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Good morning and welcome to the Callon Petroleum Fourth Quarter 2017 Earnings and Operating Results Conference Call. All participants will be in listen-only mode. After today's presentation, there will be an opportunity to ask questions. Please note this event is being recorded. A replay of this event will be available on the company's website for one year.
At this time, I would like to turn the conference over to Mark Brewer, Director of Investor Relations. Please go ahead, sir.
Thank you, operator. Good morning, everyone, and thank you for taking the time to join our conference call. With me this morning are Joe Gatto, President and Chief Executive Officer; Gary Newberry, Chief Operating Officer; and Jim Ulm, Chief Financial Officer.
During our prepared remarks, we'll be referencing the earnings results presentation we posted yesterday afternoon to our website. I encourage everyone to download the presentation if you haven't already. You can find the slides on our Events & Presentations page located within the Investors section of our website at www.callon.com.
Before we begin, I would like to remind everyone to review our cautionary statements and important disclosures included on slides 2 and 3 of today's presentation. We'll 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 may find these reconciliations in the appendix to the presentation slides and in our earnings press release, both of which are available on the website. Following our prepared remarks, we will open the call for Q&A.
And with that, I'd like to turn the call over to Joe Gatto.
Thanks, Mark, and thanks, everyone, for joining us this morning. Our quarterly earnings release was out yesterday along with earnings slide deck that we'll be referencing during today's call. As you've seen from our website and presentation materials, we recently launched our reaffirmation of the Callon brand and the underlying values that have guided us for over six decades. These principles of doing business have stood the test of time and continue to differentiate our organization as we carry on the Callon tradition for years to come.
This past year represented another record year for Callon, with our team delivering production growth of more than 50% combined with reductions in both operating costs and finding and developing metrics for the third year in a row. All of these significant improvements contributed to expanding cash margins and enhanced corporate level returns, which as we have said multiple times is one of the primary goals for Callon and a product of a measured investment program and high-quality assets.
2017 closed on some very positive notes and I believe has set the stage for a year best characterized by a focus on improving the program development and capital efficient growth.
With that, I'd like to direct you to slide 4 of our presentation. During the fourth quarter, we have robust production contributions from all four of our core operating areas, as activity progressed across our Midland and Delaware Basin footprints. This activity culminated in average daily production rate of over 26,500 BOE per day, of which almost 80% was oil, translating into a sequential increase of 18% in total BOE versus the prior quarter, and a greater than 20% increase in oil volumes. This result brought our full year daily production average to over 22,900 BOE per day, which is at the top end of our annual guidance range.
We continue to drive down operating costs, resulting in LOE of $4.84 per BOE for the quarter and ending the year with a 27% reduction in this line item since the first quarter. Managing these operating costs while continuing to increase our oil-rich production resulted in peer-leading cash margins of $40.51 per BOE for the period.
Reserve growth was equally impressive, with a 50% increase proved reserves at a drill-bit F&D cost of $8.42 per BOE, which also drove organic replacement of over 550% of our production as we expanded our proved reserve base from a deep inventory of high-return locations.
Overall, our continued focus on the right assets, solid execution and field level operating efficiency has placed us in a position to deliver value-added growth in the future. And importantly, our foresight regarding infrastructure investment and a focus on playing the long game, as it relates to responsible development, is something we believe will be an increasingly important advantage.
Moving to slide 5, you can see that a significant driver in our continued EBITDA margin increases has been our stable production trajectory over the past two years, with an oil cut of just under 80%. Our average peer is producing just above 60% oil, which leaves us with a significant advantage from a blended commodity pricing perspective. And we'll highlight that advantage in terms of recycle ratio metrics here shortly.
In addition to this margin expansion over the last several quarters, consistent improvement spans across many other key drivers of our business, as you can see on slide 6. Over the past two years, our production has grown at a compounded annual growth rate of 55%, alongside a proved reserve growth CAGR of 59%.
At the same time, we have lowered our cash operating cost by 24% and reduced our highly competitive drill-bit finding and development costs per BOE by 6%. On that metric, in particular, many companies within our peer group posted sequential F&D increases in 2017. We are proud to have bucked this trend and overcome industry-wide cost pressures with strong well results and overall capital efficiency.
With this type of performance, it is rarely apparent that our operational model has been successful in capturing the value embedded in our high-quality acreage position against the backdrop of increasing industry activity and operational challenges.
On the next slide, you could see the 2017 proved reserve growth once again was greater than 50%, bringing our total proved reserves to 137 million BOE, which are nearly 80% oil. Along with this value-added volume growth, our proved PV-10 value increased just under $1.6 billion. Of that figure, over $1 billion of that value is attributed to our proved developed reserves that are concentrated in highly productive oily areas of both the Midland and Delaware Basins.
We all know asset quality is critical, but our operating cost structure and ability to deliver competitive well costs also provides a significant uplift to the value of our entire portfolio. A key driver of that cost structure comes from our progressive mindset towards implementing infrastructure projects that result in sustainable cost savings and also support responsible development for all of our stakeholders.
On slide 8, we have provided an illustration of the significant value creation from our 2017 capital program. Beginning with PD, PV-10 value of $500 million at year-end 2016, we grew that proved developed value to over $1 billion by the end of 2017. We needed to invest additional capital to achieve that doubling of value, some of which was funded from our proved developed reserve base that was in place year-end 2016.
Since that additional capital spend demands return on investment, we added that capital spend to the value base we started from to set an adjusted starting point to judge our performance. As you can see, we were able to add over 40% in incremental PD value over that adjusted bar in just one year.
Looked at slightly differently, our net investment translated into a 3x contribution to PD value over the year. While improvements in commodity prices helped some of this math, it does highlight the compelling bang for your buck proposition available to Callon as we pull forward returns on our asset base.
Slide 9 provides some context relative to our peers on a couple of important metrics. For growth companies, reserve replacement is a key factor for a sustained outlook and we are very pleased to be at the top of this list. But growth is one thing, quality growth is another, and you can see how our quality reserve adds are laying the foundation for leading cash margins.
On the next slide, we've summarized a couple of the key elements I just mentioned to give perspective regarding the significance of combining an increasingly competitive proved developed F&D costs with strong cash margins and the implications for recycle ratios and capital efficiency.
The vertical distribution outlines the economics for adding proved developed reserves capturing both well productivity and well costs. While this metric is not adjusted for oil content, this is picked up in the second element on the horizontal axis, which captures the relative hydrocarbon pricing mix uplift as well as operating cost structures.
With Callon at or near the top of both of these categories, we've established one of the most competitive structures in the Permian for delivering sustained capital efficiency. With strong cash margins available to reinvest with attractive development costs, we're able to pull forward well level returns primarily from internally-generated cash flow, and as a result, continue to bolster corporate level returns while also growing our production base.
At this point, I will turn the call over to Gary Newberry.
Thank you, Joe. I will continue on slide 11. We provided an operational capital spending outlook for 2018 with our February 1 operational update, which remains unchanged. We still expect to spend between $500 million and $540 million in operational capital in 2018, excluding capitalized expenses. This includes the assumption of potential cost inflation of 10% for drilling and completion activities. As of today, we have yet to see any significant inflation from a cost perspective.
Our planned activity is to be allocated relatively equally between the Delaware Basin and Midland Basin and is assumed to be over 98% operated by Callon. Our fifth rig has already been deployed to our Spur asset and has commenced drilling operations.
In total, the program assumes the spud of 47 to 50 net wells, with 43 to 46 wells placed on production in 2018. While we're doing some delineation and testing work this year in both basins, nearly 95% of our capital program is development-oriented.
The testing we began or plan on executing has been designed in a way that reduces operational risk to our overall program expectations. For instance, our six-well mega-pad concept at Monarch is utilizing two side-by-side three well pads targeting a single zone to replicate a larger six-well pad concept. This will allow us to better understand reservoir drainage, offset frac impact and improve existing infrastructure utilization, while avoiding an increase in cycle times. Our only planned down-spacing test for the year is at WildHorse, utilizing two wells offsetting historical production to determine the efficacy of potential 460-foot spacing.
Another important point about our operational plan for this year lies in the front-loading of our planned infrastructure projects, with the majority of these impactful additions being put in place earlier in the year. We are reducing the potential for disruptions to our planned drilling and completion activity while lowering our projected operating costs.
Turning to slide 12, we have laid out the projected pace of operational spending and wells to be placed on production. You can see that our overall operational capital picks up just slightly in the first quarter of 2018 from our spending in the fourth quarter of 2017. As we highlighted in our February 1 release, both production and spending are expected to ramp during the second and third quarters of the year with significant incremental production growth in both periods.
You may also note that infrastructure spending gradually steps down in each of the four quarters of 2018 after initial spending to support the recent expansion of our Delaware drilling program. As we have said before, implementing the critical measures related to infrastructure are key to ensuring optimal field development efficiencies.
Our recycling program in the Delaware is something we're very excited about as we expect to source up to 50% of frac water volumes from recycled barrels. We also expect to have our new saltwater disposal well in Ranger online early in the second quarter to support our Wolfcamp C drilling later in the year.
One of our newer initiatives includes the development of electrical substation projects, which will further reduce our need for generators and associated costs from fuel and the rental fees. Overall, we have made tremendous strides in preparing for efficient full field development and are now in a position to reap the benefits.
Looking at the pace of wells placed online, you can see that there is a significant step-up from the first quarter to the second quarter, some of which is related to pad size and timing of wells being placed on production. But it should be noted that these are net wells and we have a lower than average working interest for wells in the first quarter.
When combined with the slowdown in January completion activity to build a larger base of DUCs for operational flexibility and weather-related disruption that the Permian encountered in January, we do expect production for the first quarter to essentially be flat to the fourth quarter of 2017. As we progress through the second quarter, we forecast a significant ramp in production, as many of our larger and higher working interest projects come online.
Let me now hand the call over to Jim Ulm, our CFO.
Thanks, Gary. I am truly pleased to have joined the Callon team, and I'm glad to be here today with you and Joe. You can see on slide 13 that we continued to maintain a strong liquidity position with over $500 million available as of December 31. We also continue to screen wells from a debt to EBITDA perspective, as our strong cash flow from operations continue to support our planned growth in 2018. As you can see in the chart here, we have no near-term debt maturities until 2022.
Our spring borrowing base redetermination is approaching and I would expect that our robust growth in 2017 would have a potential and significant increase in our bank capacity.
Our crude oil hedge contracts are outlined on slide 14 and provide a breakdown showing a floor price of around $50 a barrel for 2018. Roughly two-thirds of these positions are collars that allow us to participate in the upside. With over 60% of the consensus production hedged, we still have the opportunity to reap the benefits of higher prices in the near-term, while protecting our cash flow should commodity markets begin to decline.
We have limited our 2019 hedging to approximately 25% of consensus production levels to date. However, we are closely monitoring the market and we'll begin to enter into additional positions as the year progresses.
Our natural gas hedge position is detailed on slide 15. While we have less natural gas volumes covered on a percentage basis relative to oil, I'll remind everyone that our production is nearly 80% oil and it's the primary driver of our cash flow.
That being said, we are locked in on swaps at about $2.95 per MMBtu for most of the year, with additional coverage in the first quarter from some collar floors at $3.40 an MMBtu. We will continue to keep a close eye on basis pricing differentials and we'll be opportunistic in adding to our overall positions throughout the year.
Our full year guidance for 2018 is provided on slide 16 along with our 2017 results. We are affirming our prior full year production and capital guidance ranges and providing 2018 estimates for our additional guidance categories.
Back to you, Joe.
Thank you, Gary and Jim. And again, thanks, everyone for tuning in and allowing us to talk through a very successful year for us in 2017 and set the groundwork for the path forward in 2018.
With that, we will turn it back to the operator for Q&A.
Thank you, sir. We will now begin the question-and-answer session. And your first question will come from Neal Dingmann of SunTrust. Please go ahead.
Hi. Morning, guys. This is Josh (18:27) on for Neal. So, I had a question on – so well interference, we've heard a number of your peers kind of talk about parent-child relationships and two-type spacing. How do you see these risks for Callon – or the industry and what steps have you kind of taken to mitigate these?
Josh, (18:51) thanks for asking. Yeah. That's something that we're all learning about together as we go forward. We've been stepping into this in a way that, I think, has been very educational and learning. Frankly, part of the reason we've actually gone to pad development from the very beginning was to minimize that impact early on throughout the entire lifecycle of our drilling program. Since early time, we've been doing mostly pad wells.
But as we get into infill drilling, just similar to what we did in CASM, it was where we have our – CASM and really some parts of Ranger, we have the majority of our experience with parent-child relationship, de-watering or deferred – or watering out and deferred production and ultimately, the ability to effectively fracture stimulate the offset wells based on depletion.
So, there's a lot of things that are impacting this entire relationship. But in total, as we've down-spaced in both the Wolfcamp B in Reagan County and as we've down-spaced the Lower Spraberry in Midland County primarily around all the things that we've actually published data on over the last several quarters, we think we've mitigated that impact quite well.
Now, the next step for us is to move to this larger pad development, which is what we're moving through now and Monarch this year to further minimize and mitigate the impact of deferred production from de-watering existing wells as well as more effectively and efficiently propagating effective fracture stimulations into this shale development in a larger way.
So, we think it's going well. I think it's something as we continue to mature in each area that it'll be different. But I think the data that we've shown you is that it seems to be working well and there will clearly be an impact. We've mentioned it before, there's clearly an impact to that next well over, but it can be mitigated if planned properly.
Great. And then just a follow-up, you guys have been early on in infrastructure build out. How much kind of headroom do you guys have over your production guidance in 2018, first, your current infrastructure or what you'll have midyear?
We're well ahead of what our needs are, Josh, (21:30) but our production growth both in water and oil is that we're expecting that to be substantial. So, at the end of the day, we'll never be finished. What we've done ourselves, frankly, in getting to pipeline infrastructure for water management, getting to our own deep disposal wells for water management, high-capacity deep disposal wells to avoid shallow hazards. We are now partnering with third-party companies to help actually manage some of that peak loading that we expect on some of these larger pad developments.
We've already announced actually in the Delaware Basin a long-term relationship with Goodnight Midstream and we're anxious to talk about another relationship on water sourcing and disposal with another company that we're working on right now, both in the Delaware as well as the Midland Basin. We're just not quite ready to do that yet. We're still working on a few other items with this other company, but they're being very proactive in doing all the right things in our mind.
And the focus on recycle that we've had for a number of years is going to be very impactful in managing all of our needs throughout the area. So, I would say that we're ahead of where we need to be, but we're not quite done. That's why we're spending primarily money in the Delaware Basin yet to further enhance our ability to move water around to our own disposal wells and then ultimately to delivering into the Goodnight system.
Great. Thank you.
The next question will be from Gabe Daoud of JPMorgan. Please go ahead.
Hey. Good morning, everyone. I was hoping we can maybe just start a little bit on the Saratoga well and the Delaware Basin. I was curious if this was one of the operating completions in which you intended on reining in proppant intensity and just overall completion intensity in an effort to get the well cost down. So, maybe if you can just talk a little bit more about the completion design and the cost?
Yeah. We pulled back sand loading a little bit on that well, Gabe, just like we had intended to actually get another learning step on how we effectively stimulate a single well, as well as ultimately moving to multiple well pads in that area. This well is performing quite well based on what we see today. We're happy with the performance. But there's still more to learn as to how we go forward in the Delaware. But yeah, we pulled back on sand loading just like we said we would.
Thanks, Gary. Moving on, I guess the Wolfcamp C, a nice result there. Curious about any updated thoughts on the Wolfcamp B? I know at one point, you did plan on testing the zone at Ranger in 2015. Just given some recent competitor results, do you think about testing that at any point this year?
There's a lot in that question, but, again, I want to emphasize we're very focused on efficient development throughout the year, but we are encouraged with the Wolfcamp C in the Reagan County. It's very early time. You guys know I don't like talking about single well results. I'd never have, never will. It is a single well. We're encouraged with it. It's a well that is encouraging enough that we're going to drill more wells. But I'll tell you that I have as many questions about the well as I have answers. So, it's still just a single well result with encouraging information early time.
So, with that, we're going to do more. We're encouraged that we're actually able to participate near-term with another well as an OBO partner, carries on with one of the area wells down there soon. So, we're anxiously learning about that. And we're learning as much as we can from all the public results, of course, from the Parsley data that we can get because their Taylor well is an interesting well. This well doesn't feel like a Taylor well to me, but it's encouraging. So, I'll just leave that the way it is with the Wolfcamp C.
Your last question was with the Wolfcamp D. And I think, again, I'm assuming still Reagan County because that's where we had planned to drill one prior to pivoting at the end of 2014 to the Monarch area. There's some very good results, very interesting results being delivered by offset operators there today and we're very encouraged with that opportunity. We're not prepared to go drill our own this year at all.
Yeah. So, I think, Gabe, overall, we do have some delineation work going on in both Midland and Delaware. But as it relates to our overall program, it is in the single-digits, on a percentage basis, in terms of capital exposed. So, some of that's having some lower working interest, which helps us get into some more wells with lower capital exposed, but we have those opportunities, like you said, in the Wolfcamp D. They're on the radar screen. It's just probably not on this radar screen for 2018, but it's good to see those results continuing to come in the de-offsetting as in Reagan.
Sure. Thanks, guys. That's helpful, and just one last one for me. Just on infrastructure spend, can you maybe expand a little bit on the comment of potentially divesting more assets this year at some point? And then also spending about 20% of (27:18) I'm assuming this year, does that normalize to like 10% or so as you move forward in 2019 and beyond?
Yeah. The opportunity for divestment of some of the infrastructure spend that we've already had is really in the partnerships that I referenced before as we continue to mature and partner with other companies that are building out some lower type high-capacity infrastructure. There's a willingness and really an ability to potentially partner with utilizing these assets to benefit both parties, whether we divest of it 100% or partially in order to fully utilize that and let them focus on the good things that they do and utilizing those assets to their fullest is a really good opportunity that's before us today.
So, it's likely along those lines. And yes, as we continue – just think about what we've done. And WildHorse and Spur in a very short period of time, we've put enough infrastructure in place and partnered with the right responsible companies to actually get to an efficient development mode in a very short period of time. And so, as a result of that, our infrastructure spend should go down.
And the next question will come from Jeff Grampp of Northland Capital Markets. Please go ahead.
Good morning, guys. Gary, just I don't want to spend too much time on the one Wolfcamp C well. I was just hoping to maybe get a little bit more color on maybe any interpretation you can give early on that oil cut. It seem to be a little bit more favorable than some of the peer Wolfcamp C bench wells. Is that something you guys maybe expect to normalize as that well kind of flows back, or is that kind of relatively in line with what you guys were expecting?
Again, we're not suggesting one well tells much. I would like to actually see that oil cut go down because that would help me feel more comfortable about the energy in the reservoir. So, I would like to see it more normalized toward some of the area results because that tells me that there's – I'm connected to a longer term energy view. But, again, it's just a simple early discussion that we're having about what all this means. And frankly, we're way too soon. We don't know. But I would expect, and I would kind of hope I would see a little bit more gas energy come with it. That might be a bad thing to say, but that's generally the way I'm thinking about it from a reservoir perspective.
Okay. No, that's perfect. I appreciate the candor there. And then, just from a high level maybe for Joe. Obviously, we see a lot of folks talking about free cash flow generation and kind of lines of sight to the inflection points. Can you just maybe give us some updated thoughts on that? Is neutrality still generally a few quarters out from just adding this fifth rig? And then, what are kind of the longer term views of Callon in the context of free cash flow?
Yeah. I think nothing has changed on our part. Whenever we add activity, we want to see a path to four to six quarters out, getting back to a point where we are cash flow neutral. We will make a lot of progress during 2018 to getting to that point. So, that is still part of our DNA and how we think about adding activity.
As we've laid out, 2018 is going to be about five-rig program with two dedicated frac crews. We don't see any increase to that. Part of that is – inherent in that five-rig planning case, we have some cycle times embedded in there for the Delaware that we hope to improve on, and with that five-rig program, could probably do more with what we have. But we want to prove that out before we add another rig into the mix as we move forward.
All right. Great. Thanks for the time, guys.
Thanks.
The next question will be from Jeanine Wai of Citigroup. Please go ahead.
Hi. Good morning, everyone.
Hi, Jeanine.
Morning, Jeanine.
Hi. The 2018 plan includes progressing larger pad development concepts that you discussed, the mega pad in Monarch, for example. Other than this development, what's the average pad size for 2018 versus 2017? And what do you think the optimal pad size is, given your footprint, and whether or not the pad size plays into any execution objectives you have for this year?
Yeah. Wow, Jeanine, that's a big question, but in summary, I'll say it this way. We're really focused on fully understanding the asset base in its entirety in the Delaware Basin. And even though we've just finished a two-well pad, we're going to focus on single well pads primarily in the Delaware for this year. But in WildHorse, we'll go to two and three-well pads. And that's all aligned in some lease obligations as well as trying to mitigate this parent-child relationship that we talked about earlier, as well as deferred production.
So, it all depends generally on what our obligation wells are, how we want to mitigate future development impacts, as well as cycle time and efficient development for what we're trying to do throughout 2018. Monarch is where we're going to do the six-well pad. We invested in infrastructure several years ago. We're well setup with our own disposal as well as third-party disposal, as well as a recycle there to do that very efficiently. And we think that's the best place to jump right into that.
We're learning actually about a lot of things in pad size and development going forward. Given the pace that we think is a responsible pace to run and the capital levels to invest, we're partners in some multi-well pad development – multi-level, multi-well pad development in Howard County with some of our offset operators and we're learning a lot from that. So, more to come on it, Jeanine. It's something as we think about it in a lot of detail in our planning process in order to effectively and efficiently bring value forward. It's a little different in each area. But over time, we believe we're headed to bigger and bigger pads.
Okay, great. That's really helpful. Thank you. And then just following up or maybe asking a different way the prior question. You mentioned responsible development a few times in your prepared remarks and I don't think that's anything new. You guys have always consistently discussed maintaining long-term leverage of less than 2.5 times and 18-month plan of steady cash flow like you discussed. Can you just talk about at what point in Callon longer-term lifecycle does responsible development involve free cash flow, returning money to shareholders?
Yeah. I'll handle that. I guess, Jeanine, there could be a point in the future. Over the last couple of years, we've been focused on bringing forward the returns on capital that should be associated with roughly $2 billion that we raised in 2016. That has been our focus. We're getting to a point where as we continue to pull those forward, it is translating into corporate returns that exceed our cost of capital over the next several quarters. And that's been our focus for the near-term. So, we need to get to that point, which we don't see to be too far off, but that's central step one, right. We need to be earning return on our total capital propositions in excess of our cost of capital. That's the business, right. We need to just drive to that.
To move on from there, I think that we see opportunities to continue to consolidate assets in the basin and we think company at our stage of evolution, that's a better use of capital at this point than returning capital to shareholders. So that's our focus for the near term. On the longer term, if this asset base matures and we continue to grow, that might be on the table, but that's not something in the near-term vision for us.
Okay, great. Thank you for taking my question.
Sure.
The next question will come from Irene Haas of Imperial Capital. Please go ahead.
Yeah. Hi. Good morning. My question's on Delaware Basin and Ward County. You guys got some of the best acreage that I can think of. And just wondering if there's any plan to look at the Bone Spring, because there has been activities from your competitors. And then, ultimately, when you look at the Delaware Basin, understanding how well you guys have worked your margins in Midland Basin, do you think you can approach similar cash returns in light of the probably higher water handling costs?
Irene, great question. We've got some great acreage in the Delaware. We're happy to have it. We're happy to go learn as much as we can about it this year through the planned and dispersed development program that we have. We're very focused on reducing cycle time, managing costs out of system, as well as, as we've already discussed, building the appropriate infrastructure necessary to be very efficient with managing the higher water-loading that is associated with the Delaware. And I think we're ahead of the curve there. I think that the innovative and creative solution we've gotten with Goodnight Midstream, I've already referenced it, but there's – I can't speak too much more about it other than the water sourcing arrangement that we have with a third-party company.
The water recycling system that we're doing on our own self and do it with ourselves as well as in our own infrastructure is going to be very critical in managing costs. And so, we see plenty of opportunity to further improve the margins in the Delaware, similar to what we've done in the Midland Basin.
And so, therefore, you think at some point in time, if you work this hard enough, you should be able to capture similar margins. And then, second or third Bone Springs, any action going on there in your neighborhood?
Well, thanks for that reminder. Yeah. Thank you for that. Yes, we do plan to have a second Bone Springs test later in the year. And so, we're anxious to see that. We're seeing very encouraging results from our neighbors, just as you mentioned. And so, we still see plenty of opportunity up and down the column there even though we're focused primarily on the Wolfcamp A this year.
Okay. If I may, the water to oil ratio within the Upper Wolfcamp in Ward County, what is it now?
It's variable from well to well. That's why, again, it's important for us to kind of get a sense for what it's going to be across the acreage position, but it's anywhere from 3:1 to 6:1. It's variable. And again, it's kind of still early life on some of the wells we're talking about. So, it's certainly higher than the 1.5:1 to 2:1 that we see in the Midland Basin.
Great. Thank you.
Thank you.
Thanks, Irene.
The next question will come from Chris Stevens of KeyBanc. Please go ahead.
Hey. Good morning, guys. Maybe I'll just kind of get your latest thoughts on M&A. Are you looking to continue expanding your footprint? And if so, which area do you see the greatest opportunity to continue adding acreage?
I think, simply put, yes, we are continuing to look at expanding the footprint. The focus has largely been on continuing to bolt-on around our footprint in the four core operating areas and we've made progress in all four of them over the last several quarters. So, that'll continue to be the priority.
There are some potentially larger transactions we look at, but the way we think about that is we want them to be in and around our existing footprint. We're not looking to add a fifth core operating area at this point and grow our opportunities out there. There's a lot of transactions that didn't clear the market last year that are probably swinging back around, and we'll watch. But the good thing is we have a very deep inventory right now to work on these smaller types of opportunities that are very value added. They fit into the drilling program near-term and bring forward the PV proposition. We'll continue to look, Chris.
Okay, got it. And maybe just another one on the infrastructure side. There's definitely a lot of investment there in 2018. Could you kind of quantify or maybe just give some thoughts on where you see LOE may be exiting 2018? Do you see some pretty significant improvements over the course of the year? And then, also on that recycled water system, any estimates of what the sort of cost savings would be from that?
We see opportunities, Chris. I can't tell you what our – whether I'd project a number, but we certainly see opportunities. We just need to call it out one step at a time. And again, the recycled system, we'll certainly be competitive with anything that we see out on the – in third-party opportunities probably much better than that. But until we get up and running, I'm very hesitant to really talk about the numbers.
All right. Thanks a lot, guys.
Yeah.
The next question will be from Dan McSpirit of BMO Capital Markets. Please go ahead.
Thank you, folks. Good morning. You stated that you're not seeing much by way of early signs on cost inflation. Is there anything that better insulates the company that could make the 10% inflation factor look conservative, which I guess is a good thing?
Yeah. I mean, look, Gary pointed out that, I guess, over the last few months, we really haven't seen much in terms of inflation after – I'd say, it was a lot different last year. 10% was our working assumption for that metric. And certainly, we're going to continue to work hard and not be complacent just because we haven't seen it in the last three or four months, but we know that the potential is there with the increased activity in the basin. But I think we'll lean hard on strategic partnerships, which we have in the past that have bared a lot of good benefits for us.
We think, going forward, there's similar types of opportunities to work together. We are looking at incorporating more local sand into our completion designs. The pace and how that comes, I think we did take a conservative look at how that's going to all play out. But I think that conservatism was warranted because it's a lot of talk with (43:07) local sands. It's just the pace that's going to come and where the bottlenecks pick up. But that could certainly be one area that we do better than we expect. But overall, given such a dynamic market and trying to figure out how activity is going to play out from operators, how activity on new-builds horsepower is going to play out, it's good to have that cushion in there and we don't want to say that anything is conservative, but I think we can point to some tangible areas where we hope to do better as the year goes on.
And I guess I would just add to that that the things that potentially provide us some opportunity to manage cost better than some would be the infrastructure systems that we've made, the partnerships that we've established, the focus on reducing cost for every little aspect of our business, the drilling contracts that we have, the five-rig contracts, only one rig comes due this year. The rest are well into 2019.
The sand sourcing, even the direct sand sourcing we have, as well as the sand sourcing that we do through our pumping services relationships are all – they're not basin-specific. They're not directly only local sand or Wisconsin white sand. It's a blend of the two. And I think that was the best thing that we could have done to where we're not exposed to shortages.
Our plan for doing that type of work is, when local sand's available, we incorporate it into our program in an efficient way in order to manage costs. But if it's not, then we're going to keep moving efficiently forward with the solid sand sourcing relationships that we have.
From what we can tell with increased services, especially around pumping services, there's a lot of capacity coming to the basin, which we're excited about. And I think the basin still needs capacity, but it's a lot of capacity that's focused on being efficient, very efficient with the equipment that we have. And those are the types of companies we like to partner with.
So, I think we have good systems in place, good forethought in the past and how we built out our development plans and really, the partnerships that we have, have really been the best thing for us to manage upward swings in cost. There clearly had to be a correction in 2017. That correction has occurred. And now, it's getting more focused on pulling out cycle time and being efficient in leveraging the full supply chain of not only ourselves but the partnerships that we have.
Well, I appreciate the detailed response. And as a follow up, hoping you could share your view of the world. You described the company's approach is playing the long game, which to me, I think, speaks to running the company like an investment, not like a trade. Is there anything you see in the industry today where the business is approached more with a short-term view or maybe capital efficiency could prove to be overstated, thinking about the infrastructure spend that's needed basin-wide that could burden future returns?
I guess you bring up a couple of things in terms of, as we said, playing the long game. It really goes to the infrastructure investments we have made over the last couple of years when we did look past the short term outlook, right. It wasn't a popular thing to say, hey, we're going to spend over the normal percentage of D&C on an infrastructure. So, we own that because of the very reasons that we're starting to see bubble up in the industry, right.
And we talked about deep disposal wells last year, right. We've been ahead of that year-and-a-half ago, talking about going deep during the Ellenberger. We saw some of the issues pop up around shale salt water disposal zones last year. It was unfortunate that things came out that way, but for us, yeah, we were ahead of this. We've owned that. And I think as we think about playing the long game, we got ahead of a lot of these issues. So, as Gary said, the infrastructure investment for us is going to continue to taper starting in the sort of second half of this year that we're going to be stood up with the right saltwater disposal capacities. It can be an excess of 200,000 barrels of water a day outside of the Goodnight partnership, right.
We spent a lot there. We're getting ahead of some substations on the power side. We've got recycled frac pits already in motion. So, as we get to the back half of this year, we see this investment tailing off quite dramatically and position us for the long-term, not only from a cost perspective and the savings we get, but being responsible with things like disposal of water, not sourcing freshwater for fracs, recycling water. These all add up and I think position us to be a responsible developer, not only for shareholders but for communities and landowners as well.
Thank you.
The next question will be from Tim Rezvan of Mizuho. Please go ahead.
Hey. Good morning, folks. I was hoping to pick on the LOE topic a little more, given infrastructure is coming together. If we look at 2017, LOE, ex-G&T, was sub-$5. I'm just trying to understand the 2018 guide, which is sharply higher to the fully-loaded 4Q 2017 level. Is this conservatism given the pivot to the Delaware? Just trying to get some understanding on kind of how you're thinking about that line item.
The way I think about it, Tim, is that, yeah, there is some still learning and some cautious optimism around our ability to pull cost out of the Delaware, so that's part of it. There is an inflationary type of component that we've kind of factored into that that we hope can be more mitigated, maybe even fully mitigated out of that.
There's a couple of exposures that we're still very vastly improving upon that is primarily in the Midland Basin and it's in and around electrical sub-pump type run times that the whole industry is working toward improvement, that as we grow and grow that type of lift mechanism in the Midland Basin versus gas lift focus on the Delaware Basin, there is some exposure there that we think we're getting very good at. That is kind of factored in there also. So, if that helps explain it, I think we're conservatively optimistic that we can improve upon that, if those two words ever go together.
Yeah. Okay. It's good to be conservative. I appreciate that. And then, as my follow-up, you made a couple of comments I thought were interesting, really, only 5% of D&C CapEx this year is what you call outside of development drilling. You talked about in the release focusing predominantly on the Wolfcamp A in WildHorse. And it seems like the drilling is really being focused on sort of the best of the best and you're sort of eliminating kind of any uncertainty on the drill-bit. Why did you feel the need to do that focus in 2018? And how do you think about WildHorse longer term as far as viable commercial horizons that you'll develop?
As it relates to the program this year, and part of it is we are going to some larger pad designs, as Gary talked about, right. So, you're getting multiple wells in single zones and they happen to be very good zones. But as it relates to WildHorse, WildHorse certainly has a lot of potential outside of the Wolfcamp A. We do have wells in the Lower Spraberry and Wolfcamp B, as well as others. So, we are doing some of that activity this year as well. It's just that the focus is really on the Wolfcamp A. But even outside of the Wolfcamp A, there's good results in the Lower Spraberry and the B as well. So, I guess it's all sort of shades of gray. We have a lot of good opportunities there. We are getting efficient in single zones in certain areas as well. So, while we highlight those areas and show there's a clear path to getting into a pretty regular program development, it's not like we're not drilling other zones as well.
Okay. That makes sense. And just to clarify, the two Monarch pads of six, are those going to be Lower Spraberry?
Yes, both of them will be Lower Spraberry.
Okay. Thanks so much.
The next question will be from Derrick Whitfield of Stifel Financial. Please go ahead.
Good morning, all, and congrats on a strong year end.
Thanks, Derrick.
Throughout earnings to-date, gas evacuation has become a topical discussion point for Permian producers in light of growth plans within the region. While you guys are quite a bit older than your peers, could you comment on your thoughts on gas macro in the basin and how you position the firm to mitigate risk?
Thanks for the question. I think you started off right, and would remind everybody that about 77% of our equivalent net production is oil. Of the remaining 23%, roughly one half is natural gas that is sold into the Waha market. We're not seeing any flow concern issues to date. We have gas gathering contracts in place and our gatherers are incentivized to flow 100%. So, we're not seeing those issues to date.
We are actively considering some basis trades to mitigate differential risk. I know that this is an issue throughout the basin for some, but I just want to highlight on a revenue basis, a $0.25 per MCF movement in Waha differentials will impact our total revenues by less than 0.5% or 1%. It's really – for us, we have the flow capacity and it's just not meaningful when you add it all up.
Yeah. So, Derrick, for us, there's a financial element there that Jim had talked about. But when we started talking about this topic several quarters ago, it was really a focus on how do we move the gas volumes because we want the oil, right. I mean, we're close to 80% oil in Delaware. It's not like we're differentiated between Midland and Delaware. So, the focus of the team was let's make sure we can move the gas.
And I think going through that analysis, looking at the pipes and the takeaway, feel pretty comfortable that there is physical takeaway there. It might mean that you're getting into gas on gas competitions in markets that are going hurt the Waha basis. But in terms of evacuating and moving the methane volumes, we feel pretty comfortable. There's a pass out of the basin that just becomes a price aspect and we need to continue to work on how we mitigate some of those price impacts. Although, as Jim pointed out, even with some of that adverse movement, it's pretty negligible in terms of the grand scheme of our revenue picture.
Perfect. And for Gary, just a quick follow-up on your earlier WildHorse comment. In past calls, you noted the potential need to co-develop the Wolfcamp A and Lower Spraberry. Is that still your view based on all the data to-date?
Well, we think there's clearly discrete reservoirs there, but we think as we get further along, as we focus more on the Wolfcamp A in the near-term, that we'll incorporate more of that co-development. And as we even further learn more about how best the B might be connected, we may well go to a different pattern.
But, yes, the Lower Spraberry seems to be something now, as we think about it, that we can do at a later time and not have to co-develop as we see it today. And most of the industry is focused in Howard County on the Wolfcamp A, which is validating that view.
Perfect. Thanks.
And ladies and gentlemen, this will conclude our question-and-answer session. I would like to turn the conference back over to Joe Gatto for his closing remarks.
Once again, thanks for joining our call and we look forward to talking to you all again soon. Thanks.
Thank you, sir. Ladies and gentlemen, the conference has concluded. Thank you for attending today's presentation. At this time, you may disconnect your lines. Please note that a replay of this call will be available on the company's website for one year. Thank you.