Callon Petroleum Co (CPE) 2017 Q4 法說會逐字稿

Good morning, and welcome to the Callon Petroleum Fourth Quarter 2017 Earnings and Operating Results Conference Call. (Operator Instructions) Please note this event is being recorded. A replay of this event will be available on the company's website for 1 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 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 earning 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 and presentations page located within the Investor section of our website www.callon.com. Before we begin, I would like to remind everyone to review our cautionary statements and important disclosures included on Slide 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 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 turn the call over to Joe Gatto.

Thanks, Mark, and thanks to everyone for joining us this morning. Our quarterly earnings release was out yesterday along with the 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 a reaffirmation of the Callon brand and the underlying values that have guided us for over 6 decades. These principles of doing business has 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 the cash margins and enhance 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 in 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 proven 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 had robust production contributions from all 4 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 was 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 in 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 2 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 will highlight that advantage in terms of recycle ratio metrics here shortly.

In addition to this margin expansion over the last several quarters, consistent improvement spanned across many other key drivers our business as you can see on Slide 6. Over the past 2 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 cost 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 readily apparent that our operational model has been successful in capturing the value embedded in our high-quality acreage position against a 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 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 a 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 at 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 1 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 bank-free 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. The growth is one thing, quality growth is another, and you could 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 cost 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 at attractive development costs, we are 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'll 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 1st 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 spot 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 6 well mega-pad concept at Monarch is utilizing 2 side-by-side 3 well pads targeting a single zone to replicate a larger 6 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 2 wells offsetting historical production to determine the efficacy of potential of 460 foot spacing. Another important point about our operational plan for this year lies in the frontloading 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 cost.

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 1st 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 4 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 are 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 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's 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 ducts for operational flexibility and weather-related disruption from the -- 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'm 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 31st. We also continued to screen well from a debt to EBITDA perspective as our strong cash flow from operations continued 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 hedged contracts are outlined on Slide 14 and provide a breakdown showing a floor price of around $50 a barrel for 2018. Roughly 2/3 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 will 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 will 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 allow us to talk through a very successful year for us in 2017 and set the groundwork for the path forward in '18.

With that, we will turn it back to the operator for Q&A.

(Operator Instructions) and your first question will come from Neal Dingmann of SunTrust.

This is Josh 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 2 type spacing. How do you see these risks for Callon or the industry and what steps are you kind of taking to mitigate these?

No, Josh, thanks for asking. Yes, 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're wanting to, 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 in-field drilling just similar to what we did in Chasm where we have our Casselman and really some parts are Ranger, we have the majority of our experience with parent-child relationship dewatering 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 and in Reagan County and as we've down-spaced the Lower Spraberry and Midland County primarily around all of 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 to now in Monarch this year to further minimize and mitigate the impact of deferred production from dewatering existing wells as well as more effectively and efficiently propagating effective fracture simulations into the 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 there'll be different, but I think the data that we've shown here is that it seems to be working well and there'll clearly be impact, we 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 to follow up, you guys have been very 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 have midyear?

We're well ahead of what our needs are, Josh, but our production growth both in water and oil is, 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 at -- 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 in the 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 and 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 on 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.

The next question will be from Gabe Daoud of JPMorgan.

I was hoping we could maybe start a little bit on the Saratoga well in the Delaware Basin. I was curious if this was one of the operated completions in which you intended on reigning in proppant intensity and just overall completion intensity in an effort to get the well cost down? So maybe if you could just talk a little bit more about the completion design and the cost?

Yes, we pulled back sand-loading a little bit on that well, Gabe, just like we had intended to, 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 yes, we pulled back on sand-loading just like we said we would.

Moving on I guess, Wolfcamp C, nice result there, curious about any updated thoughts on the Wolfcamp D. I know at one point you did plan on touching the zone at Ranger in 2015 just given some recent competitor results do you think about testing that at any point this year?

There was a lot in that question, but again, I want to emphasize what we're very focused on efficient development throughout the year, but we are encouraged with the Wolfcamp C in Reagan County. It's very early time, you guys know I don't like talking about single well results, I 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 or 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 the 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 in -- at the end of 2014 to the Monarch area. There are 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.

Yes, so I think, Gabe, overall we do have some delineation work going on in both Midland and in Delaware but as it relates to our overall program it is in single digits on a percentage basis in terms of capital exposed, so some of that having some lower working interest which helps us get into 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 D offsetting us in Reagan.

And just one last one from me. Just on infrastructures then, can you maybe explain a little bit on the comment of potentially divesting more? As of this year at some point and then also spending about 20% of D&C I'm assuming this year, does that normalize to like 10% or so as you move forward in 2019 and beyond?

Yes, 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 more 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 in WildHorse and in Spur in a very short period of time. We 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.

(Operator Instructions) And the next question will come from Jeff Grampp of Northland Capital Markets.

Just I don't want to spend too much time on the one Wolfcamp C. well, but I was just hoping maybe to get a little bit more color on maybe any interpretation you can give really on that oil cut, it seemed to be a little bit more favorable than some of the peer Wolfcamp C bench well, 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 are expecting?

Again what I'm 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. So but I would expect and I would kind of hope I would see a little bit more gas energy come with it. It 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 see a lot of folks talking about free cash flow generation and kind of lines of sight to some inflection points. Can you just maybe give us an 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?

Yes, I think nothing has changed on our part and whenever we had activity, we want to see a path to 4 to 6 quarters out getting back to a point where we are cash flow neutral. We will make a lot of progress during '18 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 5-rig program with 2 dedicated frac crews. We don't see any increase to that. Part of that is inherent in that 5-rig planning case, we have some cycle times embedded in there for the Delaware that we hope to improve on and what that 5-rig program can 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.

The next question will be from Jeanine Wai of Citigroup.

The 2018 plan includes progressing larger pad development concepts that you've 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 sizes given your footprint and whether or not the pad size plays into any execution objectives you have for this year?

Well, 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 2-well pad, we're going to focus on single well pads primarily in the Delaware for this year. But other way in WildHorse, we'll go to 2 and 3-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 6-well pad. We've invested in infrastructure several years ago, we're well set up 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 running 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.

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 2.5x and 18-month line of (inaudible) 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?

Yes, I'll handle that. I guess, Jeanine, there could be a point in the future over the last couple years we've been focused on bringing forward the returns on capital that should be associated it with roughly $2 billion that we raised in 2016. That has been our focus for getting to a point where as we continue to pull those forward, it is translating into corporate returns that exceed our cost 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 a step -- central step one, right? We need to be earning return on our total capital propositions excess of our cost of capital, that's the business, right? We need to strive 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 and returning capital to shareholders, that's our focus for the near term. On the longer term, as this asset-based matures and we continue to grow, that might be on the table, but that's not something in the near-term vision for us.

The next question will come from Irene Haas of Imperial Capital.

My question is on Delaware Basin and what 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 that 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 see you can approach similar cash returns in light of the probably higher water handling cost?

We've got some great acreage in the Delaware where 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 cost out of the 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. I think we're ahead of the curve there. I think that the innovative and creative solution we've gotten with Goodnight, Midstream, the -- I've already referenced it, but there's -- I can't speak to 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 -- with ourselves as well as in our own infrastructure, is going to be very critical in managing cost. 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 Spring, any action going on there in the neighborhood?

Well, thanks for that reminder. Thank you for that. Yes, we do plan to have a second Bone Spring's 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.

If I may, the water to oil ratio within the upper Wolfcamp in Ward County, what is it now?

It's variable from water well. That's why again it's important for us to kind of get a sense for what is going to be across the acreage position, but it's anywhere from 3:1 to 6:1. It's variable. And again, it has still early life on some of the wells we're talking about. So it's certainly higher than the 1.5 to 2:1 that we see in the Midland Basin.

The next question will come from Chris Stevens of KeyBanc.

Maybe I'll just kind of (inaudible) to start 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 4 core operating areas and we've made progress in all 4 of them over the last several quarters. So they'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 or 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 lot of transactions that didn't clear the market last year that are probably swinging back around and we will watch, but the good thing is we have a very deep inventory right now to work on. The smaller types of opportunities are very value-added, they fit into the drilling program near term and bring forward the PV proposition. We'll continue to look, Chris.

And maybe just another one on the infrastructure side. There's definitely a lot of investment there in 2018, can you kind of quantify or maybe just give some thoughts on where you see LOE maybe 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 what the sort of cost savings would be from that?

We see opportunities Chris. I can't tell you what they're out of or 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 will certainly be competitive with anything that we see out on the -- and 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.

The next question will be from Dan McSpirit of BMO Capital Markets.

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?

Yes, I mean, look, Gary pointed out 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 last 3 months or 4 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 are 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 and I think -- but I think that conservatism was warranted because through our talk with local sands the pace is 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 it's -- 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 growing contracts that we have, the 5-year contracts are only -- one rig comes due this year, the rest are well into '19. The sand sourcing of 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 based on specific, they're not directly only local sand or Wisconsin white sand, it's a blend of the 2 and I think that was the best thing that we could have done the way we're not exposed to shortages. Our plan for doing that type of work is when local sand is available we incorporated into our program in an efficient way in order to manage cost, 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 a ramp-up in 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 build 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.

And as a follow-up, hope you could share your view of the world. You described the company's approach is playing the long game which to me 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 bringing up a couple of things in terms of as we said planning 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, it wasn't a popular thing to say, hey, we're going to spend over the normal percentage of D&C on an infrastructure, but we own that because of the very reasons that we're starting to see bubble up in the industry, we talked about the disposal wells last year. We've been ahead of that 1.5 years ago talking about going deeper in the [Alan Berger], we saw some of the issues pop up around shale, saltwater disposals on last year. It was unfortunate that things came out that way, but for us like, yes, 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 can be in excess of 200,000 barrels of water a day outside of the Goodnight partnership. We spend 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 in 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.

The next question will be from Tim Rezvan of Mizuho.

I was hoping to pick on the LOE topic a little more given your infrastructure is coming together if you look at 2017 LOE [ex-GNT] were sub $5, I'm just trying to understand the 2018 guide which is roughly higher to the fully-loaded 4Q '17 level, is this conservatism given that the pivot to the Delaware -- just trying to get some understanding on how do you think about that line item?

The way I think about it, Tim, is that, yes, there is some still learning and some cautious optimism around our ability to pull costs out of the Delaware, so that's part of it. There is an inflationary type of a 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 couple of exposures that we're still very vastly improving upon that is primarily in the Midland Basin, and it's around electrical sub-pump type runtimes 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 the -- we're conservatively optimistic that we can improve upon that if those 2 words ever go together.

Then as my follow-up, you made a couple of comments about (inaudible) of 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 trailing 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, but why did you feel the need to do that focus in '18 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 as Gary talked about, right, so you're getting multiple wells and single zones, may 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 Lower Spraberry and Wolfcamp E 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 it's -- I guess it's all sorts 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 pretty regular program development, it's not like we're not drilling other zones as well.

And just to clarify, the 2 minor pad offsets, so those are going to be Lower Spraberry?

Yes, both of them will be Lower Spraberry.

The next question will be from Derrick Whitfield of Stifel Financial.

Throughout earnings to date gas evacuation has become a topical discussion point for premium producers and might have growth plans within the region. You guys are quite a bit oilier than your peers, could you comment on your thoughts on gas (inaudible) in the basin and how you position the firm to mitigate risk?

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 1/2 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 $0.25 per MCF movement in Waha differentials will impact our total revenues by less than 1.5% or 1%. It's really for us we have the flow capacity and it's just not meaningful when you add it all up.

Yes, so Derrick for us there's a financial element there that Jim had talked about, but when we start talking about this topic several quarters ago, it was really a focus on how we move the gas volumes because we want 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 in the takeaway feel pretty comfortable that there is physical takeaway there, it might mean that you're getting into gas on gas competitions and markets that are going to hurt the Waha basis, but in terms of evacuating and moving the methane volumes, we feel pretty comfortable there is pass-out of the basin, it just becomes a price aspect and we need to continue to work on how we mitigate some of the 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.

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 data to date?

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 on -- in Howard County on the Wolfcamp A which is validating that view.

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 1 year. Thank you.