Callon Petroleum Co (CPE) 2018 Q2 法說會逐字稿

Good morning, and welcome to the Callon Petroleum Second Quarter 2018 Earnings and Operating Results Conference Call. (Operator Instructions) Please note, this event is being recorded. A replay of this event will be available on the company's website for one year.

I would now like to turn the conference over to Mark Brewer, Director of Investor Relations. Sir, please go ahead.

Thank you, operator. Good morning, everyone, and thank you for taking the time to join us. With me this morning are Joe Gatto, our President and Chief Executive Officer; Gary Newberry, our Chief Operating Officer; and Jim Ulm, our Chief Financial Officer.

During our prepared remarks, we'll be referencing to earnings results presentation we posted yesterday afternoon to our website, so I encourage everyone to download the presentation, if you haven't already. You can find the slides on our Events and Presentation's page located within the Investors section of our website at www.callon.com.

Before we begin, I'd like to remind everyone to review our cautionary statements and important disclosures included on Slide 2 of today's presentation. We'll make some forward-looking statements during today's call that refer to estimates and plans. Actual results could differ materially due to the factors noted on these slides and in our periodic SEC filings.

We will 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 prepared remarks, we will open the call for Q&A. And with that, I'd like to turn the call over to Joe Gatto.

Thanks, Mark, and thanks to everyone for joining us this morning. Our second quarter's earnings release was out yesterday, along with the earnings slide deck that will be -- we will be referencing during today's call.

We have another highly productive quarter that set us up well heading into the back half of the year, as we integrate our pending acquisition into our Spur operating area. We expect activity levels to remain consistent throughout the second half of the year and drive strong growth and production and cash flow per debt-adjusted share as we begin focusing on planning for 2019.

Let's recap some highlights from the quarter on Slide 3. Production for the quarter was 29,000 BOE per day with 76% oil, a 30% increase from the second quarter of 2017 and 9% increase sequentially. As we stated on our first quarter call, we expect production growth to roughly 10% per quarter, and we are well on track for the target on a standalone production position with momentum building out of the second quarter.

Operating margins were nearly identical to previous period, despite a slight decrease in realized prices. Year-over-year, our operating margin increased by 37% due, in part, to improvements in LOE, which came in at $4.99 per BOE for the quarter, an 8% reduction from the first quarter.

In May, we announced a significant bolt-on acquisition of over 28,500 net surface acres in the Delaware basin, which will become a focal point of our capital program, as we now have 2 dedicated rigs in our Spur area and recently completed our first 2 multi-well pads, targeting 3 different flow units in Wolfcamp during the second quarter. We currently expect the acquisition to close by early September and plan to then quickly incorporate new activity on the position into a combined Spur operating plan.

With the vast majority of our capital program focused on pad development, we've been able to beat our own expectations for wells placed on production for the quarter, as we realized cycle time synergies. We progressed towards even larger pad designs to mitigate the impacts of offset fracking appearance and began to flow back on our recently completed first mega-pad in early July at the Monarch area, which Gary will discuss in more detail.

As another example of our continued efforts through optimized resource development, we have seen continued outperformance from our 10 well downspacing test in the WildHorse area, and we'll be using that data for our future development of the Wolfcamp A.

As a last key point, we recently executed an agreement for 15,000 barrels a day of firm transport capacity to move oil to the Gulf Coast for our growing oil production volumes. We anticipate this capacity to be available in late 2019 and will complement our existing firm sales agreements that are currently in place under longer-term agreements. We are evaluating similar opportunities to diversify our takeaway capacity and develop a portfolio of benchmark pricing points for the physical sales of our hydrocarbons over time.

Moving to Slide 4. We continue to deliver amongst the strongest operating margins of any producer with an operating margin of $44.17 per BOE in this past quarter. With our focus on driving a more efficient operation with increased scale and disciplined investments in infrastructure, cash operating cost as a percentage of unhedged revenue have dropped by more than 1/3 since late 2016. As you could see in the bottom chart, Callon has -- had the second-highest adjusted EBITDAX margin per BOE across a peer group of over 50 E&Ps in the first quarter of 2018, nearly $15 per BOE ahead of the group average.

We've also generated one of the highest 3-year production CAGRs of anyone in the E&P space. This is a powerful combination that will continue to underpin our ability to generate robust growth and keep debt-adjusted share metrics, as we advance to cash flow neutrality.

Moving to Slide 5. You can see that we had a productive second quarter and placed roughly 14 net wells on production compared to our previous estimate of 12. The quarter was back-end loaded with 8 of those 14 wells coming online in June, but that has contributed to a strong start to the second half of the year.

Capital spending continued to track expectations with operational capital for the quarter coming in at $166 million, even with 2 extra wells placed on production. We have spent just over 50% of our capital budget in the second quarter and are tracking towards our previous year expectations on projected capital deployment for our standalone plan. We are pleased to have managed the business in line with our original 6-month capital plans, especially considering several instances of a first half 2018 outspent within the peer group. While we expect our pace of wells placed on production in the second half to be above the first half due to improved cycle times and incorporating in progress and new activity from the acquired assets into our combined Delaware program, these expenditures should be more than offset by additional cash flow from the acquired production stream.

In addition, we expect that the early benefits from local sand usage and recycling we have seen to date to accelerate into the second half of the year.

Continue around to Slide 6. Our overall level of activity has risen with our rig count, but its composition has also evolved as we progress to larger pads now in development.

In the upper chart, you can see the daily production rates having continue to increase, but in the less linear fashion, as we placed more net lateral feet on production in larger discrete events with increased pad sizes. April and June represented our most significant months of the year, so far, and this activity has already driven July production to over 31,000 BOE per day.

The composition of our production profile has also evolved. As the bottom chart illustrates, the Delaware basin accounts for over 20% of Callon's production after only one year of dedicated rig activity. As we maintain our 2-rig Delaware program that has becoming more efficient and also fold in the production associated with our acquisition starting in the third quarter, we expect to see the Delaware to become an even more prominent portion of our overall production stream, driving cash flow growth.

On the topic of cash flow growth, you can see on Slide 7 a D&C spending profile that has roughly mirrored our EBITDA generation over the last 1.5 years. We are now positioned to transition to corporate level cash flow neutrality, as we had converted our significant acreage acquisitions in 2016 into a more mature and producing asset base. In addition, we are now winding down the larger portions of the infrastructure programs established to position those areas for capital efficient growth and, as a result, expect facilities capital as a percentage of total D&C to normalize moving forward.

On the bottom left quadrant, we have provided a picture of our estimated field level cash flows by basin, assuming strict benchmark pricing and differentials as well as a PDP contribution from the Delaware asset addition. Our Midland Basin areas are squalling self-funding mode with the ability to generate free cash flow in the future after our measured growth initiatives over the last 2 years. The Delaware assets are following a similar path to free cash flow generation, a path that has clearly benefited by the impact of our recent acquisition.

With that, I will turn the call over to our COO, Gary Newberry.

Thanks, Joe. Good morning to everyone. I am pleased with the team's relentless focus on operational excellence across our business and believe we are well positioned to drive further improvements in both well performance and cost management going forward.

We have had a very predictive second quarter and have continued to build on the momentum in July with the completion of our first mega-pad at Monarch. The wells for this project were simultaneously drilled as 3 well pads, utilizing 2 drilling rigs and placed on production in early July. Early-time production has reached an average peak rate of 185 barrels oil equivalent per day per 1,000 lateral feet. The wells were all single-section laterals in our CaBo area of Monarch and came in at just over 4,200 lateral feet on average.

As evident in the chart on the right, the wells are performing in line with 2 separate offset 3-well pads in the operated section nearby. Our second 6-well mega-pad in the area is expected to be placed on production during the fourth quarter. And we will begin drilling a third 6-well mega-pad around the same time.

As Joe mentioned, we have essentially completed the integration of our previously acquired assets and are now moving to more capital-efficient development. Furthermore, as shown on the bottom of Slide 8, we now have 100 days of production from our Wolfcamp A and B pair test at Monarch, and the results are very compelling. The single-section laterals have cumulative oil production through the first 100 days of 46,000 barrels -- oil barrels on average. Mega-pad development of these 2 intervals will provide a long-term opportunity to grow production and add value in this area with highly repeatable low-cost wells. It's one of the many opportunities that we will be discussing as we continue to work through our 2019 planning cycle this fall.

Moving to Slide 9. I will review very encouraging results in our WildHorse area. We have continued to optimize completion designs, resulting in significant improvement in early-time oil production and better than 30% outperformance above the respected type curves. Our '10-well downspacing test, which we've provided initial results during our last call, has continued to perform favorably against offset 2-well pads in the Fairway area, despite having some recent interference from offset frac activity. The optimized completions include reduced sand and fluid loading, resulting in measurable cost savings of 3% to 5% per well.

Looking at the map in the bottom left, we have a number of pads planned for development during the second half of the year, including returning to the Sidewinder area during the fourth quarter. Our focus on efficient development should result in an average completed lateral length of 8,500 feet for these wells.

On Slide 10, let's move on to the Delaware basin, which clearly has become a focal point for improved operational efficiency with the infrastructure build-out, the addition of our fifth rig and the recently announced acquisition. During the past few months, we've placed on production a number of new wells, including the upper and lower Wolfcamp A wells at our Rendezvous pad, the Moran well and the Rag Run wells, which included a lower Wolfcamp A and our first test of the Wolfcamp C. The results from these new wells are significantly outperforming our earlier vintage wells as well as the normalized 7,500-foot type curve.

The Rag Run 134 South #25CH, our first Wolfcamp C well, has performed quite well, matching the best available offset well in the area and producing a cumulative 23,000 barrels oil equivalent, of which 80% was oil through the first 43 days from a 4,800 feet of completed lateral.

Our water disposal and recycling facilities work have made significant progress, and we were able to utilize recycled volumes for more than 40% of the Rag Run Wolfcamp C frac. We are now producing from 5 different flow units across our position and are gearing up to drill our first 2nd Bone Spring shale well later this year. As we plan for 2019, our focus for this area will include more multi-well pads similar to the Rendezvous pad. We want to deliver capital-efficient development of a number of different zones, as we continue to increase activity on this growing asset.

To summarize, our development across all of our operating areas continues to move towards more efficient multi-well pad development. Our pad sizes and application of technology are evolving and, coupled with our extensive infrastructure planning, we are reaping benefits that result in more productive capital deployment and improved cost structure.

The forthcoming advantages of our water disposal agreement with Goodnight Midstream, combined with our growing recycling efforts, will be instrumental in facilitating robust growth of our Delaware asset.

Our ability to integrate new crews for both drilling and completion operations has been exemplary and is evidenced by our ability to nearly double the amount of net lateral feet placed on production quarter-over-quarter.

I am very excited about the pending addition of the assets from our recent acquisition, and we'll get to work on integrating those assets promptly into our 2019 capital development program.

With that, I will turn the call over to Jim Ulm, our CFO.

Thank you, Gary. I'm very pleased to share that we recently executed a firm transportation agreement for dedicated capacity on a new pipeline system that will connect with the regional gathering system, which currently transports oil volumes under long-term agreements from our properties in Howard, Ward, Reagan and Upton counties. Subject to completion of the new pipeline system, which will have delivery points in several locations along the Gulf Coast, we will have a commitment of 15,000 barrels per day for a multi-year term. We expect this pipeline to be in service by the latter portion of 2019. We have secured multi-year firm sales agreements, covering all 15,000 barrels with established buyers in the Gulf Coast region. These sales agreements are not linked to export development and provide exposure through a combination of international and Gulf Coast pricing. This next step in our marketing plans is reflective of our desire to proactively seek diversification of both pricing and buyers to mitigate risk, as we continue to grow our production volumes measurably over time. This also provides us the opportunity to hedge our future production at highly liquid benchmarks, protecting our future cash flow.

On Slide 12, you can see the effect of our recent financings that were executed in conjunction with our acquisition announcement. We currently have 0 drawn on our revolver with significant cash on the balance sheet in anticipation of closing our transaction. We have layered out debt instruments with the addition of $400 million in senior notes that mature in 2026. And we will be renewing our borrowing base shortly to reflect the expected increasing capacity from the addition of production and properties.

Our liquidity and credit metrics continue to be strong, and we expect to see the beneficial effect of additional cash flow from the pending acquisition in both enhanced liquidity and capital flexibility.

As Joe showed earlier, we see an improved path to free cash flow generation with the addition of these assets and production. And we'll continue to focus on creating improved cash flow for debt-adjusted share growth.

As the second quarter progressed, we continue to monitor the commodity outlook and made the decision to significantly improve our hedge positions. We have added additional protection for both the underlying commodities and the applicable basis differentials. This is something we have done consistently. And we have been patient and waiting to execute when pricing has become advantageous.

For NYMEX-related hedges, we have almost 20,000 barrels per day covered for the second half of 2018 and 14,500 barrels per day on average for the full year 2019. We have significantly raised our Midland-Cushing hedge position, increasing our basis swaps to 12,000 barrels per day for the remainder of 2018 and all of 2019. The swaps are priced to between $3.81 and $5.76, significantly better than forward curves would indicate. We continue to evaluate additional options for improved risk mitigation and price improvement, and we will actively utilize instruments, we believe, will further protect our cash flow.

With that, I would like to ask the operator to please open the line for questions.

(Operator Instructions) And our first question comes from Neal Dingmann with SunTrust.

Joe, my question are for you and Gary around Slide 3. When you show you're -- you definitely have now, after the acquisition, a large amount of acreage. Can you talk about cadence? Specifically if you continue to run the 5 rigs, will you keep them in those -- the one in WildHorse and then the 2 between Monarch and Spur? Or do you plan to go to Ranger as well? If you could maybe just talk about cadence a bit.

Neal, this is Joe. I'll start out and let Gary jump in here. But certainly, for the remainder of the year, we'll be focused on Spur, Monarch and WildHorse. We do have some incremental activity going on in Ranger, as we've seen some good results down there, so it still is part of our program. But as we move forward, certainly, the Delaware basin is going to attract its share of capital as well as WildHorse with incremental activity in Monarch. Ranger, as we've talked about, we've gotten back down there this year with some really nice results after going through some more new-generation completion designs. And we're digesting that data, and we'll figure out going forward how much capital it will attract. But for the near term, we've seen majority of the capital in the Delaware and Howard County.

Yes, Neal. I was just going to say that, like we've said before, we've got 5 rigs working, 3 rigs in the Midland Basin. Really, it's 2 in 1, 2 WildHorse, 1 Monarch Ranger. But it's -- then 2 rigs in the Delaware. And right now, I don't see any reason to change that cadence. We'll be doing a lot of planning for 2019, thinking through what the best option is to add value. But we've got an incredibly robust portfolio, and I'm glad to think about going into the next month or so on figuring out what -- how we can bring that value forward.

Good at it. And then, Joe, just one follow-up looking into this nice firm transport, and I like that slide on 11 that Gary will add to that for -- and then Jim mentioned about just the basis hedging. Now that you have all that, again, looking at Midland pricing today around $52, can you just discuss -- now that you have that in place, is it less likely that you would see durability as far as having to let a rig go? Or would you add a rig? Or maybe, could you talk about how that plan looks now that you have a lot of these things in place?

Neal, while we're really excited to have this agreement, this is isn't necessarily a magic fix to anything or a huge needle mover. And we've been managing financial basis risk over last few years in a sort of systemic type of basis. This is a nice complement. And I think the key takeaway from this is over time, with increased scale and scope, we're able to entertain more of these type of arrangements that, ultimately, will get us to pricing points that aren't all based in the Midland Basin. We can manage on our exposure financially, but we'd like to manage it more physically as we move forward, so this is a first step. But this doesn't necessarily change our view that we have a robust asset base. We're in a good position to -- pace we're on to enter '19 and continue to point towards cash flow neutrality.

Our next question comes from Asit Sen with Bank of America Merrill Lynch.

Gary, just going to Slide 8 on Monarch and the last bullet there, you talked about low-cost, short-cycle time option for additional projects. Could you talk or elaborate on the cost and the cycle time comments and also how you're thinking about the lateral length here?

Yes. Again, as you can -- on Slide 8 in Monarch, as you can see, Asit, from a -- just the description on the map, you can see a large part of CaBo and even the Pecan Acres there, for us, it's really a single lateral length -- single-section lateral length. So it's 4,200 to 5,000 feet depending on whether we get an off-lease location or an on-lease location. For the most part, Carpe Diem, is the area that's distinguishes itself a little bit differently and the fact that you can have 9,000-foot laterals going North and South there. And we're partnered with another company on the West side of Carpe Diem to continue to drill 10,000-foot laterals. This has been our bread and butter. It's been working really, really well. It did work really well in the low price points in 2015, '16, and it's working even better today at the improved pricing structures that we had, even at the higher cost points. But these returns are some of the best returns that we have in our portfolio, so we're happy to have this type of activity, especially with the A/B results that we just announced, that even adds to this great opportunities set.

Excellent. And then on Slide 10, the Wolfcamp C, while oil cut looks pretty good, just wondering if you have any updated thoughts there.

Yes. The Wolfcamp C, again, that's a -- that was a 5,000 foot lateral, so that is a very good result for a 5,000 foot lateral. That's about 600 to 700 MBoe well. And very pleased with that overall performance. It's operating just pretty much as we would have expected given some of the better offset results that we have. We clearly think there's still more to improve in that area. And cost for drilling that type of a well is anywhere from around -- for a 5,000 foot lateral, it's around $10 million.

Our next question comes from Gabe Daoud with JPMorgan.

Maybe -- yes, I guess, just starting at Monarch, the mega-pad. Can you maybe just talk a little bit more about what you're seeing there and what you've learned, thus far, and then maybe anything you'd do differently on the next set of mega-pad?

Yes. Again, we're -- again, the general focus on mega pad development is all around efficiency, right? It's fewer rig moves, very improved cycle times on fracs. We have significant opportunity there because of the infrastructure build-out we did in Monarch in 2014, 2015 that we can handle significant water volume offtakes given that we have our own SWD system as well as tied into a highly reliable third-party SWD system. So we're drilling mega-pads because the cost advantages of doing all of that in a very much shorter cycle. Now of course, the other advantage is related to parent-child relationships. It comes down to the bigger the cube, the less likely you're going to have to come back and have an impact on that offset production in the future. And less likely, you're going to have any impairment, whatsoever, with that very next well when it comes to any type of depletion affects for completions. So this is the way we've been wanting to get to in all of our assets now that we've got all the assets integrated. We've got the infrastructure in place. We'll be able to move this type of development even more so throughout, as we continue to execute it here at Monarch, in WildHorse as well as in Spur. And we've essentially been doing similar-type things in WildHorse even already, as we put a couple of rigs side by side, drilling on a couple of well pads and tracking those simultaneously as well. We just haven't really focused too much on that because we wanted to highlight the results of this 6-well pad to you all. But our focus is efficiency and value.

That's helpful. And then so I understand you'll true-up '18 guidance when this merge deal closes. But could you maybe just talk a little about the infrastructure needs on the similar acreage? And I guess, what exactly needs to be build out before you perhaps accelerate a bit on the acreage in 2019?

Yes. The -- as we mentioned in the rollout of that asset, it came with significant infrastructure in place already. It already ties somewhat into our existing infrastructure. We'll have to upsize some lines. We're already talking to Goodnight Midstream about the connection to the West. We'll -- before we get too [optic] on that asset, we'll want to make certain that we can be efficient with it. We've learned a tremendous amount on our legacy asset in the Delaware basin, as we've gone through with these single-pad wells -- single-well pads and looking at that whole development potential across the asset position. So yes, we'll have to add a little bit of infrastructure, but it came with infrastructure, so it's not likely integrating a brand-new asset, like we've done in the past. Very pleased to have one that I don't have to jump right on right away. But some incremental enhancements are necessary.

Our next question comes from Derrick Whitfield with Stifel.

Joe, I want to try Neal's question with a different approach. With the understanding that you're better positioned to a better protected firm basis exposure on some of your peers based on the FT, based on the basis hedges, how would you change your operations, if at all, if you were faced 2 quarters of Midland differentials an excess of $20 a barrel?

That's good question, Derrick, and I'd like to frame that a little bit differently, but also addressing your question. I mean, we're focused on differentials. But really, for us, it's net realized price, right, whether it's TI or Midland differential comes down to the net realized price for oil and your product. That question also goes to cost structure, right? We can't look at realized prices in a vacuum. So as you highlighted, yes, we're in a very good position from protecting basis differentials, protecting benchmark WTI that does what we want it to, right? Hedging gets you through periods of transition and commodity prices. And if they stay at a sustained level, we should see cost structures go down as well and provide that bridge. But let's just say there was a more extended period of time. Let's get to the heart of the matter in terms of where price realizations are right now. We are very firm in our focus on returns-based drilling. We are fortunate to have a portfolio of very strong returns across our asset base, across all 4 areas that are now even in a better position that we put infrastructure in place and benefiting from that. So from a full cycle base, these are not discrete half-cycle returns, we're in a great position. Now we are also cognizant of -- to get those returns. There is a upfront capital spend that goes with it. And we're going to be balancing our outspend, right? That's a big goal for us, is to keep our eye on the target for 2019, getting the cash flow neutrality. We're squarely on track for that, even despite some headwinds that we see on the commodity price. But we will keep an eye on that metric and balance that with chasing returns as well. One of the metrics that we put in place this year, as a company, that we judge ourselves on is cash flow per debt-adjusted share. So again, I think that highlights that we're going to be very mindful of, while we have great returns, there's also another part of the equation that we're going to make sure we adhere to on the outspend. But overall, we feel good about the path we're on and the level of activity that we have.

Very fair response. And perhaps for Gary, regarding your Spur area, would it fair to say that the Wolfcamp C is more overpressured than the Wolfcamp A and has comparable oil composition levels? And if so, is there any reason to believe this interval can't be a meaningful contributor to your portfolio as you look out a few years?

It is fair to say that there's a lot of oil in place in the Wolfcamp C. And it is even a higher-pressure regime than the Wolfcamp A. And it is -- as exhibited on our early-time performance, it is already contributing value today. I think we can significantly enhance that value through additional technology application, studying the area and learning more about what works and what doesn't and then making certain that a big part of operating in has always been efficient operations. That's what's going to drive the value of these wells, like a Wolfcamp B or a Wolfcamp C that does come with, honestly, additional water loading on production. So that's our focus. And there's no doubt that, that will be a significant value contributor in the future.

And Gary, just one quick follow-up with that. Knowing what you know today, is there anything you would have done differently with the well design for that 3-well?

We have an ongoing conversation right now with our technology team. And before I give them the answer, I want them to challenge me on what they think better. So I would just assume to defer that question till next call, if you don't mind.

Our next question comes from Brad Heffern with RBC.

Now that you guys have this first mega-pad under your belt, I was wondering if you could talk a little bit about how you think about optimal pad size and the trade-off between longer-time lags and the working capital impact versus infrastructure build-out and so on. Is this mega design that you have now probably where it's going to stay? Or do you think that there's a potential to go even bigger on pads?

I generally like the 3 wells pad per rigs with 2 rigs sitting side by side or potentially, 3 rigs sitting side by side depending on, as you pointed out, the capacity for water offtake, the opportunity to growth rate, the opportunity to minimize offset production, all of the various attributes of going to larger and larger pad developments and the efficiencies that come with it. So generally, I would say, because the cycle times in the Midland Basin, you're looking at 3 well pads with simultaneous operations side by side. And then Delaware basin, for now, because the cycle times is a little longer, even though we're working expeditiously to pull that down. I would say it's 2 well pads with rigs sitting side by side, as we go forward, if that gives you some guidance as to what we're thinking today.

Yes. That's great. And then I guess, I'll try another question on basis. Do you -- are you happy with sort of the 30% to 40% coverage that you have in 2019? Obviously, it would be paying full to hedge more at these wide spreads. But as you've said, you guys good economics, even with Midland prices in the low 50s. So is there any desire to take some more risk off the table and hedge more basis?

This is Jim. What I would say is, I think, we're going to continue the portfolio approach that we've described. And as Joe mentioned, we're really thinking about a total realized price versus just a basic differential in isolation, as we've said on the slide. So I do think there will be opportunities to do additional hedging of WTI. We're very closely watching Mid-Cush. We saw an opportunity later in the week last week to look at a full year 2019 at below $6.50 at some level, that would be very interesting to us. So I think you're going to see us do this in conjunction with the 2019 plan with getting the pending acquisition closed. And we'll continue to be very methodical. And we'll also be very thoughtful as other opportunities related to physical sales have greater clarity, as well. So I think it's going to be very dependent on market conditions and doing the right kind of deal relative to our views on 2019.

Our next question comes from Irene Haas with Imperial Capital.

I saw that this quarter's lease operating cost of $4.99 were just very impressive. And considering that your infrastructure investment seems to be leveling out and the new acquisition doesn't need a whole lot of money, should we carry this sort of cost structure into the fourth quarter?

Thanks for that compliment, Irene. I appreciate it. The team deserves a well-deserved pat on the back for that. And thanks again. So yes, we continue to see opportunity. We'll continue to drive cost out of the system where we can. But importantly, we'll also continue to grow rate where we can. That's a dual course, so everyone contributes to that metric in some form or fashion. But very pleased with that. I -- I've kind of been hedging on lowering that guidance only because I wanted to make certain that I was -- got through the third quarter with all of my infrastructure build-out and I didn't have significant water disposal capacity exposure at Spur. And that's essentially done -- almost done, not quite tied in to Goodnight Midstream yet, but that will be in September. And then I'll feel very comfortable about our exposure to increased cost.

Yes, Irene, we'll be out with the update around that guidance as we get the acquisition closed prior to providing an update. But obviously, we're very pleased with the progress we've made. And the new -- the acquired asset base had -- we think of a similar LOE type of profile, so we'll be able to update our thoughts, as Gary said, once we get this closed and get the water infrastructure all lined out. And the way we think, it's coming together in the next month or 2.

Okay. And I have one follow-up question on the firm transportation. Can we have a little more color in terms of how many years? You said multi-years. And how soon would you be able to tap into the international markets? That's all.

Thanks. We are somewhat constrained in what we can communicate by virtue of confidentiality provisions. But I think we've said it's a multi-year agreement. We've mentioned that we will have both the firm transportation as well the sales agreements that will give us exposure to both the Gulf Coast market and international pricing.

Our next question comes from Sameer Panjwani with Tudor, Pickering and Holt.

I know you said you're running 5 rigs, but the data services are showing 6. Not sure if that's correct, but can you provide some color on what's going on there?

Yes. Sameer, thanks for asking that. That is something we need to clarify. We actually picked up a spot rig in Ranger a couple of months ago only to drill 3 wells, essentially 3 specific wells. The reason we've picked up the rig wasn't really related to trying to increase pace. It was related to some of our partner concerns around their lease obligations. And so within the schedule that we had planned for, those obligations weren't going to be met, and they asked us to pick up a rig to accelerate their development plans because they had some exposure. And so we went ahead and did that, and we've finished the development now in Ranger. We're going to drill one more well with them and then we're going to release that rig.

Okay. That's really helpful. And I guess, just following up on that couple of questions. So first, with more activity at Ranger, I guess, how should we think about the oil cut kind of going forward? It sounds like it should be kind of a little bit more depressed as the activity flows through. And then secondly, it's kind of in line with what we've been hearing from other operators in terms of a higher non-op activity. You guys also talked about faster cycle times. But unlike your peers, you didn't raise your CapEx budget. So I understand there's an update coming soon around guidance, but what gives you comfort around keeping the capital budget unchanged for now?

Yes. So there's few points to that question. We'll try to address some of that. In terms of Ranger, this was fairly low working interest relative to the rest of our properties in terms of the wells. On the margin, it is going to be a little bit more gas price than the rest of our properties. So we saw that impact a little bit in the second quarter. But as we -- our drilling in Spur and WildHorse and Monarch, we see that oil picking back up as we did in July up to around 78%. In terms of our CapEx spend, we anticipate a little bit more non-op activity from our visibility going into the back in the year. But again, we had a really good first half in line. And with our expectations and -- we'll provide an update, like we said, in a few weeks because there's not only non-op activity on our properties, but with -- the acquired properties have some non-op activity. So we got to -- we want to come out with one update for you. But I think that the one thing to highlight is in the first half, we're pretty much on our mark. We do to try to account for non-op activity in our budgeting process, and we captured most of that. And we'll just have to -- we'll continue to reassess that in the back half of the year because we are seeing a little bit more as others are as well.

Our next question comes from Dan McSpirit with BMO Capital Market.

To clarify, does the wording commitment of 15,000 barrels a day when describing the recent takeaway solution mean minimum volume commitment? Are you finding the need to take on MVCs when considering other agreement?

So, this is a classic firm transportation agreement, so there's a tariff that you pay, whether you use it or not. So it's not necessarily an MVC. It's just a classic transportation agreement. Now on the back end of that, we do have sales agreement, but they're not subject to MVCs.

Very good. And what about the terms on what you're considering when diversifying -- further diversifying your portfolio of takeaway solutions. How are you finding those terms -- the term itself in years or MVCs?

Well, I think one of the things we've talked about is we've been focusing initially on land in the Gulf Coast. There are other alternatives out there, and we will evaluate those, obviously. As we look, there are high-level benefits of diversification. We've also looked at it. We've mentioned on kind of for a realized price and that includes the cost associated with getting to the Gulf Coast. And clearly, we thought that those levels were acceptable. And we will continue to evaluate those on a case-by-case basis going forward.

Very good. Appreciate the color here. And then just as a follow-up to that maybe. By how much is the non-op activity expected to increase from budget? And who are the operators involved that you can -- if you can say?

The operators are is going to be a mix of publics and privates at this point. I can't point to any one group and, certainly, not to specific parties at this point. But again, rather than talk about peace meal, Dan, going to -- a few weeks from now that we can update that. Again, I think it's largely in line with our original expectations on non-op. But given the areas wherein, there's some good wells to be drilled. So people are, obviously, getting after them a little bit more, we think, in the second half.

Our next question comes from Jeff Grampp with Northland Capital Markets.

About WildHorse, I'm curious on this Barclays and players pad. With the outperformance there, would you guys attribute the majority or all of that to the frac load optimization that you guys highlighted? And can you clarify, are those the first wells where you guys kind of implemented that optimization process?

It's a combination of things, but a lot of it is associated with, actually, pulling back on sand and pulling back on a field loading, so it's actually a benefit on both sides of the ledger. The cost came down. Production went up. And it's also a significant benefit to the way we're actually drilling and completing the wells. We're actually running larger casing streams in these wells now to allow the operating team to run larger pumps as well to help with managing how we draw down those wells, more efficient way of operating the well from start to finish. So we spent more money to drill it, but we're actually enjoying the benefits to get it. But then we saved more than what we spent on the completion design. So it was a win-win all around. And this is the type of completion that we'll continue to move forward within in WildHorse going forward. So always looking to tweak things to get just a little bit better. This team is never satisfied with just sitting still.

Great. I appreciate that, Gary. And then you guys referenced in the deck increasing usage of local sand in the back half of the year. Can you guys give us a sense of how big of a component in the program it is in the back half of the year and what your level of access is to local sand going forward?

Yes, yes. Again, we were expecting some of the inefficiency that actually some people saw with the startup of the local mine. So we didn't really plan too much local sand in the first half. Our contracts with Schlumberger, who's doing all of our pumping services and providing the majority of our sand today, we put in that contract that we would have full access to local sand in the third quarter, and so that's where we are. And we now have full access to local sand to utilize in the Midland Basin. We're using it for 100 mesh pad in the Delaware basin, but we're still committed to using Wisconsin White, primarily in the Delaware basin until we actually see a little bit longer-term performance from offset operators who have been consistently using local sand in the basin. But it won't take as long to figure that out. So savings in the Midland Basin is around $300,000 a well, so we're happy with that.

The next question comes from Ron Mills with Johnson Rice.

Just really one quick one for me. As we think about the mega-pad development and the A and B co-development test in the Monarch area, how do you think about development of these mega-pads? And are you going to -- or will you start to hold in co-development in the A and B at the same is doing mega-pads? Or based on the early data, how do you think that development plays out?

There's a lot that goes into that answer, Ron, but it's a good -- very question because there's tremendous opportunity in Monarch, right, as what we've shown you already on Lower Spraberry, what we've now gotten excited about on the A/B. We know there's significant Middle Spraberry development. It's got a great opportunity in this area. There's more than just this. So we're pleased with this entire section. But we still think in Monarch that there's discrete reservoirs between the Lower Spraberry and the A/B pair, so that gives us a lot more flexibility around mega-pad development and the opportunity to go forward with efficient development, while focusing on those 2 discrete reservoirs. But because of the infrastructure build-out that we've already done for the Lower Spraberry, we can quickly integrate the A/Bs in a larger-style development in a more efficient development going forward without hardly any additional infrastructural spend. So I would still think of them as separate reservoirs, but codeveloped -- but developed in a more efficient, larger-pad development in order to minimize impacts to parent-child relationship, as we come back in the future.

And how could that impact the cycle times, the capital efficiencies in terms of -- does that then potentially move the 3 well pads to 4 to 6 well pads as you do multi-zone development?

Yes. That's an interesting turn. I've actually thought about that with the team. It could get us to 4 well pads to get to this to 8 well co-development, things like that. But we're not quite ready to jump to that yet. The cycle times are very good in the Midland Basin. I'm not sure I can shorten those any more. I really like the returns I get with this cycle time that I'm on, I've gotten very comfortable with it. But we'll challenge ourselves to get bigger, so that we don't have to come back. It might be that because we're getting so much flexibility after this year, we'll essentially be held by production across our asset base. Only very few obligation wells in the future that can only -- that could probably be handled by a single rig. So it could be that we have more than just 2 rigs working on any given section. But the infrastructure was the most important thing to be able to do this in an efficient way, and that's in place.

Our next question comes from Noel Parks with Coker & Palmer Institutional.

I wanted to go back to the Wolfcamp C for a minute. And I was wondering, is there a sort of distinct upper and lower number to the Wolf C on your acreage?

Well, we're focused really on the upper section of the Wolfcamp C. We're looking at the various opportunities for changing the landing zone to initiate the frac a little bit better and as well as to get access to the more resource. But we're really looking at a single level in the upper Wolfcamp C at the present. Hopefully, that will emerge as we go forward, but that's what we see today.

And that was exactly where I was headed next. Was just wondering about the -- how much work you did as far as establishing the right landing for well. So is that something that's going to be very important to the development going forward? Or are you seeing enough consistency that there might be some more room there longer term?

So we think the landing point in any zone is very important and as just as important in the Wolfcamp C. We'll have a lot of technical work. We're involved with the various industry consortium studies going on right now that are run and have a lot of data sharing around various development opportunities. We're going to learn an awful lot to being a part of that and being technology focused on this asset. I think us and a few others will be driving the overall improved performance that should be expected in the zone that has so much oil and so much opportunity.

Terrific. And on the acquired properties, you said you've made a lot of progress on integrating them. And I was just curious on the topic of data, data sharing. Basically, are you acquiring -- the quality of data you're acquiring roughly comparable to what you have on your existing acreage? Or do you think you have to put some more effort on that as you get to know the area better?

In terms of acquiring data, obviously, there's a pretty good inventory of well data that comes and we'll be able to corroborate what we've drilled in the area. But apart from that, we do have extensive size and a coverage over the vast majority of both our properties and the acquired properties that we outlined in the acquisition presentation back in May, to give you a sense. So we already had control that data in house here, so it's not like we're acquiring that. It is useful to get more well data and those specifics on completion designs, et cetera, but from a subsurface or well down the road on that from a regional perspective on our own.

Yes. I'm sorry, we just have to -- just to give a shout-out to people on the team. We have some in-house folks who paid a lot of attention to industry activity across the basin over time and that's what gets us excited about these other opportunities when they come available because we've already figured a lot of it out. And all of the new assets that we've gotten have -- they have performed at or even significantly better than our expectations simply because after we get them, we work them. And we work them through our own technology team as well as the way we partner and exchange in trade data with all of the industry partners in the area. We are a very open shop when it comes to getting to the best result as soon as we possibly can.

Our next question comes from Gail Nicholson with KLR Group.

You guys talked about supply chain initiatives in the back half of '18. Can you just provide some clarity and what exactly you're trying to do there and the potential cost savings?

Yes. Based on the results, you can tell we've done a fairly good job sourcing materials and services in the past. But as we've grown, we've decided that it's time to clearly develop an organization focused on every aspect of our -- every line item. We'll take some of that burden off of our execution teams and let them focus on engineering and effective execution and design of the work. And we'll let that team support the ongoing sourcing and leveraging the total spend now across our entire area, hopefully, to fewer vendors and actually leverage better pricing going forward just like any supply chain of any organization should do.

Great. And then looking on the Delaware (inaudible) and the acquisition that's done, you guys have a couple of little insert pieces in Delaware, specifically on Pecos County that you picked up with Ameredev that you couldn't assign much value to. Have you guys thought on any portfolio optimization on a go-forward basis post the bolt-on closing?

Yes. We certainly do think about that, whether it's -- what you referenced. Or more broadly, this year, we did sell a section, an extra county that we had called Kayleigh. We evaluated where does the property sit in the queue of development and the NAV proposition if there's a way to bring that value forward on areas that we're not going to be focused on and, importantly, can't get efficient on in terms of level of activity and momentum, then we certainly will entertain that.

Great. And just going back into the Monarch, the A/B pair. What is -- I mean, what are really good oil schemes that are both on those zones? Was that surprising to you that, the outperformance? And do you think that's indicative of doing them together as a pair? Or what do you think is driving that?

No, it wasn't surprising at all. We expect that, actually. We knew that inventory was there. We've known it for some time. We've worked hand-in-hand with other operators, RSP specifically now. Their assets are loaded into (inaudible). They did a lot of work around proving up the A/B. We knew it was there. We now prove it ourselves, as with the work that we did. So we always just had the Lower Spraberry just little bit better and that's why we're focused on it to this point. And we always looked that as an opportunity we can come back to. But now that we're in mega-pad development, we've got the infrastructure in place. That's something that's very compelling to us, as we think about our long-term development plans going forward.

Our next question comes from Kevin MacCurdy with Heikkinen Energy Advisors.

Just one question for me. Can you remind us how many gross on that locations you have in Spur after the acquisition? And does that number include the Wolfcamp C?

See I don't know if -- I'll try to pull that out, but the number that we carry in our delineated inventory does not include the C just yet. And while we came out with, I think, roughly 169 net locations with the acquisition and the A and the B with the acquisition, but what its -- we're pulling up a chart, Gary, if you have in front of you. We haven't broken out that way. Kevin, remind me to get back to you on that. I'm not sure if we have that in front of us.

Yes, without the integration, I couldn't tell you the number. Yes

Would you then try to guess how many -- okay, that's fine. Would you venture to guess how many Wolfcamp C locations you could potentially have on that acreage?

Yes. I would say there's going be close to -- it's not -- it wouldn't surprise me if it's close to 80 to 100. You asked me to guess, I can give you a guess.

And this concludes our question-and-answer session. I'd like to turn the conference back over to Joe Gatto for any closing remarks.

Thank you, And thanks, everyone, for joining us to talk about second quarter, one that we're certainly very pleased with. It's all production growth and building a lot of momentum into the back of the year. Certainly, we're looking forward to integrating the pending acquisition, and we look forward to giving you an update in the coming weeks on that. Thanks, again.

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