefully give us additional revenue into that cash flow calculation we've been talking about today.
Tim Rezvan
Okay. Thank you for those comments.
Operator
Our next question comes from Sameer Panjwani of Tudor, Pickering and Holt. Please go ahead.
Sameer Panjwani
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 trends lower as savings roll through.
Or could we see incremental wells placed on production this year while leaving the overall budget unchanged?
Mark Brewer
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.
We've provided a guidance range of five to five twenty five on operational capital front. I think you saw what we spent was roughly 30%.
I think we're pretty comfortable that our goals are very achievable. As with anything else if we do everything that we're supposed to I think there's 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
Okay. And then secondly as you've progressed to free cash flow later 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 from some of your other initiatives like the water system build-out and the Delaware optimization project?
Joseph Gatto
I’m sorry, were you looking for efficiencies or cost savings and just let me double check and make sure I'm clear on your question.
Sameer Panjwani
Yes. So cost savings in terms of enhancing the margin.
Joseph Gatto
Sure. Yes.
The recycling program that we have in the Delaware is fantastic and it's already well advanced. That was one of the very attractive things about coming over to Callon which was how seriously this team 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 have mentioned here in Slide six that we've got an additional rollout of a treatment plant that's in our kind of Southeastern assets zone in Delaware.
That combined with this new pond that we have that will add another 350,000 barrels of storage. The plan is to be able to deliver -- the two areas are called [Indiscernible].
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 grid [ph] line, so it gives us the flexibility of moving recycled volumes both north and south within the whole asset.
So when you look at the infrastructure that we have in place and what we added into that we'll continue to see what's already in good recycling program increase. And you're probably getting $0.50 to $0.75 a barrel savings for every barrel that you can reuse.
Sameer Panjwani
Okay. That's helpful.
Thank you.
Operator
Our next question comes from William Thomas of Barclays. Please go ahead.
William Thomas
Hey, good morning. Just a follow-up on that 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 gives you confidence that count won't run hot on a CapEx budget in the second half of the year. And if I recall correctly you would plan to add a second dedicated completion crew in the second half of the year.
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?
Joseph Gatto
Yes. That's exactly right.
We talked about bringing in the second completion crew to help with the larger pads and running simultaneous operations. So we're moving to larger pads we're not giving up cash conversion cycles.
But you're right I mean we're still bring back a second crew which is bringing back for less period of time. Just given how efficient we have been with that first crew.
So we're using those efficiencies from the first crew to reduce our needs for second crew versus accelerating capital allocation during the course of the year.
William Thomas
And then, is it fair to -- the completions have been – is it fair to assume that the completion efficiencies are being driven by that the increase per fracs by larger pad development. And if I recall correctly you got some pricing concessions for your frac crew provider last year and I guess is it fair 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 and cyclic?
Jeffrey Balmer
Those are all 100% true statements. There is also the improvements that we’ve got on the water which we had highlighted a little bit realizing the usage of local sand and then modifications to the designs, the actual designs on well, but yes, everything that you said was a -- is a big driver that adds to the overall cost reductions in combined with the overall efficiency gains.
William Thomas
Okay. And then one more quick one from me; I think you exited 1Q with 21 gross DUCs.
How should we think about the appropriate documentary per rig as you transition a larger pad development?
Jeffrey Balmer
Let me double check and make sure I understand the question.
William Thomas
Yes. I mean, I just want to get a sense of like, what a normalized DUC inventory per rig should be as you move to larger pad development?
Jeffrey Balmer
Sure. Like I mentioned a little bit previously, you’ll see the kind of ebb and flow with us, so we’ve build up a little bit of DUC inventory for two reasons.
The first one is to make sure that other learnings that we’re uncovering as the older wells are on production and giving us data, we can make sure that we translates those into actually improvements when we go in and basically complete the wells. And then also it makes us efficient on our existing completion operations.
So we don't have to call in a crew, run in for a little bit, drop them, bringing back a month later, run in for a little bit and drop them. That creates operational inefficiencies and safety considerations also.
William Thomas
Thank you.
Operator
This concludes our question and answer session. I would like to turn the teleconference back over to President and CEO, Joe Gatto for any closing remarks.
Joseph Gatto
Thank you. And again, thanks for everyone joining today.
Hopefully, got a impression that we made a lot of strives this quarter and set a stage for executing on larger pad and more efficient development. Clearly we’re delivering on the plan out of the box here in 2019.
Lot of attention around savings, I’m glad we had a lot of chance 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 that are capturing resource savings is really add up to where we want to be in terms of the growth company that is 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
The conference is now concluded. Thank you for attending today’s presentation.
You may now disconnect.