Battalion Oil Corp (BATL) 2017 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Halcón Resources Q3 2017 Earnings Conference Call. (Operator Instructions) As a reminder, this conference call is being recorded.

I would now like to turn the conference over to Mr. Mark Mize, Executive Vice President, Chief Financial Officer and Treasurer. Sir, you may begin.

Okay. Thank you. Good morning. This conference call contains forward-looking statements. For a detailed description of our disclaimer, see our earnings release issued yesterday and posted on our website. We've also updated our investor presentation for the third quarter and certain other items. And you can access that presentation on our website.

We'll start the call with a discussion of our financial performance during the third quarter as well as some thoughts on our 2018 guidance. I'll then turn the call over to Jon Wright, our COO, who will make some comments about operations, and then Floyd will conclude the call.

Production for the third quarter averaged 28,859 barrels of oil equivalent per day, comprised of 76% oil. This production included a contribution from our Williston Basin-operated assets through September 7, which is the date that the asset sale closed, in addition to a contribution from our nonoperated Williston Basin assets for the full quarter.

Production for our Delaware Basin assets averaged 4,799 barrels of oil equivalent per day during the third quarter, consisting of about 70% oil. We expect production to average 15,000 to 19,000 Boe a day in 2018, which will be comprised of 72% to 78% oil.

Our realized third quarter oil differential came in at 91% of NYMEX, and our third quarter natural gas differential came in at a little over 50% of NYMEX. Looking forward to 2018, we expect differentials to be materially better now that we're a pure-play Delaware Basin company with favorable midstream contracts. Therefore, we're guiding to a differential of 97% for oil and 80% for natural gas in 2018.

Our per unit operating costs were higher in the third quarter versus the second quarter driven by the divested production associated with the Williston Basin asset, which did close in early September. As we look forward to 2018, our per unit field level operating costs will improve significantly. For 2018, we're guiding to $3 to $4 per Boe for LOE and workover; $2 to $3 for gathering, transportation and other; and 6% to 7% for production taxes. Cash G&A will run between $6.50 to $8.50 per Boe in 2018 and will decline from these levels as our production continues to significantly ramp up as we round out 2018 and drill into 2019.

With respect to D&C CapEx, we incurred $103 million during the third quarter. And with 3 rigs running, we expect 2018 D&C CapEx to be between $280 million and $320 million. This level of capital spend will allow the company to operate within cash flow by the end of 2019.

Regarding hedges, we realized a net gain on settled derivative contracts of $9 million during the current quarter. For the last 3 months of 2017, we have right at 5,400 barrels per day of oil hedged at an average price of just over $59. For 2018, we currently have 9,510 barrels a day of oil hedged at an average price of $52.65 per barrel. And we have 3,247 barrels per day of oil hedged in 2019 at an average price of $52.31.

As far as natural gas, we currently have 5,000 MMBtu of gas hedged for the remainder of 2017 at an average price of $3.51, and we have 7,500 MMBtu of gas hedged in 2018 at an average price of $3.16. We'll continue to monitor 2019 commodity prices, and we'll add hedges in 2019 as it makes sense for us to do so.

As of September 30, 2017 and pro forma for the non-op Bakken sale and the exercise of the Northern Ward County acreage option and the closing of the tender for 50% of the 6.75% notes, we had $646 million of liquidity. And that consisted of cash on hand as well as our undrawn credit facility. Our next borrowing base redetermination is scheduled for the spring of 2018. And needless to say, we have very attractive current and projected leverage and liquidity levels, which will allow us to execute on our growth plans in the Delaware Basin through 2018 and 2019, at which time we will be operating within cash flow.

Finally, just a couple of quick comments on the income statement and the balance sheet for the third quarter. The Williston Basin asset sale did result in a gain of $492 million that was recorded in the quarter, which generated net income per common share of $2.85 and $2.82 per basic and diluted share, respectively. For a look at the financial results of the company excluding this gain as well as some other selected items, please see the Selected Item Review and Reconciliation table in the press release.

After our recent debt repurchases, our capitalization is very simple, consisting of common stock, our undrawn revolver and then $425 million of the 6.75% notes. The closing of the repurchase of 50% of the 6.75% notes didn't occur until early October. So accordingly, our September 30 balance sheet does show $989 million of cash and a current portion of long-term debt in the amount of $409 million. At year-end, this cash balance will be reduced and the current portion of the long-term debt line item will be eliminated as a result of the closing of that repurchase.

And with those comments, I'll turn the call over to Jon.

Thank you, Mark. As for our recent company presentation, our 2018 development is focused on growth, delineation, determination of optimal spacing and fulfilling HBP requirements.

To start off with Monument Draw in Ward County. We plan to run 2 rigs continuously here through 2018 with 14 spuds and 16 wells put online. One rig will focus on pad development drilling in core areas, where we know we will get great results. Over the next 6 months, we'll put online a 2-well pad testing 660 spacing in the Wolfcamp A formation, another 3-well pad where we will test Wolfcamp A and Third Bone Springs formations with 660 spacing between Wolfcamp A wells and a 330 wine rack above in the Third Bone Springs. Both pads closely offset our CRMWD 79-1H well, which, in 180 days since POL, has cumulative production at 180,000 Boe. This is a 5,000-foot lateral with an EUR of 1.2 million barrels equivalent.

The other rig in Monument Draw will continue delineation drilling across the entire acreage position, both north and south, more heavily weighted on our south area. We recently brought in a spot crew to this area. This frac crew is currently completing our second horizontal well in Monument Draw, the Sealy Ranch 9301H. This is a 10,000-foot Upper Wolfcamp well located on the Northern Option acreage in Monument Draw. We will have production results in a few weeks, and to note that it is a direct offset to Jagged Peak's wells in the area.

After completing the 9301H, the spot crew will conduct vertical stage fracs on the pilot wells we drilled earlier this year in both the north and south areas of Monument Draw. We will test the Second, Third Bone Spring and Strawn for production potential for future horizontal development. We plan to bring our dedicated frac crew that is currently working in our Hackberry Draw area in Pecos County to Monument Draw in a few months to begin fracking here to accelerate production results.

To summarize, in this area, we expect to have 2 wells POL, put online, prior to end of year 2017, with 2 to 3 additional wells prior to the Q4 earnings call.

Infrastructure development at Monument Draw is full speed ahead or as we call it, internally, hawk speed. We are constructing a centralized processing facility, which will allow for more efficient operations and will eliminate the need for tank batteries on individual pad locations. The commingled production will flow to that centralized facility on our HK-owned surface position. We expect to process gas by December and all fluids by early Q1 2018. Initial capacities will be 24,000 barrels of fluid per day, increasing to 72,000 barrels of fluid per day throughput. This will save quite a bit of money for us down the road on facility costs and provides a single point for oil and gas sales.

Water infrastructure is a key part of our business. The current capabilities in this area include 1 million barrels of freshwater capacity with 60,000 barrels per day rate, an additional 860,000-barrel recycling facility with 40,000 barrels per day of throughput rate.

As we move to Hackberry Draw in Pecos County, we brought a third operator rig in this area in September, which will continue to work in Hackberry Draw through 2018 with 18 wells spud and 16 POLs. 2018 will focus primarily on HBP drilling with some delineation. This rig is currently drilling a Third Bone Springs well to test this interval on our acreage. It looks like a great target for us. And note that the First, Second and Third Bone Springs look productive across the entire acreage position.

We're running our dedicated frac crew in this area since September. 3 wells have completed so far and currently completing the Hannah-Johnny 1H, a 10,000-foot Wolfcamp B well located towards the eastern end of our acreage. Note that we expect to POL, put online, an additional 3 wells prior to end of 2017, bringing our total to 6.

We recently reached a 24-hour max IP of 1,344 barrels equivalent per day on the Ethel Jesper East 1H, a 10,000-foot Wolfcamp A well. This well is performing better than our nearby Faye West Unit 1H, which has been online since early 2016 and is estimated to be a 1.2 million-barrel well.

Note that our IP20 was a -- on the Ethel Jesper was a constrained rate. Our IP24 was recorded yesterday. And we expect a peak IP30 rate that will be significantly higher than our previous IP20. There's a slide in our investor presentation that compares these 2 wells' production, which illustrates this point.

We're flowing back to Berkley State East 2H right now. It's a 10,000-foot Wolfcamp B well. And we'll have results within a few weeks. We plan to complete one more well here with our dedicated frac fleet before moving it over to Monument Draw in early December to frac a 2-well pad, as previously mentioned.

We are continuing to invest in infrastructure in Hackberry Draw as well. We are close to completing our second water recycling facility here, which will give us 1.8 million barrels recycling capacity at 80,000 barrels per day throughput. Note that we also have 45,000 barrels of salt water injection capacity. Our primary focus is on reuse. Our current fracs are using about 80% processed produced water.

We also expect that our Elizabeth high-pressure treating compression site will be operational within the next few weeks, providing a reliable sales point for our Pecos position. And finally, we have also recently completed construction in our field office and equipment yard here and held an open house to announce that the hawk has landed on Delaware.

Thank you. And I'll hand the call over to Floyd.

Thanks, Jon. So look, as Mark mentioned, we're guiding to about 17,000 barrels for '18 running 3 rigs and spending $300 million. This is going to result in extremely strong growth. And the Q4 '17 versus Q4 '18 growth will be spectacular, and the exit rate will be quite healthy as well.

We've given some directional ideas about other years, future -- beyond '18. You can see that on Page 6 in the presentation that we just posted. Important to note, and intentionally we put some metrics and measures about liquidity and balance sheet on the same page. So while just using very few rigs, our growth rate will be very strong. We're watching the progress on our balance sheet, and it looks, even though it's strong now, it strengthens throughout this. Again, that's on Page 6.

Operating costs will be vastly improved over historical levels given our move to the Delaware. If you run our production and cost guidance through your models, you'll find that field-level and corporate-level returns are expected to be excellent next year.

Again, financially, our balance sheet's in great shape, no net debt and plenty of capital to run our development drilling program and to turn cash flow positive in '19. And we expect to keep debt levels very low. Any improvements in crude prices might just hasten our drive to positive cash flow rather than be a catalyst to add another rig. As we've shown with just 3 rigs are definitely substantial and our spend sustainable.

Our drilling plans, as Jon mentioned, are focused on developing our great acreage position in several landing zones at Wolfcamp and several landing zones in the Bone Springs in both of our areas, Pecos and Ward. And we'll be creating the data needed to make smart decisions on spacing. We have a lot of internal technical work going on along those lines, which we'll be reporting to you more and more. And as Jon pointed out, we will be reporting quite a few wells over the next several quarters. And the latest well, as Jon pointed out, is in the presentation on Page 25. It looks to be a really good well. And it'll meet or exceed our type curve of 1.2 million-barrel oil equivalent. I think about 80% oil if I'm remembering that correctly.

So while we have no need to add substantially to our current acreage position, we'll continue to evaluate bolt-on opportunities. Our balance sheet is perfect for this. And I'll point out, Jon didn't mention it, but we have well-researched deeper projects in both of our areas that we will be moving forward on in 2018. We're not going to talk about those a lot, but there's a lot of data in our own properties and from our peers that tell us it's an important resource for us to evaluate.

I believe that our successful development of our existing acreage will translate into an improving share price. And we'll see how that all works out. Jon also mentioned the -- some buildout of our midstream infrastructure, both in water, gas and oil. This is Halcón Field Services. It's a very big value opportunity for Halcón. And we're -- I would encourage you to visit -- to head west and visit this some time. It's really impressive. We will stay in front of all matters infrastructure-wise. And you can see a few details of that on pages 13 and 15 of the presentation.

We're also evaluating out-of-basin opportunities for crude price improvements or avoiding some basin differential issues. So more to come on that. There are several large projects that we're spending a lot of time working and thinking about.

So in 2017, we had a plan. This plan was formulated in 2016, late '16. The plan was to sell out of 2 basins and enter the Delaware in a meaningful way, improve our balance sheet and increase liquidity through divestments and capital markets transactions. And while we anticipate really strong growth, we will maintain and continually evaluate the all-important measures of fiscal health as we point out in -- throughout our presentation. And our goal is to become a significant player in this world-class basin. I am happy to say, "Mission accomplished."

Operator, we're ready for a few questions, if there are any.

(Operator Instructions) Our first question comes from the line of Jason Wangler from Imperial Capital.

I was curious, obviously, it sounds like you haven't fracked the vertical well in the Northern Monument Draw play. But was curious, as you've looked at that data versus, obviously, the success you've had further south, how that shapes up in terms of any details you've seen or even maybe how you look at the completion maybe as you go to that horizontal versus the one down south that, again, has been pretty successful.

Yes, Jason, we don't really talk too much about pilot wells. They're highly confidential and they're totally exploratory as we step away from existing data points. We can say that we have a significant development in several zones across the acreage up on the north end. We're testing zones that would not be our bread-and-butter zones in the vertical stack, in the vertical -- these vertical frac jobs that we're doing, so that we'll have the data point. We know that we'll be developing our usual suspects, if I will -- if we will, if we can call them that.

So a pilot well does -- is designed for data and to help delineate things and then set the path for the horizontal drilling. And it's working great. We're drilling a pilot well on the -- down pretty far south as well. We're also getting ready to complete a few zones in the very first pilot well we drilled down in the Section 79. So these are really important data points to us and really intend to report more on actual horizontal results since the -- you don't typically make a real commercial play out of a vertical well in these types of zones. That's a great question, and they're fulfilling their purpose. They're -- have shown us that we have lots of pay spread over the area.

No, that's fair, and I appreciate the color. The only other one I was curious about, I think you mentioned in the release, there is some acreage holding requirements, I think, at Hackberry Draw. Just curious, any color around that as far as how many wells or it's kind of what you're accomplishing next year as you go through that.

Jon?

Sure. As I mentioned, on Hackberry Draw, there will be a -- we'll be spudding 18 wells this next year. There will be a mix of wells in our northern tier and our southern tier acreage.

Our next question comes from the line of Asit Sen from Bank of America.

So I had a -- I mean, the Slide 6 looks great. And particularly, I wanted to probe a little bit into the annual production numbers through 2020. And it's very helpful for the analytical community. But wondering if you could provide us your basic assumptions on cost inflation, efficiencies or are you factoring any change in completion designs, just some basic assumptions.

Yes, listen, I'm going to get Quentin or Mark to address your -- the first part of that. But these numbers are directional in nature. They'll certainly get fine-tuned. And they are pure outgrowth of our expectations of making our type curve wells, in a general sense, with no improvements. And Quentin or Mark, what could you add to that about the first part of that question?

Yes. We're using our public D&C cost guidance to drive that. We're using 25 to 30 days drilled -- drilling time in Pecos and around 40 days in Ward. And those numbers over the next couple of years will decline. And we're modeling some decline as we become more efficient, but nothing extravagant. And it's a pretty conservative, high-level type forecast that we used to create that slide.

Great. Very helpful. And then on comparing the Ward and Pecos, you've given us some EUR guidance broadly, but could you compare and contrast the 2 areas in terms of well cost, kind of thickness, depth, oil cut, any early expectations that you can share with us?

Jon, I think that's the perfect thing for you to address. They are quite different. One is more complex geologically. Go ahead, Jon.

Yes. As Floyd mentioned, our Ward County area is more complex geology. But -- and really, Pecos is fairly homogeneous. So that's one way to look at both of those areas.

Pecos County, we're getting some amazing drilling results. That's included in our slide pack. We recently drilled a 10,000-foot lateral in 18.5 days from spud to TD, which is a pretty solid result. We expect to improve upon that. With those type of drilling results, you're going to see a lower cost structure in Pecos County. And that's noted in our deck as well.

Both areas have outstanding EUR. Our expectations with our type curves and the results thus far show that. So our south area of Ward County being at about a 1.8 million-barrel type curve on a 10,000-foot lateral, very strong results there. But in Pecos County, we're seeing, with our type curves and our well results with existing PDPs, 1.1 million to 1.3 million barrels. That's our expectations. I hope I covered everything.

Yes, great, appreciate the color.

So listen, back to the first part of the question on that Page 6 in the slide deck, this future growth that we're projecting. This is using a very modest rig count. And we don't talk about growth as a one single subject. We talk about growth in fiscal health in the same breath. And we're trying to demonstrate throughout this presentation that we're focused on both of those equally.

Growth isn't a matter of putting a few rigs on this great rock. It's also just as important to us to be really strong. And in the future, if the crude markets give us other indications, we can change things. But we don't really talk about just growth anymore. I know that, because I've read some articles from some smart people about all that, but we talk about growth using a cautious approach to rig count and -- but we talk about it hand-in-hand with fiscal health.

Floyd, just following up on that. What would it take for you, conceptually, to add a rig? Are you completely ruling it out?

Of course, I wouldn't rule it out. You got to have a mid-$60s price for a rig under current cost estimations to carry its own weight, if that helps give you an answer. So our plan, as I mentioned at the tail end of my awesome little speech on this call, our plan was to sell property, raise enough money to enter this basin. But raise enough money in front to take care of the outspend that we anticipate and project, and we've done that. So again, a mid-$60s price with current cost, a rig will carry itself.

Now to carry itself over time, I'm just talking about that year, that first year. Over time, it's -- the return is awesome. But that first year, that's when you talk about liquidity and leverage.

And our next question comes from the line of Mike Kelly from Seaport Global.

Appreciate the visibility through 2020 and what you've provided on Slide 6. Just wanted to get your sense on the risk to achieving this growth and what you think are the potential operational impediments that you might encounter here and just the biggest risks in your eyes, especially in hitting these numbers.

I'll ask Jon to add to this, but we didn't get real -- try to be real cute. We gave some numbers here. It probably would be more appropriate to give a range. But these are directional in nature, so you could bracket these with a range, several thousand barrels on either side of those numbers.

Operationally, we see no risk to getting -- I mean, we know we have the rigs. We know we have the frac crew. We know we have the technology. And if you think that we have nearly 2,000 locations already identified and we're drilling between, what is it, is it 20 or 25 wells a year out here, depending on where the rigs are going to be, you're scratching the surface of our inventory.

So risk, we don't view a lot of risk to reaching these. You can always have a train wreck on a well. That happens to us, sometimes in others. And the bad news about running just a few rigs is, any delays or problems on wells really enter the equation because you have such a small sampling.

If we're running 10 rigs, you can have some issues or delays. We had a delay early in the year with some issues with a frac, completing frac jobs with someone. And we made a change there and we lost 6 or 7 weeks, and that was hurtful. But Jon, I don't think I see any real issues with getting to where we're projecting.

I don't either. And one of the things that our company has always been forward on -- forward-looking on is, how do we manage our infrastructure. And here, with Halcón, you can see our infrastructure plans are front-end loaded. And we've got a lot of -- we got a very strong capability early in our program, and I think that's key to really keeping us on target.

Great. And my follow-up, actually, I do want to ask on the infrastructure side of things and one, you've been successful building out your midstream capabilities in the past. How do you think we should really view what the ultimate value of what this midstream side of the business is going to be for you? If we look out a few years, what's kind of a ballpark way to look at it?

So the first way to think of it is, we are so far out in front of requirements. We will not have delays based on infrastructure. And that is a huge maintenance issue for value, of course. If you have to drill a well and have to wait 6 months to get something done or if you're waiting on water all the time or you don't have any pipe in the ground, it's just a big issue. So we're way out in front of that.

Ultimately, it depends somewhat on the capital markets and the valuation that's ascribed to those types of businesses.

In the past, as you've mentioned, we have been somewhat successful in that area. We did maintain ownership of those things until we were comfortable that the basic spine and the basic layout of all the infrastructure was sufficient for the future.

Then it's just a matter of deciding if you have a good use for that money. And it's a -- there's a going rate for all of those fees, gathering and whatever -- that's water transportation or gathering or whatever. And you can value the EBITDA on those really rather easily on the back of an envelope. And then in the past, the capital markets have been very supportive of those businesses, whether they're drop-down type partnerships or just outright sales.

Early on, the most value for us is keeping our -- keeping way ahead, keeping that infrastructure coverage way ahead of the rig -- of the rigs. And it is front-end loaded, as Jon pointed out, which is -- everybody's watching the pennies. Okay. So that it's front-end loaded and you just can't shirk in that area. But it's quite valuable. It's worth hundreds of millions of dollars already. Okay. I'll just say that much.

Our next question comes from the line of Jeffrey Campbell from Tuohy Brothers.

My first question, kind of more of a narrow one, then I'll ask a little bit broader one for the second one. You announced your intention to exercise the Northern Option ahead of the well result of the Sealy Ranch 9301H. I was just curious why you didn't prefer to wait for the well result first.

I -- let's just say this. I didn't announce that. Now if somebody in our company did, unknown to me, we're going to have to have a little talk. We would never undertake an option before we had all of the -- pay up and own an option before we had all of the data that we're entitled to, period. That'd be, what would I say, I think the direction of your question is, that would be stupid.

Right. Well, I was just going on what I saw in the press release, but it did strike me as a little odd, which is why I wanted...

If that's in there, it's wrong, wrongheaded, but I don't remember that being in there. If it is, we'll -- I don't think you do retractions, but we'll try to make it very clear that we'll gather all the data that we're entitled to in a fair, businesslike way before we undertake any contract.

Yes, Floyd, I think the press release, just to clarify this point, indicates we plan to exercise it based on where we sit today and what we know about the acreage, but we have not yet exercised it. And just as we're planning and people are looking forward on their business plan, you ought to probably assume that, that capital will be spent.

Okay. So it's a bit forward-looking, Jeffrey. We drilled a pilot hole up there and we got the exact information we were looking for. We're fracking a 10,000-foot lateral in the western side of that acreage. We have a wonderful Weatherford log, a horizontal open hole log of the entire wellbore of that. And we have about 6,000 or 7,000 feet of the kind of rock, exactly the kind of rock we were expecting. And then about 3,000 feet of rock that far surpasses our expectation.

So we're not expecting any curveballs when we finish fracking the well and get it on production within the next few weeks. But I think the word plan there maybe threw a curveball out there. Our plan is to gather all the information that we're entitled to before we make any financial disbursements.

All right. Well, that's a lot of color that I think lends a lot of confidence to the plan. My broader question was, over the past few quarters, a number of the major E&Ps in the Permian have moved towards batch completions or they've talked about cube development of multiple productive zones to avoid parent-child production effects on pad completions. I'm just wondering what your view is on this issue and how it will affect your pad development practices, if any.

So we're somewhat smaller than some of those companies. It's the obvious right answer to do that kind of development. But I think I need to suggest that, at least for our company, we need to step back and fully evaluate in all ways that we can what our frac jobs are leading us to in terms of spacing.

So I am -- we are absolutely not prepared to cube out one of our drilling spacing units right now. Even if we were willing and have the fortitude to be on a pad like that for over a year and not have any income out of it, which we're just not set up for that, as you know, right now either. And we're very conscious of the parent-child relationship in all of these plays. We measure the hits we get in producing wells. And when wells are proximate, Jon is fracking them simultaneously or zipper fracking them and not putting them on until the same time.

So we'll do the best as we can to narrow the difficulties you might have from those things. But we are -- again, we're not really in a position to drill 20 to 30 wells in 1 -- in a cube development. And we're still evaluating some of the other zones in these areas. The Upper Bone Spring, the Third Bone's becoming relatively clear. And then we got some deeper zones in the Wolfcamp. And if you're really going to do a cube, I mean, you pretty much need to have all that stuff in front of you. Jon, what would you add on that? We talk about this a lot, by the way.

I'd just add that the key for us on our particular acreage position is really understanding our optimal spacing. And that's probably the first step in our development plan.

Well, that makes perfect sense. And I mean, if I just translate what you just said. You're basically talking about a capital cycle. And you don't want to lock up too much capital for too long before you get the cash flow you want. But you're also going to grow so much over the next couple years that this might be a topic that we could revisit in a few years and get a different answer. You think that's fair?

It's actually the right thing to do in other plays as they got more mature. And if we got larger, we would do a pad all at one time. And many of those other plays were single pays. This is complicated with multiple pays. No real barriers between many of the pays, including the Third Bone and the Upper Wolfcamp.

Now there's some barriers in some of the Upper Bone. But -- so it's an issue. And so we're doing a lot of microseismic. We're doing a lot of pressure measurement. And we're watching hits on every stage. So we're going to get there.

But right now, we're thinking, because just from experience that we can develop these things on 660 with a chevron-style or a wine rack-style development from -- as you go from upper to lower, as you go from more shallow to more deep, but we really want to get that totally identified. And again, it's not just an output of how efficient and how well-designed your frac jobs are.

And our next question comes from the line of Tarek Hamid from JPMorgan.

This is actually Kevin Kwan calling in for Tarek. Just -- this is just surrounding -- I know those guys are kind of coring up their acreage in Pecos County. And I was curious if there's been any talks with you guys on potential acreage swaps with some of your partners, maybe with Diamondback or maybe Callon?

Jon, go ahead and tell him something about that. But companies are sort of like people. You run into one person, and yes, let's go do this. You run into another person, that's going to take me a year to think about it. You run into a third person, it's no, I don't even want to talk about it, we're too busy. Jon, what do you have to add about that? We're working that angle daily.

Yes, absolutely. We've been in contact with our neighbors per se. And things are in the works to try to consolidate acreage where we can. The focus a lot is on optimal lateral lengths. And our focus is on 10,000-foot laterals. So we're working with our neighbors on how do we consolidate acreage to optimize that type of development. We have made some small, small trades to consolidate acreage, but nothing, nothing major. We're talking a couple thousand acres so.

I bet you have 10 or 15 conversations going right now, though?

Absolutely.

Okay. Helpful color. And then this is just on your 2018 guidance. I understand the sort of the range in your production guidance for full year is 15,000 to 19,000 barrels a day. Just kind of want to see sort of the ramp that you guys are having. What's kind of the assumptions that you make for the downside, in the 15,000, and versus the sort of -- just an overall gauge of what the range is and how you guys got to that range?

Yes. So someone in the company will cringe. But the midpoint of that guidance, we wouldn't put it out there if we didn't think we could exceed it. The downside of that guidance, the way that I view it, and Jon, you could help with this, would be purely timing issues, whether there was a major frac problem or a big fishing -- something that was really causing us delays that we just couldn't project for. Normal wear and tear and delays, that's the bottom of the range. And the upper part of the range is based on no delays and continued great results. What else, Jon?

Well, I think you've nailed it there, Floyd. We have a small program, 3-rig program, running 1 fleet. Any delay could have a -- with a rig or the frac fleet could cause a delay. But that's -- I think that's been well addressed.

Okay. And my last was just on cost-saving initiatives. Obviously, that's been an evolving thing. But just wanted to see sort of more granularity on more recent -- during the quarter, I think some operators were speaking to sourcing frac sand locally, et cetera. Just want to get more detail on more recent cost-saving initiatives you guys are looking at.

Again, I'm leaning on Jon, and I want him to pipe in here. But another part of running just a few rigs is, we really can't afford to experiment. And not that these aren't great experiments that are going on. And some of them are going to work out great. And we hope they do.

So we're not really trying to save $0.5 million on a well because of the proppant. It's a worthy savings, and we will be. But with just 3 rigs running and 1 frac spread, as you pointed out, what's the risk to our guidance? Well, we just really can't -- we don't feel like we should be doing kind of the experimental things that you do to really, really trim cost at this juncture. We're watching costs quite avidly, of course. But Jon, what else about that and about the local frac sand?

I will say that...

Which we're not against, by the way, by any means. We're all for it. Go ahead, Jon.

Well, we've looked at -- and we're talking to a number of sand providers that are located in the basin. The concern for us is that the crush strength of the 40/70 brown is very similar to our closure pressure. And as Floyd mentioned, I think our key to our development at this point is execution and delivering positive well results. I'd hate to introduce a variable that would cause us to have some concern about that at this point. It would save about $0.5 million per frac, so that's one way to look at it. And it's not something that we would rule out in the future, of course.

Other aspects of it, as Floyd mentioned, we're looking at our costs, but being more efficient is really what drives costs. And as we look at our drilling results, especially in Pecos County, over the past 3 quarters, we dropped -- we've had a significant reduction in our drilling days. That has a direct impact. It's pretty exciting when we can drill a 10,000-foot lateral on a single run with a rotary steerable. That's pretty impressive. And that's a direct -- that directly affects the bottom line. So we're looking at that.

Obviously, when we're talking about a central production facility that we're building in Ward, we minimize the equipment that we'll have on an individual location. So that significantly drops our facility costs on -- for each individual pad or location to nearly 0. So that's -- those are the type of things that we're looking at that are really going to drive our program as far as cost reductions and so forth.

Jon, I think you told me that the 100 mesh brown has got sufficient crush strength if we need or want to use it? We don't use a ton of 100 mesh, but is that -- was that right?

That's correct.

Yes. And then the other piece of this is, we've been doing this for a while in different basins and across the United States and from the beginning of the shale business. We always align ourselves with the top providers of goods and services in every area. They are never the cheapest. We never brag about -- our well costs are not low. So we just don't really -- we focus on them being the right amount of execution and safety and tiptop quality of any component versus returns on capital. And we think returns on capital are best measured with wells that you can replicate day in and day out without a lot of trouble.

Our next question comes from the line of Ron Mills from Johnson Rice.

This might be for Jon, but on the frac capacity, when you talk about having a spot frac crew, have you already been talking about potential timing of that or is there any risk of kind of getting that spot crew to come in and out as needed? Or how do you plan that out based on some sort of normalized DUC level?

Yes, go ahead, Jon.

Yes, so we had a spot crew that -- so we have 2 crews operating right now in the basin. We look at our DUC inventory. We pinpoint areas where it would exceed a normal drilling or frac inventory that we see as appropriate. And we start planning, but planning for that particular period.

But it's really done 6, 9 months ahead of time, where we're talking to a number of frac providers and making -- getting that message out that we'll be looking for some equipment, some resources during a specific time frame and keeping those conversations alive. So that's really how we plan for it.

I could tell you that we're confident. We're seeing some -- we're seeing opportunities that are available at this point. So it's about relationships really and keeping that communication. But it's really, you have to be talking 6 to 9 months ahead of time.

Ron, you didn't ask this, but we don't have a program where we intentionally drill wells that we don't complete. They're just -- we're -- our plan is to complete our wells as soon after we finish drilling them, as is appropriate, given the need to have -- getting ready for the frac and then frac them and have the wireline unit available.

So we don't have a thought process of creating DUCs by any means. We're not in that camp. We operate some naturally just because there's, I don't know, Jon, with 3 rigs, there's probably, what, less than 5 wells probably at all times once we catch up here?

Right. Just to speak where we're currently at, we've got 5 wells that are waiting on completion. However, 2 of those wells are on pads that we're either drilling a second well on or we plan to drill that second well in the near future.

And one question that was asked earlier is, how do you drive costs down or methodologies for that. In those cases, where we have, we're going back to a location where we do have a DUC, we're able to frac 2 wells simultaneously. By doing that, we can incorporate simultaneous operations within the spread. And that's where we're doing our wireline operations while we're fracking the other well so. And that's just another way to drive our costs down and the things that we're looking at now.

Great. And then you had mentioned a couple times, Floyd, other zones. I know Jagged Peak has talked about both the Wolfcamp C and the Woodford. And I know -- I think your inventory is -- you include some As, some Bs and some of the First and Third Bone Springs.

But can you talk about some of the differences across your position in terms of where you think you may have potentially a couple landing zones in either the A or the B? And any preliminary commentary at all on the Wolfcamp C or Woodford that was -- have been recently discussed?

Yes. So look, you need 3D seismic, right, for almost anything that you do out here that's really meaningful. We're having brand-new seismic run on the Hackberry Creek area. We've got new seismic and some newly reinterpreted seismic up on Monument Draw. I said Hackberry Creek, I meant Hackberry Draw.

We clearly have 2 or 3 landing zones in most of these areas in the upper section, which I would say encompasses the -- what everybody calls the A and the B. There's, for sure, it's a thicker zone over in Ward County. So that's clearly could be 3 in the upper. We don't -- we're not counting that way right now.

There's great C opportunities in both areas. We just haven't got there yet. Over at Hackberry, the D, I would call it D. It's a sand. It's a Wolfcamp sand. There's an old development all through there. And it looks like it could really be an interesting play, a fairly inexpensive, high liquid content gas wells that would be a nice adjunct to these horizontal wells in the Upper Wolfcamp.

And then in the Bone, gosh, we're finding that there's no reason in some areas for us to think the Second Bone's any different than the Third other than it's spatially displaced a little bit from -- in terms of vertical. The Woodford and Barnett over in the Ward area, it's a bona fide good project that we're going to move forward on in some fashion in 2018, probably be reconnaissance because running 3 rigs and keeping the balance sheet in shape and all that, we're a little bit constrained, but we own the rights.

And when you come to the office, if you do sometime, Ron, or anybody else, I'll give you a whole presentation on the Bone Springs. I can barely read it. Our fine technology group made the whole presentation on the Bone Springs, both of our areas, and also a great view of what the deep potential is out here. And it's a resource for sure. And it's widespread, both in the Bone and in these deeper zones.

And it's one of those things that a small company running just a few rigs, it's going to take you a while to actually do anything meaningful there. But you know how it is, it's great to talk about stuff, but man, until you drill it, you're just flapping your gums, right?

Our next question comes from the line of Jacob Gomolinski from Morgan Stanley.

I guess similar to some of the most recent questions. But as you look at a $57 prompt price and you think about 2018 plans maybe into a backwardated curve in the second half. You touched on levels you needed for a rig to pay for itself, but curious if you'd consider adding a frac spread contracted one if we roll up the curve and stay in the high $50s or if a 3:1 ratio sort of rig to frac crew is what makes sense -- makes the most sense for you guys right now?

3 rigs, 2 frac -- 2 full-time frac spreads are too many for 3 rigs. I think you need 1.3 frac spreads for 3 rigs. Is that about right, Jon?

Yes, Floyd, that's correct.

Yes. So if we're running more rigs, we'd add a full-time spread, but we're not planning on it right now. We're not going to -- we had this delay earlier, and it cost us 6 or 7 weeks. But we're catching up on that as we speak. So we're not going to have an unusual number of wells that are waiting on frac. Many of them are going to be waiting because we're doing more than 1 well on a pad. So it really wouldn't be -- physically wouldn't help us that much to bring in another full-time fleet right now.

Yes, sorry, I guess I meant maybe more in conjunction with adding like a half a rig or something, but that makes sense.

If we added a half a rig or a rig, we'd be looking at it for sure.

Okay. And then maybe some real quick, 2 quick housekeeping questions. Just want to confirm, I guess, if we were to plan for that $108 million getting spent on that 8,320 acres, that option, would that take net acreage to around 52,000 acres? Or is the reported 43,719 net acres already taking that option into account? Realize it's a bit of a housekeeping question.

That's okay. Quentin, how is that set up in the...

Yes, the 43,000 already includes that acreage.

Okay. And then lastly, just on the cash, the projections on cash flow on that helpful Page 6. Does that include spend on infrastructure as well? Or -- I know that, that's mostly front-loaded and you've done a great job building that out ahead of time. But just wanted to confirm whether or not that was included there as well.

Yes, it does.

And our next question comes from the line of David Beard from Coker & Palmer.

A big-picture question as it relates to your comment on $60 oil. Is there also a time component there where you'd like to see oil trade with a 6 handle for a certain period of time before considering adding a rig?

Since we hedge around the strip, our time frame can be viewed as more than just a spot number. And as you think about the strip, if it's significantly backwardated, it doesn't do us that much good.

So right now, the strip is not -- it's constructive in a way, but it's not -- it's still backwardated even in second half of '18, first half, I believe, and certainly in '19. So we look at the entirety of the period in which we spend the money and the budget and the returns we're trying to at least freeze on that current spend. And yes, you'd want to see it.

My offhand comment -- not offhand, but my comment was mid-$60s pretty much on a flat basis allows a rig out here with pretty high drilling cost and completion cost to carry itself CapEx versus EBITDA. So that would mean you got to have at least a flat strip for a couple years to -- but certainly not a backwardated strip.

But it's just the idea that we're not so fragile that if there was some good reason to add a rig, like a new zone or something, it's not a killer for us, and it's particularly not a killer as we're up in the $60s. That was kind of the main thrust of that. We don't have a plan for that, by the way, right now.

No, no, that makes perfect sense. And just as it relates to the strip and you look out at your longer-term guidance, if the strip is at that $51, $52 and you're rolling into 2020, would you still feel you'd be in a position to add rigs or would you likely -- would you really need higher oil prices to do that?

Well, if you believe the chart that we put out, which we do, of course, we would have the wherewithal to add a rig here and there. I guess it could boil down to, what's your -- what's the smart move? I mean, you can grow significantly with just the rig count that we're proposing.

And if the oil prices are even less constructive than they are today, I don't know that you would want to add a rig, even if you had the capacity to do so. It's hard to predict that sort of a thing. But again, generally speaking, we look at the 5 years of strip, we try to hedge out 2 or 3 of them. And we like to see the 5-year looking constructive. Doesn't have to be contango the whole way, but it needs to be constructive.

And I'm showing no further questions. And I would now like to turn the call back to Floyd Wilson for any closing remarks.

Hey, thanks for dialing in whoever is on the call. Don't have a list or anything. I mentioned a few times I'm loading Quentin up here, but we don't do it too often, but if you feel like getting out there and seeing some awesome work being done out in the field, we'll arrange for that here at some juncture, a couple of short, inexpensive trips, not -- no dancing girls, no giant buses or anything. It'll just be a -- we'll get together in a bunch of pickups, go look at some real stuff that's going on. And I'd encourage you to think about that.

Beyond that, we feel great about where we are. I think we're well grounded in terms of what we can do with just a few rigs and keep the balance sheet strong and perhaps even strengthening. And we're enthusiastic and excited about what we're doing. So thank you, and we'll talk to everybody sometime soon. Bye.

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program and you may now disconnect. Everyone, have a great day.