Callon Petroleum Co (CPE) 2017 Q1 法說會逐字稿

Good morning, and welcome to the Callon Petroleum First Quarter 2017 Earnings and Operating Results Conference Call. (Operator Instructions) Please note this event is being recorded. (Operator Instructions) I would now like to turn the conference over to Eric Williams, Manager of Finance. Please go ahead.

Good morning, and thank you for taking time to join our conference call. With me this morning are Fred Callon, Chairman and Chief Executive Officer; Gary Newberry, Chief Operating Officer; and Joe Gatto, President and Chief Financial Officer.

During our prepared remarks, we'll be referencing the earnings results presentation we posted yesterday afternoon to our website, so I encourage everyone to download the presentation if you have not 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 will make some forward-looking statements during today's call that refer to estimates and plans. Actual results could differ materially due to the factors noted on these slides and in our periodic SEC filings.

We will also refer to some non-GAAP financial measures today, which we believe help to facilitate comparison across periods and with our peers. For any non-GAAP measure we reference, we provide a reconciliation to the nearest corresponding GAAP measure. You may find these reconciliations in the appendix to the slides and in our earnings press release, both of which are available on our website. Following our prepared remarks, we will open the call for Q&A.

And with that, I would like to turn the call over to Fred Callon and direct the audience to Slide 4 of the earnings presentation. Fred?

Thank you, Eric, and thanks to everyone for joining us this morning. We are off to good start so far this year with double-digit production growth coupled with a 17% reduction in our LOE. This is our first earnings call since closing our Spur acquisition, which expanded our acreage footprint into the Sub and Delaware basin. In total, Callon now controls approximately 60,000 net acres including pinning bolt-on acquisitions in the Spur area that we signed since mid-February. Our position is concentrated in core areas of both the Midland and Delaware Basins evidenced by extended well performance tracking 1 million barrel type curves across the entirety of both our Wolfcamp and Lower Spraberry program since mid-2016. The majority of these wells results were from Monarch and Ranger areas, that we believe will be further enhanced by our increased component of wells in the WildHorse and Spur areas. For example, our initial wells in the northern section of WildHorse have led to an increase in our type curve to 1.3 million barrels of oil equivalent from the oil composition of 85%. In addition, the Lower Spraberry A well completed by the previous operator in Spur continues to flow under natural pressure and has produced over 100,000 barrels in the first 90 days, since first oil. We're encouraged by these results and believe that they -- that with it, we have the opportunity for further upside potential in these areas in terms of both additional flow units and refinement of completion designs and landing zones. As we look at the upcoming impact of these 2 newly acquired areas, WildHorse is in full program development mode with 2 rigs that will bring 6 wells online across 3 zones in the second quarter. Shortly after that, we'll be adding our fourth horizontal rig to the Spur area and expect to bring on our first well later in the third quarter.

Turning to Slide 5. Slide 5 outlines some of the key points of our execution strategy for the next several quarters. As we seek to accelerate robust returns in our broad portfolio investment opportunities. As always, we will be focused on full cycle returns and be investing in proper infrastructure and facilities to increase capital efficiency. We will also remain focused on preserving our strong balance sheet and liquidity position, which will allow us to manage any commodity price volatility as well as opportunistically add bolt-on acreage at attractive prices prize within our existing financial means. Overall, we see 2017 as a year that will highlight the growth potential of our WildHorse position underpinned by the underlying strength in our Monarch drilling program as wells as to return to drilling in the Ranger area. As we look out into 2018, Spur will become another key growth driver for Callon, as we target an exit rate of over 40,000 barrels of oil equivalent per day, roughly double from the production rate in this past quarter. I'll now turn the call over to Gary Newberry, our Chief Operating Officer. Gary?

Thanks, Fred, and good morning to everyone listening today. I will begin on Slide 6 and highlight the steady increase in completion activity as we progress into 2017. The first quarter was weighted towards WildHorse Wolfcamp A in Lower Spraberry, which will continue into the second quarter with the addition of a Wolfcamp B well in this operating area. We also plan to bring on wells in all 3 of our other operating areas in both the Midland and Delaware Basins, targeting the Lower Spraberry, Wolfcamp A and Wolfcamp B. On the lower half of the page, we've summarized the cumulative production from all of our operated areas that were placed online since the end of the second quarter of 2016. On average, both of our major drilling programs are delivering performance in line with $1 million barrel oil equivalent type curves, which is clear testament to the quality of our inventory and the ability of our team to appropriately apply technology in the interest of long-term performance.

Moving to Slide 7, we've highlighted a few key operational parameters that are essential to our efficiency and ability to deliver strong internal cash flow margins. Starting with LOE, we have successfully addressed the transitory downhole issues experienced during the fourth quarter of 2016 with workovers returning to a normalized level. The bottom 2 bars in the LOE chart, saltwater disposal and fuel and power are squarely in focus for the team and represent a significant opportunity to further reduce LOE as the year progresses. We expect the impact of continuing investments in water infrastructure and WildHorse, combined with our discussions with third-party providers will become apparent in our cost structure in the second half of the year. We're also close to transitioning several areas to permanent power allowing us to move away from costly generators currently being used to power artificial lift. In total, we see the opportunity to reduce our LOE by $0.50 to $0.60 per BOE from these 2 line items. On the bottom of the slide, our D&C cost-per-lateral foot continue to be below our 2017 capital plan through 2 quarters of AFEs. Importantly, we expect this metric to be benefited in the second half of the year as our capital efficiency per well improves with a 15% increase in planned lateral length. I will now turn to specific commentary on our 2 new core areas beginning with WildHorse on Slide 8. As we've discussed previously, infrastructure has been a gating item, but we've made substantial progress on this front. Including the construction of 5 central tank batteries and substantial completion of 14 miles of water gathering lines. We're also in the process of complementing our current portfolio of saltwater disposal facilities with access to a growing list of third-party providers and also have permits in place to commence drilling on additional owned facilities in the near term. On the back of these investments, we're positioned for an acceleration in WildHorse activity and expect to have 12 total wells that have been drilled and completed under Callon operatorship on production in 3 distinct zones by the end of the second quarter. The bottom right-hand chart highlights the repeated strong performance of our Wolfcamp A program that started last year with the Silver City completion as well as 4 additional wells that are currently flowing back in central and northern Howard County. We provided more details regarding specific well performance on the next 2 slides. On Slide 9, the chart illustrates the performance of our recent Wolfcamp A completions in the colored lines against the backdrop of wells drilled by previous and other operators on our acreage that are in gray. We targeted the Wolfcamp A as an ideal candidate for larger proppant loadings and have seen an exceptional response in production as a result. Based on this data as well as surrounding well performance, we're increasing our Wolfcamp A type curve in northern Howard County to 1.3 million barrels oil equivalent compared to our initial curve of 700,000 barrels oil equivalent that was used as part of our Big Star acquisition analysis just 1 year ago. As our drilling activity moves to the central part of the county, we will have a similar opportunity to revisit our existing type curves in the second half of 2017. Slide 10 presents a similar analysis for the early time performance of our Lower Spraberry program. We applied a similar philosophy to this zone, using a larger proppant loading versus legacy completions, which we've demonstrated to have a positive impact on the Lower Spraberry program in our Monarch area. Based on early time data, the new wells are tracking the legacy wells that support 850,000 barrels oil equivalent type curve. However, we have seen other Lower Spraberry wells in the area exhibit strong performance after an extended dewatering period of up to 90 days and subsequently produce above their initial type curve trajectories. As we continue to watch these wells, we will also be testing smaller proppant loadings combined with an overall completion design focused on near wellbore intensity in our next Lower Spraberry wells to provide additional data points for future refinements. Slide 11 summarizes our execution focus for the WildHorse assets in the next few quarters. We look forward to substantially completing our infrastructure build-out in the third quarter in support of a 2-rig drilling program expecting to place 27 wells on production during 2017 with an average lateral length of approximately 8,000 feet. We will be active in all 3 delineated zones and gathering data that will be used for optimal resource development in terms of both well density and completion sequencing.

Turning to Slide 12. I will now spend a few minutes on our newest position in the Delaware Basin, which we refer to as Spur. In the short 2.5 months since we closed our initial acquisition, we've been very busy in this area. One of the attractive elements of this acquisition was our expectation that we could build on this initial position with direct bolt-ons that would increase our lateral lengths and add incremental locations at attractive valuations. We've been able to capitalize on this opportunity very quickly adding over 2,600 net acres on or adjacent to our Ward County footprint at just over $20,000 per net acre. These agreements increase our Delaware acreage by approximately 15% and enhance our current inventory by nearly doubling the length of over 90 laterals while adding over 40 new delineated locations and increasing our working interest in existing wells. On the operations front, we completed the Wolfcamp B well that was drilled by the previous operator, and have been upgrading the capacity of the saltwater disposal wells that we acquired with the position in preparation of a dedicated rig in early July. We've also been producing an existing lower Wolfcamp A well and monitoring its performance as it continues to flow naturally under controlled pressures. This well, the Corbets 34-149 2WA is important for 2 reasons. One, it's been a strong performer, producing a cumulative 100,000 barrels oil equivalent with 90% oil in the first 90 days; and two, we'll be able to use the whole core data taken during the drilling of this well to refine our future completion plans and landing zones.

Slide 13 provides an example of how the core data will be used to refine landing zones to more effectively access the resource potential. Importantly, the analysis continues to confirm our views of the high quality of our position and in some elements much better than anticipated. Given the reservoir quality and high oil in-place targets, we believe that outsized proppant loadings and associated costs will not be required to drive exceptional returns. The Corbets well and our recently completed Wolfcamp B well, the Saratoga 34-161, both employed approximately 2,800 pounds per foot in the completion design. We will be targeting between 2,000 and 2,500 pounds per foot in our upcoming wells later this year. As we move forward to validate our findings, we will continue to use the whole core to evaluate the full potential of the thick organic-rich hydrocarbon column across our assets including other shallow and deeper zones. Similar to the WildHorse discussion, Slide 14 outlines our execution strategy related to Spur including the currently planned drilling of 5 additional wells in the upper and lower Wolfcamp A. We're out of the gates early and positioned to accelerate activity in the coming quarters with Spur becoming a meaningful growth driver in 2018. We're in the process of upgrading existing saltwater disposal infrastructure with larger tubing and added perforations to support the development program. We expect to be positioned for 2 rigs of activity by early 2018.

Finally on Slide 15, we provided an updated view of our inventory count -- because focusing just on areas and zones that we believe to be de-risked based on current data. With a delineated opportunity base of over 1,500 locations, that we expect to generate average wellhead returns of around 90% with associated payback periods of 15 months to 24 months under the assumption of $50 flat oil prices. We're well positioned for sustained production growth from increased drilling that will be primarily funded through internal cash generation. I will now turn the call over to Joe Gatto, President and CFO, for the financial discussion.

Thanks, Gary. I'll be picking up on Slide 16. For the quarter ended March 31, Callon reported net income of $0.22 per fully diluted share and adjusted income of $0.10 per fully diluted share, which excludes the after-tax effects of certain nonrecurring items and noncash valuation adjustments. The adjusted income figure also includes a theoretical tax provision $0.07 per diluted share for the quarter as if the valuation allowance for deferred tax assets that was established in 2016 did not exist. We also reported adjusted EBITDA of $56.7 million, a sequential increase of 21%. Both of these non-GAAP measures are reconciled in our press release. On the revenue side, total daily production volumes grew at a sequential rate of 11%, including a 14% increase in oil only volumes. Our average realized price per BOE produced in the quarter was over $44 on an unhedged basis driven in part by an oil percentage of 78%, which remains amongst the highest in our peer group. Cash operating expenses benefited from a 17% sequential decline in the quarter and contributed to an adjusted EBITDA margin an excess of $30 per BOE. This internal operating cash flow was in excess of our cash operating CapEx spent per BOE, even with the increase in rig activity that began in January.

Turning to Slide 17, we provided a snapshot of our financial position at quarter-end highlighted by a liquidity position of over $500 million including $35 million of cash balances. We're currently in the process of a borrowing base review, which will now include the producing assets in our Spur area and expect our liquidity position to improve further after that review. We've also highlighted our solid leverage metrics, which remain below our planning case target of less than 2x net debt to adjusted EBITDA on a pro forma basis, including the assumed cash and credit facility funding of our pending Spur bolt-on acquisitions that were discussed earlier.

Slide 18 details our guidance for the second quarter of 2017 and a reiteration of our full-year metrics. We're forecasting another quarter of sequential production growth in the range of 10% over the first quarter, combined with continued progress and LOE reductions as the positive impact of recent infrastructure initiatives materialize.

And finally on Page 19, I'll wrap up with a couple of quick comments. Consistent Wolfcamp and Lower Spraberry development programs, they're both tracking 1 million BOE type curves on average across our broader portfolio highlight a strong foundation for Callon to build upon in future years. With our recent results and type curve increase at WildHorse, combined with the encouraging data points that continue to emerge in the Spur area and the Delaware Basin, we expect our average well performance to trend even higher over time with increased capital allocation to our 2 new operating areas. We're clearly excited about the near-term opportunities set at both WildHorse and Spur after positioning our sales for efficient program development in terms of both infrastructure and completion refinements. And we'll have 3 combined rigs running on these 2 positions by July. I will now turn the call back to Fred.

Thank you, Joe. I think Joe summed it up pretty well there as far as why we're all excited about 2017. So with that, I think we'll open the call to questions.

(Operator Instructions) The first question is from Will Green at Stephens.

I really like Slide 9 where you guys are showing the WildHorse performance. I noticed some things I did want to ask about. Mainly this Wright-Adams Wolfcamp A definitely looks similar on IP per foot basis as that Silver City well? Looks like it may be able to catch that well. I wonder if you guys could provide any additional color on how the flowing pressure compares on those 2 at this point in the well or just any general thoughts on -- if you think that's possible, this could be as good, as we get more data on this well?

All right. I just want to make sure I'm talking about the right well, the Garrett-Reed or the Wright-Adams?

The red one on the -- on 9, that's Wright-Adams, right?

Right. Yes, the Wright-Adams, I'm sorry. I just wanted to make sure I was talking about the right well. Yes, we're very excited about that well. It still has potential to further outperform where we're at. The pressures are good, and I'll even include the Cheek well. The pressures are good in that entire area. That whole area even though we have limited production data on the Cheek, that gave us a lot of confidence that we could move this type curve the way we did. And the obvious question is when are we going to move it a second time, right? And I just have to be a little bit -- as you know how I am, I think give us another 3 months to 6 months, so we may be moving this again. But there's a lot of potential in the Sidewinder area of Howard County within our WildHorse assets. And we believe there's similar potential in Maverick as well as Fairway. We just need more time to demonstrate that with the type of completions we're putting on these wells. And also be able to get the additional infrastructure in place to really unharness the full potential of these wells. Some of these wells are still, even though we're showing you good data, they're still somewhat restricted simply because of water management infrastructure, that's not quite fully built out yet. There's plenty of potential here, Will.

Yes, definitely very impressive results. And then the other thing I wanted to ask about, and you kind of mentioned it on this Spraberry update over in WildHorse. On Slide 10, the dewatering that's going on, I know that -- when we were in early days of Lower Spraberry development for some of the bigger operators in the Midland Basin, I specifically remember seeing like 60 to 90 days before we saw these wells clean up. But once that happened, you started to see them actually even outperform the type curve for some of those really good Wolfcamp wells. I think you kind of alluded to expecting to maybe see that. Is there kind of a rule of thumb that we could think about on how much frack load to recover, how much have you recovered? Just any additional color on what you guys are expecting to see before you feel really good about how this well starts to track?

I think you're right, Will. I think it is beyond 90 days of flowback and maybe between 90 and 180, that we ultimate get these wells functioning the way we think they're going to function, and the way they're going to perform. We certainly have every confidence of meeting this type curve and over time hopefully exceeding it. Spraberry is an interesting -- very interesting opportunity set for us here at Sidewinder because -- or throughout the entire basin actually, because, again the Spraberry was developed from the north or it was deposited from the north. So there is varied large grain sizes in and around this area. So a lot of porosity, a lot of permeability, a lot of oil in place. And frankly, as we applied on these wells -- these larger fracks, because we fracked these wells with 2,000 pounds per foot of proppant. We went into this fully recognizing it may well take longer time to dewater, because we're accessing even a greater part of a reservoir with significantly more load. So time will tell on these 2 wells, but we're confident in the area and we'll even try to refine that. The next to Lower Spraberry that we pump, we're actually going to go, pull back on that load a little bit to see if we can actually get this time for dewater and enhance performance even better refined for the longer-term development of Lower Spraberry throughout the county. So clearly, wait and see, just like us and other operators in the history of this area has shown, but we're going to get -- we're very focused on refining this and get this to the point where it's the best value component for our development.

The next question is from Ron Mills of Johnson Rice.

Gary, just really a follow up to Slide 9. First is, when I look at the Maverick area and tracking that million barrel type curve versus the 1.3, obviously, it's your first completion down there, but between the Maverick and upcoming Fairway completions, is it early days still there, or do you think in terms of completion and then targeting refinements that those areas can also track a higher type curve or is there a change in the rock?

No, it's early days, Ron. It's very early days. We're about to complete our -- (inaudible) first completions of our Wolfcamp A and Fairway, I can tell you that this Maverick area is a great area, but frankly, just in the way we're managing water right there. Again, this is one of the wells that I'm convinced we really haven't unleashed the full potential of, simply because of some of the restrictions in managing water in and around some of these areas. We're fixing all that. We'll have all that fixed in the third quarter. So it may be third quarter before we know the full potential of these wells going forward without all these other interruptions that happened as we're fracking wells through some of these drilling requirements that we had with the Plymouth acquisition right next to wells that we brought on line. So that just puts a dampening effect on the overall performance that you see. And until I get that done, frankly I'm excited about what this Garrett-Reed's doing at Maverick. But I'm confident I can do better. But it's just more time and really more wells, both in Fairway and Maverick, before I'm ready to move that curve. I'm confident I'm already exceeding the type curve that I bought it on. But at the end of the day, I'm not ready to tell you where I think I'm going to move it to, if that's fair?

No. No, for sure, that's actually great to hear. And then moving over to the Spur area. Can you talk a little bit about what the core information you're focusing on from the core data from both the Corbets well, which has had a very flat profile, and in the Saratoga, the Wolfcamp B well, trying to figure out from the core data versus where those ducts were located. Do you think there's opportunities for lateral placement and improvement in drilling design or what's the main triggers you're looking for?

First of all, we're ecstatic about having that core, right. And Von Gonten has done a phenomenal job for us in evaluating that core and describing the opportunity set throughout it. And we're very focused on Wolfcamp A and Wolfcamp B at this present time because we see significant opportunity there. But what we're actually seeing in general, because I don't want to describe all the learnings that I have from the core even as exciting as it is. In general, I can tell you that we're seeing a very organic-rich section, right, that's no big surprise. And we're seeing the development of various fractures swarms throughout the core and in various positions of the core that can potentially get us to access some natural fractures in that core and enhance the overall productivity, or certainly early time and longer-term recoveries, by moving those landing positions slightly from previous wells. And we're working directly with Von Gonten's team to help us better understand how to efficiently access the full resource potential and really how to efficiently develop this whole zone including the Wolfcamp B and the excitement even around the Wolfcamp C. When you look at the core, the Wolfcamp C looks even better than the B. So in general, those are some descriptions I'll give you without having the full geochemistry and rock mechanics report in front of me, it's pretty exciting.

And then, Joe, is it fair to assume because the 2018 exit rate that you've talked about previously is still the same, that there is upside there given the improvement in the type curve especially at least in the Sidewinder area?

I think that's fair, Ron. We haven't updated that number for that very reason, just to see how some things play out, our development plans as you remember, we developed that baseline [2-year look] assuming a fifth rig in January of 2018 comes in the Midland Basin, but following on what Gary said and some of the excitements that we see in the Delaware, I think there's a very good chance that fifth rig gets up in the Delaware Basin come January, which we'll have a chance to revisit our whole plan. So I would say that it's a very good baseline and we hope to do better than that on an exit rate basis in '18.

The next question is from Irene Haas at Wunderlich.

Congratulations on all the work that you guys have done in the east and Midland Basin. And my question for you is, as you step back, you're doing a lot sort of stack pattern. And so do you have a feeling as to when it's really finally in the development mode, how you would tackle it? For example, for each pad would you go in and tackle all 3 or 4 pay zones? And if yes, any feelings as to at what density you would space the wells? So these are my questions.

Yes, Irene, we're very focused on and how we go forward. And we're not quite ready to describe that in detail by asset yet and we'll probably change by asset, right? The Lower Spraberry has been a phenomenal asset and Monarch. But the Wolfcamp A and Wolfcamp B are exceptional as well. I mean, so -- we have multiple layers that have equivalent economics essentially and they've been even proven further by the companies that are surroundings us like RSP and Diamondback, the significant upside associated with that. So we can now start thinking about going in and doing program development in a very efficient managed way to where we can minimize the overall impact to existing production by future fracture stimulations. And you had other companies now that they kind of got everything working through their drilling obligations to hold the leases, but then getting into program management like we have. We have very few drilling obligations and by the end of the year, we'll be finished with most of those at WildHorse. We'll then be able to minimize or that deferral of production as we're hitting ourselves with an offset frack, and we can then efficiently go into an area and start developing it out. So like I just mentioned, Lower Spraberry, Wolfcamp A, Wolfcamp B and Monarch, we have options of doing it either horizontally or vertically. And the team's focused very much on that right now. Because we're getting into -- where we want to get to is very efficient program development once we get to this 5 rig program, and then where would we go with the next acceleration beyond that. And then in WildHorse, gosh, we're still evaluating as we [talked] the excitement around the A, and Fairway and Maverick. We'll have those data points in the next few months and then we can talk about Lower Spraberry A type developments and we're still looking at the potential for the B. So we're still defining that potential in WildHorse. So we're not quite as advanced in WildHorse as we are in Monarch. So that will still be a work in progress. And then, Spur, I've already talked about the excitement of the core, I won't get back into that. But there's tremendous potential there, that we're continuing to see on our own assets and we're excited to even deliver from our own assets in the second half of the year, but just the exceptional results that are being reported from others. This brings tremendous excitement about that position all in all. And gosh, with all that excitement, I'm still excited about having assets like Ranger, to have that's -- all held by production, deliver solid returns and I can still go back in there and bring that forward at whatever time frame I want to or choose to do so in the future. So with that -- I know that's not a lot of detail, but it's all still a work in progress, but the team's are very focused on the efficient delivery of value from all the different levels within our asset position and some is more clear than others, simply because of where we are in the maturity curve for each of the assets.

The next question is from Jeb Bachmann at Scotia Howard Weil.

Just quickly on Howard County. I know it's on Slide 11. Gary, you mentioned that you're looking at optimizing or refining the landing zone in the Wolfcamp B, but you didn't say that for the Lower Spraberry. Do you guys think you're in the right area on the Lower Spraberry?

We think we are. We think we are, but we got to understand exactly the full cycle of how that gets to be dewatered. We got to get set up to where we can efficiently dewater, right. Again, everyone in the county is managing or challenged with the same issues. And then we've got to figure out how best to access that resource. So I think we're, but we're certainly watching every data point that is coming available to us, so further refine that as we go forward.

Okay. And then, you also talked about doing higher density tests. Can you tell us kind of where you are currently and where you are going to on the spacing numbers?

I don't have the number that I want to talk about yet in Howard. We've talked about density in Monarch at some length. We haven't given an update on that this time, from 11 to 13 wells per section in the Lower Spraberry. But -- we'll continue to work through that, and -- but I don't really have anything beyond our current inventory that we've already published, Jeb.

Okay, and I guess last one from me. How is that down spacing test performing in Midland County? Is that still kind of with the expectations?

Yes, it is. Again, you'll have been very patient with me on Midland County, and I appreciate that. The wells that were actually currently flowing back, were the ones that I wanted to get behind me and they're just now coming online. It's in the Casselman area. It's the wells that are actually the infill wells between 2 wells that are -- 2 sections of wells that have been drilled on each side of the pad. And again, we've refined our fracture technique to make certain that we access the resource well and all that pressure, as we frack those wells and as we drill those wells out, it looks good. And now we just have to get some performance results from these 2 Lower Spraberry wells on that pad. It was a Lower -- 2 Lower Spraberry and a Wolfcamp A well that we drilled from the 3-well pad. Once I get some real results from there, and then again, they're just now -- just this week, starting to flow back. So perhaps we'll have some excitement to talk about during our next call. But that's the last data point I wanted to get behind me before I really locked in moving that from our current 11 wells per section in our de-risked inventory to potentially 13. Everything still looks good though, we're on track.

The next question is from Neal Dingmann at SunTrust.

Joe, a question for you, or Gary, that I have is just on more on the infrastructure. You mentioned about the saltwater, could certainly bring down the LOE, I'm just wondering kind of how much can that be? And then timing-wise, how do you see this playing out?

Yes, thanks for asking that, Neal. I want to spend a little bit of time on infrastructure. We kind of talk about infrastructure as something that clearly needs to be done, but I want to talk about it and how accretive it is. It's incredibly valuable in 2 ways. One, it clearly helps us unlock the full potential of our assets. Once we get that in, we can truly ramp these wells the way we want to ramp them. We can -- when we do hit ourselves with a frack or get hit by a frack from an offset operator we can dewater that incredibly fast. We can be right back on track and there is just tremendous value in being able to unharnessed in the way you want to produce your wells early time and throughout the life of the well. And secondly, once we developed that infrastructure, both pipelines and owned and operated SWD wells, we've tremendous opportunity to actually use that capacity whenever we need it or provide that surplus capacity to third parties and actually turn that into revenue streams for us. So we're not just building it for us, we're building it as a value component associated with unleashing the full potential of the assets and really maximizing the full value component of that investment over the long term. So we don't hesitate that these are good things to do. And frankly, throughout Howard County, there has been a deficiency in that type of capacity. There's a lot of companies, it's amazing how many companies have come to us knocking on our door now that they see what we're doing, how we're doing, using technology, 3D seismic technology to identify these drilling locations to truly unleash the potential and maximize these investments to their fullest that want to be our partners. And we also want to partner with third party. We're very eager to partner with the right third parties that have access to other infrastructure so that we can then even grow faster. So that's our overall strategy. I think by the end of the third quarter, we'll have a well-developed, owned and operated infrastructure as well as something that is locked in and a longer-term vision of how third parties can help us to be successful in the future.

No, that makes sense. And then, just secondly, just a follow-up on that Slide 8. Infrastructure, is that ample then for, I guess, the Delaware and the Midland takeaway? But I guess, Gary, what I'm getting at is the rig -- you have gone to a third and then a fourth rig, you've got infrastructure now ample to do that currently?

Once again, I'm going to be absolutely honest with you. I'm still a little inefficient. I'm still not happy with where I'm at, but I'm close to being where I want to be. So we had some drilling obligations, we had to go drill in WildHorse, and so we had to go do that and we did it. And in conjunction with that, we're putting in the infrastructure necessary to be efficient. Same discussion I just had recently about the Garrett-Reed, right. The Garrett-Reed potential we're excited about, that I've never -- I've not really unleashed the full potential out of the area, because I'm drilling right next to it and hitting it again with another frack, and we've been hit by an offset frack with that area too. So once that's all done, again by the end of the third quarter for WildHorse and we're well-positioned early time for Spur, we'll be ready for -- clearly the 3 rigs will be much more efficient. The fourth rig will be ready, certainly in Spur, once it hits us in July, and we've already committed that rig. It's already ready to go. It is another brand-new new build drilling rig coming out of the yard and so we're excited about that new relationship we're building with this company.

The next question is from Chris Stevens at KeyBanc.

Just in regard to that Garrett-Reed, Wolfcamp A well and the Maverick area of central Howard, it looks like it's tracking above the million barrel type curve if they're 100 days online. Are the wells there on Page 9, the actual well performance of some of those wells -- is that data normalize to 7,500 feet or would they be outperforming even further if you normalize it to 7,500?

These are not normalized, Chris.

Okay. So I guess those wells would theoretically be looking a little bit better if normalized to 7,500 foot, okay. And just in regards to the oil mix during the first quarter, you guys beat on the mix and 2Q is also guided a little bit higher than what the full year guidance is. So is it more likely that there is upside to the oil guidance this year or is production potentially getting gas here in the second half?

All right. We're talking about a pretty tight range anywhere from 76% to 78% on average. Bringing on wells early time, we would certainly see a little bit more oil production than later in the life of the well on the margin. One of the big things is, Howard County and these oil rates that we're seeing basically north of 90%. If we continue to see that type of performance over time, there could be a little bit upside on our full year guidance that we have out there today.

Okay, and then just lastly on the Delaware, looks like the Corbets Wolfcamp A well is tracking pretty much in line with 1.5 million barrel oil curve that you guys provided last quarter after 90 days, but you're still talking about wanting to further refine your landing zone. So can you just maybe give a little bit more color on the thoughts -- on the performance of this well so far just in relation to your desire to change the landing zone and then just you can also remind us on that Saratoga Wolfcamp B well, was that drilled into the optimal sort of landing point that you guys are looking to kind of use going forward?

Yes, Chris, the Corbets well is a great well. And you're right, it's still tracking the oil type curve that we gave you, and still producing very strong rates today, 800 barrels a day of oil with good casing pressure still today after 4 months of production. So I mean it's a great well. And yes -- on Slide 13, we kind of indicate to you generally how we would change the way we would modify our landing zones for the Wolfcamp A and importantly, specifically to the question that you asked about the Wolfcamp B. The 2 areas on the left-hand side of that plot is really where the Corbets and the Saratoga were landed. And we would move the Wolfcamp B well just a little slightly higher. That's what we would do. And Wolfcamp B started flowing back a week ago or 5 days ago now and it's got real strong pressures, so we're excited about seeing how that comes out. But the key here, from what you're learning from the core, is really trying to figure out in our minds how to best figure out how to confine that fracture stimulation in and around some of these fracture swarms to better get access to the full capacity of the near wellbore area and capitalize on some of the natural fractures that we're seeing in the core that can potentially improve the overall performance of this development.

The next question is from Gabe Daoud at JPMorgan.

The Spur bolt-on, could you maybe just talk a little bit about that and other opportunities you see that continue to add positions there in Ward County. And then, just 2 housekeeping items related to that, was that during the quarter or was that in April? Just trying to see if that's picked up in the cash flow statement. And then, if you could just update us now what the working interest is at Spur currently?

Sure, Gabe. We're very excited as we said about the Delaware position that we picked up, especially in Ward County. A lot of it's going to be start with the rock obviously, as Gary has talked about during the course of his call. But one of the other elements in addition to having infrastructure in place in a better way than we typically see with these types of deals, is running room in and around that footprint that was truly contiguous and that we can bolt-on and leverage the organizational power putting out there an infrastructure we're investing in. So we got on this really quickly after we signed up our acquisition in December, we started off identifying opportunity sets and plus or minus 20,000 net acres that we identified in and around our position that had some probabilities [for success] we wanted to go knock on some doors. So this is the result of that in a few pieces that we've picked up over the last couple months. One of -- there's a couple of different packages in there. There's one large one that makes up a good majority of that acreage, but there's going to be more to come, that we're working on. We can't really talk about at length right now for obvious reasons, and we're also working on some interesting trades to again lengthen out laterals, which was another component of this transaction that added both new locations and lengthened laterals in a meaningful way. On the housekeeping side of things, we paid a deposit here recently, but the full purchase price will show up in early June and roll through the cash flow statement then. So it's not in the first quarter at this point. Working interest pro forma in this area is somewhere between, we expect 75% and 80% as drilling units continue to be [performed.]

Joe, that's so helpful. And then just a quick one from me, last one. Down in Ranger, when you guys get back to work there, if you could just remind me, which zone you'll be going with off the bat, and then if you plan to maybe touch the Wolfcamp C at some point this year or maybe even next year, just any thoughts around that?

Yes, we're still -- for the wells we just drilled and about to complete and then the other 2 wells that we have on our schedule for this year, they're all in the Lower Wolfcamp B in Reagan County, and we're very excited about the C potential. We don't have it on the schedule, but we see all the excitement around it, especially from the Parsley well. We're paying a lot of attention to that well and other things that are developing around it. So it's not on the schedule this year to test. We're looking for a place to do that.

The next question is from Derrick Whitfield at Stifel.

Gary, your excitement's certainly clear. Regarding your Wolfcamp C comment at Spur, could you further elaborate on what specifically looks better in the C than the B? Is it simply better rock quality with comparable oil saturation levels?

It's -- yes, it's all those things.

All right. And then, I guess, moving over to WildHorse. Certainly appreciate your conservatism. SM, as you guys know, announced some very strong wells in and around your Maverick area, could you comment on your expectations and productivity for as you move south from Sidewinder. And specifically, are you expecting Fairway to generally be better or worse than Maverick based on geology?

When we do the petrophysics, we think they're equivalent. We don't see much difference there. Again, when we bought -- just to be frankly honest about, and I think we described this to you when we bought Big Star, that seemed like so long ago, but it wasn't that long ago. We kind of thought that hey, some of this does degrade going to the south and to the east, and that's part of the reason we were happy with what we got. But from Maverick to Fairway, we thought these were equivalent. We didn't see any difference. We even risked some of the type curves just in case, but that was beyond the Fairway area. It wasn't really at Fairway that we did much risking. So what we can tell that we're very excited about and we'll be able to tell you about it in another quarter, because we'll have real results. And the wells that we've just recently fracked, they're -- it's called the colonial pad, that we're about ready to go in and drill out and put on production. They were fracked in the very same manner that we fracked Silver City wells. And so there's 2 Wolfcamp A wells there. And we'll have a good test -- a really good test and be able to define for you in some level of detail, I think, on the call what we feel about, how we feel about Fairway. But from everything we see right now, it's equivalent to Maverick.

The next question is from Jeff Grampp at Northland Capital Markets.

Just kind of want to get a sense of sensitivity on the rig cadence. Can you guys kind of talk a bit on the fifth rig in early '18. If oil prices are kind of hovering in this $50 or high $40s level, does that potentially change the -- either the timing or whether or not that fifth rig comes or even kind of that fourth rig staying longer term. Or just kind of wondering how you guys think about kind of rig sensitivity on the context of oil prices?

Certainly for this year we have a fourth rig coming, just in a couple of months here and the fifth rig we're doing a lot of planning scenarios in terms of where that goes. But our base case is oil hanging in the low $50s for the next 2 years. So if things pull back below $45, we might push out that fifth rig a little bit. Just because we have a goal, as we've talked about, when we add a rig we want to see a path to getting back to cash flow neutrality and having the cash inflow and outflow lines -- align in a pretty short period of time of 12 to 18 months. So we're never too far away from that if we need to pivot with any sort of bumps in the commodity price, but at $50, high $40s, I don't think we have really any tweaks to that fifth rig at this point.

Okay, perfect. And just on the service side of things, it kind of sounds, I guess, like things are more or less progressing in line with how you guys were kind of expecting and just kind of wanted to confirm if that's the case and maybe what you guys have seen more recently post quarter end here?

No, it's in line with what we've suggested all in. So I think things are -- again, things have kind of settled down a little bit, right. There was a flurry of some activity there. There's some realism that's kind of jumped into the marketplace right now because of this commodity price issues and then service industries catching their breath and getting efficient and then now even though we may have stepped back a little bit because of the growth in service capacity simply because of manpower, we'll now be able to improve upon that cycle time through experience and knowledge and working with other teams. So yes, everything is kind of in line with what we're doing and it's all normal blocking and tackling for us and every company out there right now in the service side.

This concludes today's question-and-answer session. I would like to turn the conference back over to Fred Callon for closing remarks.

Great. Thank you. Once again we appreciate everyone calling in today. And as always, if you have any questions, please don't hesitate to contact any of us. Again, thanks for calling in.

The conference has now concluded. A replay of this event will be available for 1 year on the company's website. Thank you for attending today's presentation. You may now disconnect.