Callon Petroleum Co (CPE) 2018 Q1 法說會逐字稿

Good morning, and welcome to the Callon Petroleum First 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 1 year. I would now like to turn the conference over to Mark Brewer, Director of Investor Relations. Please go ahead.

Thank you, operator. Good morning, and thank you, everyone, for joining our conference call. With me this morning are Joe Gatto, President and Chief Executive Officer; Gary Newberry; Chief Operating Officer; and Jim Ulm, Chief Financial Officer. During our prepared remarks, we'll be referencing the earnings results presentation we posted yesterday afternoon to our website. So I encourage everyone to download the presentation if you haven't already. You can find the slides on our Events and Presentations page located within the Investors section of our website at www.callon.com.

Before we begin, I'd like to remind everybody 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 this slide and in our periodic SEC filings.

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

With that, I'd like to turn the call over to Joe Gatto.

Thanks, Mark, and thanks, everyone, for joining us this morning. Our first quarter earnings release is out yesterday along with earnings slide deck that we'll be referencing during today's call.

We had an active first quarter with the addition of a fifth rig in mid-February ahead of the 2 dedicated completion crews, setting the stage for a steady level of activity through 2018. As we all know, the Permian had a rough start to the year with extremely cold conditions in January. Our operations team did an excellent job of bringing wells back online and importantly, keeping us aligned with our operational plans and expectations for wells placed on production. In fact, we did better than planned with realized efficiencies of both the drilling and completion side that we will talk about in more detail.

With that, I'd like to focus on Slide 3 of the deck. Production for the quarter was 26,600 BOE per day. It was slightly ahead of the last quarter in which we posted a sequential increase of almost 20%. The production was right in line with our expectations during a quarter where we built a small backlog for operational flexibility and also had a lower than our normal average working interest in gross -- wells placed online. Almost all the wells placed on production this quarter were in the Ranger and Monarch areas, with Reagan wells placed on production in WildHorse and Spur early in the second quarter. Production for the second quarter has begun to ramp as the 5-rig program hits its stride with average April volumes in excess of 28,000 BOE per day.

On the financial front, we generated first quarter EBITDA of approximately $92 million driven by sustained high oil mix combined with strong price realizations and a decrease of approximately 20% in LOE per BOE produced in the first quarter of last year. We also had a few operational results and achievements across our position worth highlighting. In the Midland Basin, our first down-spacing test of the Wolfcamp A in Howard County has been online for over 4 months and has performed above our results for offsetting wells completed on 8-well section spacing. In addition, we are nearing completion of the drilling of our first mega pad concept in Midland County that we expect to be a model for larger pad developments in other areas going forward.

In the Delaware Basin, our first 2-well pads, which is targeting both the upper and lower Wolfcamp A, has been producing for almost a month and is posting strong early time rigs with very high oil cuts and formation pressures. Given the results we have seen from our Spur area over the last few quarters, combined with the recent addition of a second rig in the Delaware, the Spur area will be an increasingly important driver of production growth and capital efficiency in the future.

Moving to Slide 4. We continue to deliver amongst the strongest operating margins of any producer with an operating margin of $44.31 per BOE in this past quarter. Consistent wells productivity, timely pipeline offtake arrangements, thoughtful infrastructure investments and continued focus on operate -- operating cost improvements have all contributed to sustained increases in this critical measure of internal cash flow generation over the past 2 years. Despite an increasing level of industry activity, we expect that our leading cash margins will continue to be a differentiator for Callon given the investments we have made in our team and critical facilities to preserve this advantage for the long term. Importantly, this internal cash generation provides a clear path to align with the growth capital we are spending per BOE produced in the near term. As an example of this progression, in the first quarter, our operational capital is $28 per BOE versus operating margin of $44 per BOE.

I'll now move to the -- Slide 5 and discuss our capital spending for the quarter. You can see that our first quarter operational capital spending came in at just under $117 million for the quarter, better than the anticipated total that we discussed in March. While we factored in 10% service inflation for our 2018 CapEx estimates, E&C cost inflation has been limited thus far in 2018, but we continue to work on areas of cost improvement and efficiencies to mitigate any unexpected increases that may be working their way through a tight labor market.

In terms of big-ticket items, 4 of our drilling rigs are on longer-term contracts with only 1 rig coming up for renewal this year. In addition, we recently entered into a long-term agreement for 2 dedicated frac crews. As I highlighted earlier, you can see in the right-hand graph that we're able to deliver above our expectations for wells placed on production in the quarter as the team has efficiently integrated a new rig and frac spread into our program.

Looking at the balance of 2018, we expect the pace of wells turning lines to be fairly balanced over each of the remaining quarters after updating our E&C schedules to optimize operations over our larger pad development. Ultimately, this should result in a more linear growth profile for the year with production increasing approximately 10% per quarter throughout the remainder of the year.

With that, I'd like to call -- turn the call over to Gary Newberry for our operations update.

Thank you, Joe. I will start on Slide 6 with activity in the

Midland Basin. As Joe stated, during the first quarter, we were moving rigs around the basin, but the majority of the wells placed online were from Ranger and Monarch. As we move into the second quarter, we will have Wolfcamp A wells from our Fairway area coming online as well as additional wells from our Monarch area. Very successful recycling efforts at Monarch resulted in sourcing 40% of our frac water needs from recycled produced water. This is quite an accomplishment and sets a strong precedent for what we expect as we prepare to frac our 6-well mega pad and further illustrates the high expectations for use of recycled water at Spur.

As Joe mentioned earlier, we are making excellent progress with our first mega pad at Monarch. We've completed drilling of 5 of the 6 wells and are currently drilling the lateral section of the sixth well. We currently have these on the completion schedule for late second quarter with first production in the third quarter. We're seeing very encouraging results from our Wolfcamp A down-spacing test in Howard County, which I will talk more about on the next slide. We've also had the opportunity to begin utilizing some intra-basin sand and have seen no performance issues thus far. We will continue to integrate local sand into our completion strategy as we will have access to local supplies through our pressure pumping partner, Schlumberger, beginning Q3 2018.

Moving to Slide 7. Our Wolfcamp A down-spacing test in WildHorse has performed extremely well during the first 120 days of production as compared to 2-well pads that are direct offsets in the same area of our Fairway asset. This is an important data point as we transition to program development with larger pad concepts this year. We will continue to watch these wells for the next couple of months before we make any decisions about added down-spacing testing in the Wolfcamp A in Howard.

I will now highlight activity in the Delaware Basin on Slide 8. We have ramped activity as promised and are starting to see some excellent well results along with improvements in our well cycle times. As you can see in the bottom left-hand graph, our first 2-well pad at Spur, which includes an upper Wolfcamp A and a lower Wolfcamp A, has been performing extremely well through the first 20 days of production. It is early, but average oil production from these 2 wells is beginning to significantly outpace the average of our first comparable wells at Spur. Both wells have exhibited high reservoir pressure following drill-out of the frac plugs. The wells have achieved production rates of 1,700 barrels oil equivalent per day with 85% oil cuts while continuing to clean up. We are very encouraged and expect to have additional wells at Spur online later this quarter as our activity in the area is reaping the benefits of our recent drill rig addition and infrastructure work.

As shown on Slide 9, we have become more efficient in our drilling at Spur as we get a few more wells under our belt. We have achieved better than 25% improvement in our drilling footage per day since our first operated well and feel there is much more to achieve in cycle time reductions, which will offset cost pressures throughout the year. As shown on the graph on the right, we compete very well against peers in the Spur area. Our average footage drilled per day through our first 6 operated wells is ahead of the peer average by 18%, and our most recent well was even more improved. The team continues to look for ways to safely reduce cycle times while drilling highly economic wells.

We spend a fair amount of time talking about infrastructure and how it relates to our operational efficiencies and ability to effectively ramp production on new wells. On Slide 10, we have provided an update on the significant infrastructure milestones at our Spur asset, which enables us to develop the asset in the most economical and responsible manner.

As I have said on many occasions, we feel recycling is going to be the right answer in the Delaware Basin as it reaps the benefit of reducing costs while pairing that economic incentive with the environmental benefit of reducing locally sourced water for frac operations. The business is significantly impacted by logistics, and water management is a major part of that planning process. As shown on the slide, we are ahead of the curve on constructing new tank batteries. And even more importantly, we have made significant progress towards tying in saltwater disposal lines across nearly our entire position. We've also installed 2 separate 1 million barrel recycle frac pits connected by water transfer lines.

Also shown is the central gathering facility and interconnect to the Goodnight Midstream saltwater disposal pipeline to carry non-recycled volumes off-lease to the Central Basin Platform for disposal. We expect added efficiency gains as we complete the most significant portions of the Spur infrastructure project in September with the commissioning of the Goodnight tie-in and pipeline system.

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

Thank you, Gary. You can see on Slide 11, we continue to maintain a recently enhanced liquidity position with an increase to the borrowing base of $125 million, bringing the facility up to $825 million with an elected commitment level of $650 million. Along with the increase in the facility, we pushed the maturity date out to May of 2023 and saw a reduction on the pricing grid of 75 basis points. This further reduces our cost of borrowing.

With the recent changes, our net liquidity position at the end of the first quarter was just under $600 million. This leaves us in a very strong financial position as we continue to see robust margins supporting the planned spending associated with our annual capital program. Our debt metrics continue to remain in check, and we are closing the gap on reaching a state of cash flow neutrality.

Moving to Slide 12. We continue to have some of the stronger 2018 Mid-Cush hedges among our peers with approximately 60% of consensus oil production covered at less than $1. We have continued to add to our hedging position in recent weeks with 9,000 to 10,000 barrels of oil per day covered with collars in the 2019 timeframe. Those collars have a floor of just under $54 and a ceiling that has been increased to just under $64.

Given recent movements in the Midland-Cushing differential, coupled with the lack of longer-term liquidity in hedging volumes, we are being patient in putting 2019 differential hedges in place. Along with addressing pricing for oil out of the basin via hedging, we have recently agreed to 2 incremental firm sales agreements, each providing up to 10,000 barrels per day through December of 2019 with firm takeaway on various long-haul pipelines where both parties hold FT capacity. This only further enhances our ability to move volumes as we continue to ramp our production over the next several quarters across both the Midland and Delaware Basins. We also continue to look at the potential for longer-term physical deals on long-haul pipelines, and we'll review opportunities that may be attractive.

With that, I would like to hand the call back over to Joe.

Thanks, Jim. That concludes our prepared remarks. And operator, I'd like to turn it back to you to open the line for questions.

(Operator Instructions) The first question is from Asit Sen of Bank of America.

Guys, you guys have been fairly early on your infrastructure build-out. My question is what headroom do you have over your production guidance as you lay down infrastructure in 2018 and '19? In other words, what do you see as the greatest chokepoints? And then I think you've talked about divesting some infrastructure this year. Could you provide us an update on your thought process?

Yes, Asit, we think about infrastructure a lot. We recognize that in order to be efficient out here, we've got to move -- be able to move this product from the well, both water and oil and gas, all 3 components of it, in an efficient manner. So we worked hard on water disposal systems, water infrastructure systems to be efficient with the way that water moves to best ramp up oil and gas. And that's why in every area, we've actually invested in our own infrastructure, as you've mentioned. We've been -- we've actually partnered with third-party service providers that are aligned with our goals of going to either deep disposal in the Ellenburger to where we can avoid shallow drilling hazards or we're going to take the water offsite to make certain that we don't cause significant future problems while we're accessing this valuable resource. So we've done a lot of that throughout all of our assets as we've brought them on. And as you know, in my detailed description of our Spur asset, that being our newest asset, that's where our greatest focus is today because we see so much opportunity there. Now we still work on that every day, and I think the key to success is to make certain that you have an operating team that's there, planning for that, being ready to move that fluid just as soon as those wells are drilled and fracture stimulated. And I think we're well positioned across all of our assets to do just that. As far as the disposition of some of the assets that we've invested in ourselves, as we've developed these longer-term relationships with third-party providers, we think it's only the right thing to potentially divest some of those assets at competitive market pricing for their benefit and for ours so long as we don't put pinch points in our plans to ramp development in the areas that we've invested in. So we think it's the right thing to do. We've always thought it to be the right thing to do, and we'll continue to focus on that as we get better and as we continue to think about ramping in the future. So you asked about '18 and '19 capacity. We think beyond '18 and '19 when we think about infrastructure. So we're well covered at least for the plans that we have throughout that timeframe.

That's very helpful, Gary. So -- and my follow-up is, what do you think your average pad size is going to be in 2018 compared to '17? And what is the optimal pad size given your current footprint?

That's a good question. Again, we think about pad size and cycle time in similar ways because it's all related to value, and we're focused on value. And that's why the 6-well mega pad that we're doing in Monarch, that was drilled with 2 rigs. That was 3 wells each. It didn't change our cycle time at all with what we've done in 2017 and 2018 in Monarch, and we'll continue to do that and we'll have simultaneous operations like you see throughout the Midland Basin by those who are doing this in a very capital-efficient manner. So the mega pad size, if that's what we're getting to, is we think 6 wells is probably good to start. We may expand that in the future depending on how we go, but we want to see how that works. Our infrastructure that we've built has plenty of capacity to manage the flowback of those wells. That's one of the biggest challenges the industry has is whenever they go out and do big mega pads, how do they move that much fluid of both water, oil and gas from a single point -- single take point going forward in a short period of time. Again, that's part of the reason we've been so focused on infrastructure is because we knew we were going to get to very efficient program development across all of our assets going forward. We were always focused on getting positioned to be efficient with moving those fluids. So for now, I would say it's -- in the Midland Basin, we're 2 to 3 well pads per rig, and we're multiple rigs on some sites. And in the Delaware Basin, we've been very transparent about we're still doing single-well pads throughout most of this year as we define the real opportunity across the Delaware Basin, the Spur assets. Understanding any variation in geology or performance across that asset position is important to us before we then jump into the most value-added program pad development going forward in 2019.

The next question is from Neal Dingmann of SunTrust.

Gary, my first question, maybe just kind of add on to what you said on the earlier one. I understand your infrastructure when you talk about water and all these other things you're doing ahead. Just make sure I understand with -- on the oil side on that Slide 10 where you talked about the Medallion pipeline connection. Is that -- could you talk a little bit more about that and the optionality that, that enables you? I mean, obviously, this morning the topic du jour is obviously the oil spread. I see Midland is down another $2, so it's minus $12 this morning. So maybe you could talk around the oil side of that.

Yes. I can talk a little bit about that, Neal. Again, we -- it's like a lot of things we do. We have a long-term view on things when we think about it early time. And specific to Spur, we got a very good arrangement with Medallion to be the primary gatherer for our Spur barrels going forward. The way we got that was because we had a great relationship with them down in Reagan County. We then grew in Howard County and they said, "Hey, we'd love to be your primary gatherer in Howard County," and they've done a phenomenal job for us in Howard as we've ramped those barrels very efficiently. And then it was a natural progression even though we had lots of different opportunities to have different gatherers. They won out again in the Delaware Basin. Now what we like about that arrangement is that we can move those barrels to multiple long-haul pipelines. We can move them from Delaware into Crane. We can move them from Delaware into Colorado City, and we can move them from Delaware all the way into Midland. So we like the optionality of that, and that also gives us optionality to actually firm up our sales contracts for a longer period of time on term deals on all those parties that have needs -- future needs, end-user needs, as well as long-haul capacity on all of the pipelines coming out of the basin. So our strategy has always been take it to market, get it to market and ensure flow. So -- and that's kind of the way we've structure all of our contracts going forward.

Great optionality there. And then just one last follow-up on the cadence. I want to make sure -- you guys have laid this out, I think, quite well for the year. You and Mark and Joe and the guys have said about -- that the first quarter was going to be a bit flat with activity, and it was. I think you all completed, I think, 4.5 wells, something like that. Could you potentially talk about just how you see the cadence for the remainder of the year? Is that still sort of in line what you were thinking previously?

Yes, Neal, this is Joe. As I've talked about in the prepared remarks, we had moved some things around to accommodate some of the larger pad development concepts we had talked about. So I think the previous slide we had out there, there was a big ramp in the second quarter that's sort of spread a little bit more evenly throughout the year at this point. No big changes, but I think just directionally, that's how the schedule has been modified.

Yes, Neal, again, recall that we actually intentionally slowed down a little bit in the first quarter because we had to build a bit of a DUC inventory. And so as a result of that, we kind of -- even though we did outperform in the first quarter, we tried to slow down. We did a little bit. We've got a couple of DUCs now, which I'm kind of happy to have, to give me a little bit of optionality on timing. But at the end of the day, it only makes sense to, as we ramp activities, to smooth that activity level out. I'm very happy with the start-up activities of both the new rig that we got from Cactus Drilling Company. That started up very efficiently. And I'm pretty happy with at least the initial results of the startup of our second frac crew from Schlumberger. They're all going through growing pains, things to learn, but we're only going to get better from this point forward.

The next question is from Irene Haas of Imperial Capital.

You mentioned earlier that you have secured 2 contracts sort of through 2019 to end users or buyers that have firm transportation, which is really smart because you're not committing anything yourself. And my question for you is, without disclosing some of the details of your agreement, what are you buying in terms of security? How much are you going to be insulated from the [basins flow] out? Just some color on this, please.

Irene, this is Mark. So the arrangement there is actually these are 2 -- and they will remain unnamed for now -- but 2 large global buyers, both of which hold FT capacity on a number of pipelines that tap into various points around the Medallion system. And they will be taking volumes as we continue to ramp volumes on that Medallion system off. Now the pricing will still be in line with our other deals, which is generally NYMEX with Mid-Cush implications. That's why we continue to look at hedging options there, and we're pretty well protected through '18. Obviously, we'd love to have just a little bit more before things start moving, but we're looking at a number of different kind of creative structures for '19 and beyond there. And we do have a couple of markers in the market right now that we think if things come in a little bit, that we could see some additional hedges come on the books there. But we're going to be patient. We're not going to rush into that. We do think it's -- there's a lot of noise in the system right now, but we are aware of the fact that we want to put things in place to handle those positions as we move forward.

Irene, this is Jim. I would just further add, Mark mentioned we have a favorable differential position. We're 60% hedged for the remainder of 2018. What I think is interesting to note is that position took us 12 months to build, and that meant that we had to be in the market, talking frequently with key market makers because that's very different than WTI and we're doing that today. It is a thinly-traded market, but we will continue to watch very closely and look for the right opportunity to start to lay in a position for 2019.

The next question comes from Gabe Daoud of JPMorgan.

Can you maybe just talk a little bit more about the Wolfcamp A spacing tests in Howard County? And maybe when you make a definitive call, I think historically, you guys like to see about 6 months of data or so. But just any more thoughts around the tests.

Yes, Gabe, the data looks very strong. So we're happy with it. We're pleased with it. Those wells are strong wells. And so we'll look at it for a few more months. But as we get into the pad development there, the -- especially the mega pad development that we're involved with going forward with program development in WildHorse, it was just an important data point. But the data is what it looks like. It looks like it -- the additional 2 wells seem to work. So it always takes a little bit more time to make certain that you don't have a little bit steeper decline on those wells as you go forward. But so far, it looks very good.

Understood. And then just any color on in-basin sand, how it looks so far? And then were there any logistical issues at all in terms of procuring sand or anything like that in the quarter?

Not for us. Again, we maybe had 1 day or 2 delay on a pad, but it wasn't significant for us. And we haven't jumped all in to the intra-basin sand yet. We've done it on a couple of pads because we had access to it through our direct sourcing agreement with Hi-Crush as well as through our sourcing agreement with Schlumberger. But at the end of the day, our direct access to look into intra-basin sand really kicks in, in Q3 2018 with our longer-term agreement with Schlumberger. No issues for us so far. We're happy with what we're seeing. The lower cost is a real advantage to us. Getting that logistical challenge worked out within all the mines, I think, will be helpful for the entire industry. But we weren't -- we hadn't planned for large volumes in Q1 or Q2 simply because we fully expected that it would take a little bit of time to ramp up efficiency at many of those local mines. So we're in good shape.

The next question is from Brad Heffern of RBC.

Sorry if I missed this in the prepared comments, but is there any update on the Wolfcamp C well in Ranger?

Brad, thanks for asking that. No update at this point in time. We're still very happy with the performance of that well. We just got a sub-pump in it last week, so we're ramping that up as we go. And so still more time before we report definitive results on those wells. We have already participated in another well that was drilled by another operator. Anxious to see that one completed in the next month or so and the results associated with that and compare those results with the results that we've gotten. But again, the well is a good well, and I think I told you on the call last time that it's not acting like a Taylor well that Parsley had, just to be clear. I want to be clear on that expectation. And the only other color I'll give you is, it is making a little bit more water than I would've hoped. So a little bit of tidbits there, but we're not really ready to define any future infill potential at this point in time.

Okay. Appreciate that. And then circling back to some of the infrastructure questions from earlier. It's been a heavy lift. You guys have been doing a lot. Can you talk about the trajectory of infrastructure spending in 2019 and beyond? Is it pretty ratable? Or are we going to see a lot of the investments that you're making now start to taper off?

Yes, Brad, that's a good question. Again, our expectation is as we get these new assets -- we're very blessed for having phenomenal assets in all 4 operating areas. And as we get these new assets, we quickly jump in, and having very high confidence in the resource and how it's going to perform, we jump in and invest in infrastructure as you've seen us do it over the last several years. Paying dividends already at Monarch, paying dividends already at WildHorse and the Spur assets will be greatly improved in efficiency beyond the third quarter of this year. And all of those significant pipeline systems will be in place, and there will only be minor adjustments going forward. So that infrastructure spend will significantly drop off in future years. So I would expect it to be primarily focused on just drilling and completing wells.

The next question is from Ron Mills of Johnson Rice.

Gary, a follow-up on the spacing test. Obviously, if you can go from 8 to 10 wells, significant inventory implications. But when do you think you might consider moving to a mega pad development up there? And if 10 wells is the right spacing, how are you protecting the most upside from your acreage if you're, in the meantime, going to go back to mainly 8-well spacing?

Yes, no, we're going to make this decision pretty quick, Ron. We just need to see a few more months on it. But we are going to pad development now in Howard, as you know. We're bringing 2- and 3-well pads on. And so we're going to look at it. There're couple of steps here, right? One case doesn't make it all work. Now you've got to go in and do it in a pad development manner and make certain that that works. And we're going to go in it. We're going to jump into it. We're going to believe in it because then ultimately, we need another 6 months to 1 year even to watch the decline of those wells just to make certain that we're not then overinvesting, because we don't want to underinvest. We don't want to lose opportunity, and we don't want to over-invest. So this is just a maturity curve, a learning curve as we and the industry gets very comfortable with the right spacing across the basin for each individual landing zone. So that's the only reason we have -- always I'm a bit cautious about these types of things. We're very comfortable with the [13 wells per] spacing in Lower Spraberry. But now I'm going to go in and do a mega pad opportunity in the Lower Spraberry and say, wow, we were right. I've just got to -- I always have to calibrate results with what our expectations are, and that's why I'm always just cautious about saying this is the right answer. It clearly looks like the Wolfcamp A in Howard given the results we have, justifies 10 wells per section and we're moving in that direction.

Great. And then just on the flow assurance, you've talked about oil quite a bit. Can you provide any incremental color on gas takeaway arrangements and assurance of gas flows especially as we think about industry growth back half of this year and into next year?

I think, Ron, what we've typically done there is first remind folks that we have a very high oil cut in the 77%, 78% range. We've said we have firm transport to Waha and a downstream point in the Delaware. We've got a strong kind of diversified network in Midland. And I'm not sure, Mark, you want to add anything beyond that?

No, I think if you think about the Spur adds, that obviously being in an area where we'll see volumes ramp there. Obviously, early time cuts on these wells at 85% oil and at least about 15% to be split between gas and NGLs. And then above and beyond that, our gathering system provider there is looking at a second tap that will touch a new north-southbound line coming into Waha, and they are going to have FT on that. So we have dual outlets there from our footprint and producing, I guess, what I would consider a minimal amount of gas compared to some of our peers. We're pretty comfortable, and we always have the option of determining those longer-term markets if we want to and aligning ourselves with an end user.

The next question comes from Jeff Grampp of Northland Capital Markets.

Just maybe a couple quicker ones here on these -- both the 2 most recent Spur wells. Can you remind us what the laterals were on those? And then just generally, what's the kind of plan is there, I guess, average lateral of the Spur program this year?

Jeff, you broke up a little bit. I just want to confirm your question was lateral length from the 2 most recent Spur wells. Is that correct?

Yes, that's right.

Those were just over 7,500-foot wells on completed lateral length. And then going forward, it'll vary depending upon the spots. We will have a lot of 10,000-footers, planned 10,000-footers. We will have some shorter laterals where we are section constrained and need to put a well down since we're still in a little bit of an HBP phase on this asset.

The next question is from Mike Kelly of Seaport Global.

You've been really proactive on protecting yourself from this Mid-Cush basis blow-out, so I'm not surprised to see you're assessing some longer-term contracts and capacity in these pipes slated for 2019. I just would love to kind of hear how you're thinking about this opportunity though and how much you'd expect or want to lock up with the FT deal. And then I really don't have a good sense of how much, with the kind of ballpark prices, how much it's going to cost to actually get one of these anchored with the transport fees. So any sort of kind of ballpark number on that would be helpful.

Well, I would kind of break this into a couple of pieces. First, we're really focusing on what the ultimate realized price is, and that means we're going to continue to watch very carefully. We've been layering in higher WTI positions. I talked about the fact that we were very methodical working into the 2018 position, and we'll continue to do that in 2019. This is -- I know I've said it repeatedly, but this is a very thinly-traded market. We've put targets out there, and we will be patient until market conditions improve. I think one of the things that we've also talked about is that we want to have a longer view, and I think it's prudent to step back and take a look at a portfolio approach of complementing what we do on the hedging side with the physical term commitments. We are reviewing some opportunities there. I think it's a bit early to give specifics. But again, this will be kind of a balanced approach and we will do whatever makes the best economic sense for us over the longer term.

That's fair. Switching gears, just back at Spur. Encouraged to see -- the latest results look real good. And just, Gary, is there anything that you did differently than kind of early wells here that you could share?

We're always tweaking things. We did frac these wells with less sand than we fracked some of the earlier wells. We fracked them with a little bit different spacing on stages. But at the end of the day, we're still trying to get to the right recipe. But no, in general, we still pump our general recipe that we think works very, very well in the Delaware, only making minor tweaks to it.

The next question is from Derrick Whitfield of Stifel.

One quick question for you on Spur. Could you comment on your broader appraisal initiatives for 2018?

Yes, we're just, again, drilling the single-well pads across the base -- across the asset position just to make certain we understand any type of drilling hazards, any type of cycle time challenges, any type of changes in geology that is of any concern whatsoever before we get into a significant program development. But we'll continue to expand across the asset position just as we have. It helps us on a couple of fronts. It helps us to understand not only any type of challenges to cycle times or drilling hazards. It also helps us understand, just like Mike was talking about, any performance differences from well to well because we know all this isn't exactly the same, but it's all still really good stuff as we bring these other wells on in the future. So it's just as, as you see on that map where all those Central tank batteries are, we'll expand that as we go throughout 2018.

And Derrick, I think -- I'm not sure if you're getting this on the question, but we also had some tests in other zones that were planned in the Wolfcamp C as well as a second from Shale later this year. So on the back of all that, getting into early '19, we will have wells in those 2 zones as well as in upper and lower A as well as the B as we think about the longer-term development of the resource here. So in addition to what Gary was talking about in terms of the aerial extent testing known zones, we are doing some work in new zones as well that we've seen some encouraging data on offsetting wells.

The next question is from Sameer Panjwani of Tudor, Pickering, Holt.

On the new Delaware results, the 85% oil cut compares very favorably to the acquisition type curves you underwrote. I think the lower A curve at the time assumes 70% oil. So is there anything you can point to that drove the higher oil cut on these specific wells? Or does this just bias your overall expectations for the area higher?

Again, Sameer, we just need more time. We'll have to -- we're very encouraged with what we see on these wells, especially with the oil cut. But again, we just need more time on these wells as we see it continuing to mature. So encouraging results. Happy to have them.

Okay. And then I think there was a question earlier about the, I guess, the spacing design you used on these Delaware wells. Wanted to confirm that kind of a similar answer that spacings that the WildHorse used kind of a standard completion design, just appropriately compare them to the offset well.

No, it was very comparable to it. It's an apples-to-apples comparison.

The next question is from Jeanine Wai of Citigroup.

In terms of the efficiency rate of change in 2018, you provided some great details on the drilling side in the Delaware, and I think you mentioned that the second Schlumberger crew was doing very well. And apologies if I missed this, but can you go into more detail on the completion side of things in both the Midland and the Delaware? Specifically, if you could quantify where you are now versus say, I don't know, 3Q or 4Q last year on whatever metric you use internally to judge yourself, so whether that's stages per day or [pound sum] per day or foot or anything.

Jeanine, we're constantly looking at how we can improve overall cycle time from drilling through completions. And we're very pleased with the level of efficiency we get, especially on multi-well pad development and doing zipper fracs on these crews today as focused as they are on efficiency. We only get better each and every day. And so in the Midland Basin, where we've got a strong track record of wells as we're doing multi-well pads, we're continuing to improve cycle times on stages per day or lateral feet per day and we'll continue to do that. It's really focused on getting the right team of people, and that's why we really like this whole relationship between frac crews, wireline crews, pump down crews, all the logistical challenges around getting profit to the location, that last-mile delivery. That all matters when it comes down to measuring cycle time for wells. And of course, the quicker we do that, the more -- the faster we move oil production forward. The new crew, it's got some growing pains with it, but it's not quite where the existing crew is. But the relationship we have now, they're comparing themselves with each. They're comparing themselves with themselves. So Schlumberger understands what our expectations are. They've set the bar pretty high with the first crew, and they're committed to getting the second crew to the same level of efficiency. It will take them a couple of wells, a couple of pads, but we're happy with where they got started.

There are no other questions at this time. This concludes our question-and-answer session. I would like to turn the conference back over to Joe Gatto for closing remarks.

Thank you, and thanks, everyone, for thoughtful questions and for joining us this morning, and we'll look forward to talking again soon. Thanks.

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.