Battalion Oil Corp (BATL) 2017 Q4 法說會逐字稿

Good day, and welcome to the Halcón Resources Fourth Quarter 2017 Earnings Call. Today's conference is being recorded.

At this time, I would like to turn the conference over to Mr. Mark Mize, EVP, CFO and Treasurer. Please go ahead, sir.

Thank you. 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 fourth quarter and other operational items, and that document has also been posted on our website.

I'll begin the call with comments on our financial performance during the fourth quarter, then I'll turn the call over to Floyd.

Production for the fourth quarter averaged 6,283 barrels of oil equivalent per day comprised of 70% oil. This production rate's consistent with the update we’ve provided a few weeks ago when we announced our West Quito Draw position and related financings. We expect production to grow significantly in the first quarter of 2018, and Floyd will comment on that in a few minutes.

Our realized fourth quarter oil differential of 95% of NYMEX was better than the 91% differential seen in the third quarter, largely driven by our production shift into the Delaware from the Williston. Our fourth quarter natural gas differential came in at 71% of NYMEX, and the NGL differential for the fourth quarter came in at 47%. Looking forward to 2018, we expect differentials to be relatively consistent with those seen in the fourth quarter.

Our per operating unit costs were elevated in the fourth quarter versus prior quarters, primarily because of the divested production associated with our Williston Basin operated asset sale which did close in early September of 2017.

I wanted to quickly highlight a few expense line items that include significant nonrecurring items in the fourth quarter. First, our gathering, transportation and other line item included approximately $1 million in rig stacking charges which will be eliminated in the mid- to latter part of 2018.

Additionally, we incurred about $1 million in contract labor in the fourth quarter in gathering, transportation and other related to operating our water and infrastructure assets. Many of those contract positions have now either been eliminated or absorbed and brought in-house.

We also had approximately $7 million in nonrecurring charges associated with G&A during the fourth quarter. These nonrecurring items included various professional fees associated with some divestiture activity as well as tax service fees, which, by the way, generated significant AMT cash tax savings above and beyond the fees incurred.

And finally, there were some onetime severance costs, relocation costs included as well.

We'll provide formal revised 2018 expense guidance, including the impact of the West Quito Draw acquisition after the deal closes in the second quarter. Having said this, we expect our per unit field operating costs on our existing assets to be in line and within the ranges of the 2018 guidance that we provided in November of '17.

And with respect to D&C CapEx, we incurred right at $94 million during the fourth quarter. This included additional costs associated with running 3 frac crews late in the quarter, in addition to general cost inflation that we had recently experienced.

We also spent another $37 million in the fourth quarter on infrastructure and seismic. These dollars were invested in the infrastructure development in Monument Draw and Hackberry Draw where we've accelerated the development of our water infrastructure and gathering assets.

We expect 2018 D&C CapEx, excluding the impact of the West Quito acquisition and assuming a 3-rig program, to be 10% to 15% higher than the previous guidance range of $280 million to $320 million. That's really driven by service cost inflation.

Regarding acreage deals, we did spend $104 million in the fourth quarter on the acquisition of 4,413 net acres adjacent to our Monument Draw position. And in January, we paid for the exercise of our option on the Monument Draw North acreage, which was $108 million.

As far as hedging goes, we realized a net gain on settled derivative contracts of just under $1 million during the fourth quarter of 2017. For 2018, we currently have 9,510 barrels a day of oil hedged on an average price of $52.65 a barrel. We also have 8,247 barrels per day of oil hedged in 2019 at an average price of $54.41.

On the gas side of the equation, we currently have 7,500 MMBtu a day of gas hedged in 2018 at $3.16. And as usual, we'll continue to watch the markets and layer in 2019 positions as opportunities present themselves.

Finally, as of December 31, 2017, a pro forma for the exercise of our northern Ward County acreage option and our February debt and equity raises, we had $678 million of liquidity, which it consists of $580 million of cash plus a fully undrawn $100 million availability of revolver on the RBL.

Our next borrowing base redetermination is scheduled for May of 2018, and we do expect strong growth in the RBL going forward with each redetermination.

We are currently sitting with very strong current and projected leverage and liquidity position, which will allow us to execute our growth plan for the Delaware Basin over the next several years. We did not have any needs under our current business plan that would require raising outside capital.

And with that, I'll turn the call over to Floyd.

Thanks, Mark. Good morning. Thanks for listening today. We find ourselves at an interesting place today. Our recent wells are beating our type curves. We're approaching 13,000 barrel of oil equivalent per day, up from just over 6,000 barrel of oil equivalent per day average for the fourth quarter. Our very most recent well hit 1,925 barrel of oil equivalent per day this morning. It's still cleaning up, and it's over 85% oil. And our stocks getting [roasted]. So it is an interesting point that we find ourselves at today.

We've announced a couple of recent acquisitions here a couple weeks ago. In Ward County, our West Quito Draw acquisition is set to close in the second quarter. It's in a very active area of the Delaware Basin and we acquired it at a very attractive price. Recent results from offset operators have been excellent in that area, as you may or may not know. We'll take a rig out there after we close, early May maybe. We'll concentrate on 10,000-foot laterals as we do in all of our areas.

We added some land to our Monument Draw area. We called it a tack-on. It was a slam dunk for us. It's adjacent to existing operations and infrastructure. The Wolfcamp is deeper and thicker there. And it offsets our most recently completed well at 5,902 that I mentioned that's approaching 2,000 Boe per day.

At Monument Draw, with this press release, we announced 3 new wells. On the 79 pad, the O2 and O3 wells, these are Wolfcamp wells, our best wells to date, save the brand new one that I mentioned earlier. Those 2 wells IP 24 average 1,817 Boe per day and they're still cleaning up.

These are ahead of our type curve in that area and they look to stay ahead. They're also great 660-foot spacing test. So we're zeroing in on spacing and we're thinking that we're about to the right spot there. This asset's a world-class asset with multi-target zones with higher oil cut, strong IP rates and low declines.

Down in Pecos County at Hackberry Draw, we reported 2 new wells, the Jose Katie Wolfcamp wells. These are some of the best wells we've drilled at Hackberry. Initial IP rates are well above type curve estimates. These 2 wells averaged 1,341 Boe per day on it IP 24 basis.

And as a sidelight, these are new wells. The 20-day rate was 1,071 on average for these 2 wells, 86% oil. Our type curve provides for a 940 Boe per day 30-day rate. So these are comparing very favorably with our type curves. Also great 660-foot spacing test here.

A well we reported on earlier, the Lindsey 1H, we previously reported it at a IP rate of 1,164. After 45 days online, we put it on ESP, and it's up to 1,250 Boe per day and still climbing.

So the takeaways. The 2 areas, capital efficiency is somewhat better in Monument Draw than Hackberry. It's very good at Hackberry as well. Hackberry itself, the IP rates are slightly less than we might have initially thought. The decline rates are also less than we thought, meaning that the wells decline more slowly. High water cuts, particularly in Pecos County at Hackberry Draw, make fluid movement or water management critical to a well's effectiveness. Also makes, of course, the water handling infrastructure is critical to eventual success. Jet pumps and ESPs are needed sooner than some other areas of the basin and certainly sooner than Monument Draw.

As we've mentioned, all of these wells reach a new IP maximum after being put on artificial lift.

In our investor deck on the website that we posted today, we included a comparison of the well performance of over 25 wells in the Hackberry Draw acreage versus a type curve that we posted. And this goes out to 600 days, with the longest history that we have down there. Our wells and those of the existing wells when we acquired the property are right in line with our current Hackberry Draw type curve.

Frac effectiveness continues to improve here as seen by the increased productivity. Our last 3 or 4 wells, we do a lot of diagnostic work as we frac wells with tracer surveys and whatnot, microseismic and everything. So we're quite happy with our results down here, generating strong returns at the strip. We would expect this performance to continue to improve over time and with additional experience. There's also a lot of rig activity from offset operators in Pecos County.

In a general sense, for rigs and how we plan the year, we're going to run 3 rigs in 2018. We may add a fourth rig in the second quarter if oil prices are strong and after we actually own West Quito Draw, which will close early in April. We have shifted our focus slightly more towards Monument Draw just based on capital efficiency. So we'll drill more wells there than we will at Hackberry Draw.

We also plan to drill for half a year at West Quito Draw in 2018, assuming that we bring that fourth rig out. And that should compete favorably or perhaps even better than the capital efficiency at Monument Draw. We have high hopes for that area.

So that's a comment on focus. We've had some, it's not runaway, but it's certainly cost inflation, significant cost inflation recently and over the past year. We've seen this every time there's been a major movement in crude prices for decades. Costs go way down when rigs slow down. They're slow coming up, and then they zoom up and things have to get revised.

We've seen 10% to 15% cost inflation just recently. We'll put out revised guidance in the next few months once we close on West Quito and have a firm handle on our rig count for the year. We're very cognizant of these costs and we're doing everything we can to hold the line there.

The Permian Basin in general and the Delaware Basin specifically, very competitive for services right now, more so than most other basins. So the rig count has zoomed up out there. Personnel and services are scarce. It's just the way a boom play. And it is a boom out there, by the way.

We'll test some new targets across all of our position in 2018. We've already had some Bone Spring tests drilled that we reported on. We'll drill a few more this year. We may tag a couple of deep prospects later in the year. We're doing spacing tests everywhere, and so far it looks like 660-foot with a wine rack or Chevron style zone development like A versus B versus Bone Spring will be an effective spacing arrangement. And we feel pretty good about that. We're seeing that our frac jobs are being contained nicely in the way that we hoped that they would be.

As mentioned on the A&D side of things, we've added some acreage over the past few months. We're up over 60,000 acres. That's been our goal all along. We'll continue to look at small deals, bolt-on as I would call them. They make sense. They're usually less expensive and they fit well with existing operations and infrastructure, don't require any extra personnel. Larger acquisitions are not on our radar screen at this moment.

Our focus over the next several months will be to grow production and EBITDA and continue to refine our drilling and completion techniques. They're very good now. I think we can improve. Reduced drilling days, keep working on our frac jobs, keep working the cost side of our business, get drilling at West Quito and stay well ahead of water and other infrastructure requirements in these areas. It's critical to be able to do that.

So I think with those comments, Katrina, we can take some questions if there are any.

(Operator Instructions) And our first question comes from Asit Sen, Bank of America Merrill Lynch.

I was wondering if I could ask 2 questions. First, on the slightly lower oil cut this quarter, what were the specific drivers? And how should we think about oil cut in 2018?

Well, I can say that all of the new wells are higher oil cut than what we've experienced in the past quarter. We were a little bit low, but I think that's just a mathematical thing that occurred during the quarter. All of our recent wells are cutting well over 80%, some of them over 85%. So I don't think the lower oil cut is anything that we'll see continuing.

Understood, Floyd. And then regarding the comment on addition of a fourth rig, and appreciate the close of West Quito, what do you need to see to say accelerate or defer the timing? In other words, how are you thinking about incremental CapEx in 2018 on that front?

Well, we're looking for that balance where a rig can pay for itself. And that's in the mid-60s, as you know, roughly. We're not there yet. If prices continue to go down, we'll defer that rig; if prices firm up and go up a bit, we'll bring a rig in. We can stay fluid on that decision. Our growth plans as we've outlined, are not tied to additional rigs. Additional rigs would change both the CapEx scenario and our production projections and EBITDA calculations. So it's all dependent on a reasonably good, stable outlook for crude oil which we kind of had over the past month or so, but not the past few days. We'll take our signal from crude prices. If they're bad, we won't bring a rig; if they're good, we will.

So it looks like $60 to $65 is the magic number?

Actually, we'd like to see it better than $60.

Got you. And last one for me, Floyd. What's your current DUC count? And how should we think about the normalized level? And at what point would you consider adding a spot crew?

Current, did you say debt level?

DUC. DUC count.

DUC. DUCs.

Yes.

We caught up -- that's one reason CapEx was a little higher last quarter. We brought in 2 spot crews last quarter. We're caught up. I think we might have 1 or 2 wells that aren't fracked just yet, just by circumstances. We don't really have an inventory of DUCs, and we don't plan to build a big inventory. One frac fleet will almost service 3 rigs. So we require an additional spot crew every periodically for about, I'd say about 1/3 of a year for one crew, if you're running 3 rigs. And we've got those outlined in our plans for during the year if we do build up our inventory of uncompleted wells.

And our next question is Jeffrey Campbell with Tuohy Brothers.

Floyd, on Slide 5, it says that Hawk is more attracted to a buyer significant inventory of high return drilling locations. Is selling Hawk your preferred outcome at this time? Or how does that fit into your positioning of the company?

Well, look, Jeff, we never wavered over 5, 4 public companies and several private companies over the years. I think as you grow a large inventory of future value that you can't access, the assets are best served and the investors are best served by trying to trade those assets into a larger capital structure with perhaps cheaper cost of capital. So we're not at that juncture right now. I have to suggest that I didn't pay attention to that box on Slide 5, which I'm looking at. In general, in our business, the high inventory of high return drilling locations is attractive to a company whether you're operating the company or selling it. And so that's our goal is to continue to build that well-defined, well-delineated inventory of quality locations that don't have geologic risk, don't have execution risk, and that's what we're about. We're not at the point of talking about selling the company today, by any means.

Okay. Well, and your track record speaks for itself. So that's one of the reasons that it was interesting to ask. And speaking of inventory, on Slide 6, you note a 3 zone base case for the Monument Draw tack-on, but you only show a 2 zone base case for the Monument Draw East. I was just wondering which zone is it that's not being included in Monument Draw East base case?

We have a different approach to these things, Jeff. Or we have our own approach, let me say. We don't count zones unless we're 100% confident that they're there and they're prevalent across the entire acreage area that we're counting them. So we don't have a test in another zone up on the north side of that acreage yet. We will. And so what we've got up there, we've got 1 Wolfcamp zone and 1 Bone Spring and we have 2 Wolfcamp and 1 Bone. Down to the south, I'll have to tell you that recent work is telling us to the south we probably have 3 Wolfcamp landing zones and perhaps 2 Bone Springs. But we don't -- listen, all those zones as you count them, they're so far in the future that the PV of those is not so much. So it's our job to delineate those on both a reasonable engineering basis and on a spacing basis that makes some sense where you're not wasting a lot of money getting the same reserve. So we're somewhat conservative in the way we count those zones. I would suspect that the western part of all the north acreage will have more landing zones than what we've specified, and the eastern part will have the 2. But we just haven't drilled enough. I think we've only drilled maybe 10 or 12 wells at Monument Draw so far, maybe 13 or something, with half of them being online now. So it's early days. It's a lot of zones, though. Think about 3 zones, 660 spacing, that's 24 wells. I mean, gosh, that's more than 1 rig's out -- that's almost 2 rigs' output for a whole year right on one 10,000-foot spacing unit. So it's a lot of places to drill for sure.

Yes, there's no question about that. Let me ask one final question. On Slide 16, looking at the EUR it seems to suggest that the West Quito Draw is considerably gassier than your other acreage. I was just wondering if you have any concerns about getting that gas to market over the next 1 year or 2 because we know that the southern Delaware Basin, that gas production is going to increase considerably over that time.

So just as a companion piece to that, look on Slide 19. And our point being made there is that all of these areas make a significant amount of oil, including West Quito. And we're probably conservative there. This chart was drawn based on our acquisition economics rather than any historical economics. The other charts are drawn on some limited history, but good histories. So the point being that over at West Quito, we'll make a lot of oil, over 1 million barrels per well of just oil, crude oil, maybe 1.25 million. But the gas is a higher gas cut over there. It's maybe only half oil, higher liquids. But absolutely yes, in the future we expect there to be issues with gas. The good news is there's an arrangement at West Quito already for the gas takeaway and it's significant. It's got a lot of horsepower behind it. So this entire part of the Permian Basin is going to be challenged with gas takeaway over time. Like all of our infrastructure concerns, we try to tackle those things quite early. And not just gas, by the way; crude takeaway, Waha differentials, all these things. We're looking at these all the time. So we think we're good on gas for the moment. We've got long-term arrangements in all 3 areas now so that we think we’ll be ahead of the game somewhat. But it's a powder keg out here in terms of rig count and new wells coming on. It's just growing almost exponentially last year and this next year. We're also doing some hedging out here to protect the basis. We're hedging the Waha differential so as to protect that price. But that doesn't really address the actual takeaway, and the physical takeaway is a concern, I think, for the entire industry.

(Operator Instructions) And we'll take our next question from Jason Wangler with Imperial Capital.

You've touched on it a bit, Floyd, but was just curious with the 3 rig program and it sounds like you're going to focus mostly in Monument Draw, will that basically keep that completion crew busy there? Or will you be able to just kind of move that one out to Hackberry or even West Quito as you see fit and just be able to use the one crew throughout the year?

There's a map early in this, and you can see that these are not very distant from each other. So once you move off of a pad, it doesn't matter that much if you're moving 1 mile or 20. So the dedicated frac fleet is quite mobile around all 3 areas. So as I mentioned earlier, it'll service wells that we have drilled in any of these areas, and then we'll bring on a spot crew as necessary throughout the year. I don't think we're planning on needing one before the third quarter and maybe only 1 this year. But it could also be in any of these areas. We'll have fewer wells put online than we anticipated last year in Hackberry. So you'd expect to see the frac fleet down there a little less and a little more at Monument Draw. And then West Quito, not starting drilling -- so whether we add a rig or not, we'll start drilling at West Quito this year. So you'd expect to see a frac fleet out there July, something like that, once we get started drilling maybe perhaps in May.

Okay. And just as a follow-up, on Hackberry Draw, it did seem like the recent wells that you kind of gave us were looking better than the original wells that you gave only about a month ago. Was there anything you guys did differently or were able to refine that specifically, that helped that? Or is it just simply that we're just getting some more data from the formation?

Listen, a lot of it's just more data. Kind of like the way we count locations, our type curves are not meant to be promotional in nature; they're meant to be factual. They're not drawn by some financial guys. They're drawn by engineers and they're based on history. So you would expect as in every basin in the entire shale world, which is basically the United States for the most part right now, you would expect results to continue to improve. Sometimes it's just such a small matter of pump rates or proppant size or, you know. And we're constantly reviewing all of our history on every single aspect of how we complete these wells and how we target them. So we would expect to improve upon this year's wells. We would expect in general to be better than last year's wells. And frankly, I probably expect 2019 wells to be better than 2018 wells.

And our next question is from Philip Stuart with Scotia Howard Weil.

I wondered if we could circle back on the expense side. That seems to be causing some investor concern this morning from people that I have talked to. Just wondering if you could kind of maybe go into more detail on perhaps some one-time things that happened in 4Q '17 that caused gathering and transportation and possibly LOE to be a little bit higher than expectations. And just kind of trying to give people comfort in being able to be within the guided expense range throughout 2018?

I'll let Mark give you an answer to that. I will say that some of our activity in the fourth quarter of last year was driven by bringing in a spot frac fleet. But listen. Costs are higher than they were. They increased a lot during that quarter, and it's unfortunate but it just did. In terms of comfort, I would like to suggest that we'll drill the best well at a reasonable cost structure as anybody in the business will and that our returns will be acceptable. Mark, do you have any details on all this?

Yes. I mean, it really is pretty simple. And I'll just take each one of the items, the 2 that you mentioned and I'll just touch on G&A again as well. So gathering, transportation and other, the kind of inflation that we had in Q4 really was just driven by contract labor. Some of the work that we were having done out there was being performed by third parties that we brought in. And we have now gotten organized out there to where most of that has been eliminated at this point and a lot of those duties just absorbed in-house. So as Floyd just mentioned, as I had mentioned in the opening comments, we absolutely do expect to be within the ranges that we gave for guidance for 2018. On LOE, that really is at an operating per-barrel basis that really is driven by the production that was divested of. And again, 2018, we expect to be right in line, right down the fairway of where we projected. And then G&A probably had the largest number of nonrecurring-type activity that did range from a fee paid for the non-upsell of the Bakken to some tax services that were rendered to relocation fees and just things of that nature that will not be ongoing into 2018.

Okay. I really appreciate the color there. I think that kind of answers my question. And just curious if you could give us an idea of how that will trend, I guess on the expense side. Will it be kind of towards the higher end of the guidance range during the beginning of 2018 in general and then trend lower throughout the year? Or will it be kind of even within the guidance range kind of across the different line items?

G&A, we've really made some very significant adjustments as is evidenced here just by what you're seeing flow through with some of the severance payments and things of that nature. G&A is going to be kind of in a $45 million type range and kind of right down the fairway through 2018. Gathering, transportation and other, again, should be in the range, but we'll probably trend toward the higher end of that range. And LOE should just be, as production continues to ramp dramatically, you're going to see it actually coming down as we go through Q4 of 2018.

And our next question is from Mike Kelly with Seaport Global.

Mark, I've got a couple questions for you. You mentioned in your prepared remarks a CapEx adjustment for '18. I was hoping you could repeat that and maybe give a little more color on some of the things that play there. Especially interested if you could give us a sense of what CapEx could look like if you do go to a 4-rig program. And then finally, you mentioned that leverage metrics will stay strong as you move throughout 2018. Was hoping you might be able to give us what you're modeling for kind of year-end net debt to EBITDA for '18. Thanks.

Okay. As far as CapEx, the comment that I had made is we had previously put out guidance of $280 million to $320 million. And I just made the comment that you can probably expect about a 10% to 15% higher. And that's based on the 3-rig program and that really is just driven by service cost inflation. As far as leverage, we don't really put exact amounts out there. I will tell you, though, from a trend perspective, it will continue to walk down as we go through 2018, and it will be at a very, I mean a very attractive level well below 3x, well below 3x by the time we get to the end of the year.

Okay. Good to hear. Infrastructure spend, what should we -- I think previous guidance was like 30% to 40% -- or not percent -- million. Is that still a decent number or seems like that might tick higher too?

Yes, we're kind of talking internally 35 to 45.

Okay, good. Thanks. And if I switch over operationally, this well you guys drilled in eastern Monument Draw looks real, real encouraging. And just wanted to get a sense, Floyd, how much of a read we could take from this well to the rest of that eastern option acreage. I know this is kind of the western portion of the play. But you think this tells you everything's good here? Or is there more work to do?

Well, what it does, it tells us that there's some great rock to be accessed up towards the platform. And while thinner, it's high quality. What it really does though, it 100% proves everything up to the west and south. So there's no question of anything over there. So we're still going to have to feel our way eastwards if we choose to. But it's -- look, a pilot well, you don't see as many of them as our industry probably should be drilling, and that's another thing that runs our cost up a little bit. I think we've drilled 3 pilot wells in 2017, maybe 4, but at least 3. And to do a good job with that, you drill them deep and you log everything. And half the time you don't even whip-stock that. You might save that for a disposal well or a supply well or a future deep test, and you just move over and drill a new well after that. And that runs the cost up. What this really does, it highlights that all of the acreage from at least a little bit east of this to all the way west of ours, is really in great shape. And again, the idea of the way that Steve was able to craft the options out here in eastern Ward County have been spectacular and a real thoughtful way for us to approach getting into a new area of the field. So we're ecstatic over results here, not just there by the way. We reported that section 79 pad, the O2 and O3 wells that I think over 1,800 BOPD IPs, and even after 20 or 30 days are quite strong still. So geologically and execution-wise, things are looking wonderful. It's a great asset.

Great. Appreciate that. Just a quick follow-up on that. I mean, do you see the geologic attributes changing much from that well you just put online? As you move further east toward the platform, is there a big delta between far east and far west? Thanks.

Yes. Yes, there certainly is. It clearly thins as you go east. It doesn't disappear. But the more east you go, you get more of these intrusions of carbonates, carbonate flows as we might call them. And those are not good territory for frac jobs. So you have to sort of feel your way as you know you're approaching basically a drilling hazard, not a fault, but a formation hazard that would say this is not a good frac environment. So yes, it definitely thins and it gets less, less clean shale as you go eastward. Now where that cutoff of that is, we don't have that exactly. But as I say, it's just as important for us and the results of this pilot well, they've totally cemented in our minds everything west. And our entire south area that we just added this past quarter, we had quite a few sections over there. So as you go look at the platform, it kind of meanders its way eastward as you're going south, so making that good area for production plateau a little bit to the east as you go south. So it really helps us as we're thinking about how many locations we have to drill and so on. And by the way, you didn't ask this. But when you get a more -- a thinner zone, it's a great, almost an engineering thing to consider that if you get a really wonderful completion in a zone that's only a couple hundred feet thick, you find out that you're doing a better job of assessing the crude near to your wellbore to your frac job, which means higher recovery. So we would expect to get a much higher recovery under primary producing conditions from this zone than we might get in a zone that's much thicker. So it gives us a lot of information in all different areas and it's pretty exciting.

(Operator Instructions) And we'll take our next question from Ron Mills with Johnson Rice and Company.

Floyd, just two clarifications from earlier questions. When you talked about the $65 oil price to self-fund a rig, what is the anticipated time frame to have that oil price self-funded rig be given the lag time between starting the program and getting the production?

Okay, Ron. That's kind of half-ass thing that I like to say. If the strip held and if cost held in the mid-60s, a rig would take care of itself in a 12-month period. In other words, your EBITDA would be nearly equivalent to your CapEx that that rig would engender, which would be $130 million, $140 million in a year's time or maybe a little bit less, we hope. So that's just sort of a -- it's a directional thing. So if prices are trending better, it's costing you less and less to add a rig than it does if prices are trending lower, meaning that while your CapEx spend goes up, you're getting a nice boost in EBITDA; whereas the other direction, if you just add rigs and prices are falling, crude prices are falling, you're working the wrong side of that equation. So my comment on that line was more directional in nature. And we're not there, by the way, and costs are not flat. Costs are not at all flat.

Given where we are in oil prices when you think about West Quito and drilling there, if oil prices stayed closer to these levels, would one of the options be to take one of your current 3 rigs, drill some at West Quito and take it back rather than adding a fourth rig?

That's absolutely what we would do. And again, it's the same as frac fleets. If you move off a pad, it doesn't matter if you're moving 1 mile or 20, right, on a rig. I mean, it matters a bit. But if you get off the pad where you're not walking the rig or dragging it, you're -- we absolutely would and probably will put one of the existing rigs over on West Quito. If we had a rig, it makes it an easier thing to separate; but if we don't, we'll just divide our rigs. And again, they'll be heavily weighted towards Monument Draw, and we'll get our first few operated wells under our belt at West Quito to make sure that our expectations are met. Those expectations are to make over 1 million barrels of crude with the well over there, along with quite a bit of gas and natural gas liquids. So I mean, the numbers are there. All the offset operators have done that sort of thing. We like to prove it to ourselves first. But yes, option would totally be to rotate around our acreage with just the 3 rigs that we currently have, if prices are not cooperative. If prices are dropping, we won't add a rig.

Got it. And then to follow up on Mike's prior question on the eastern option acreage. The well, the 5903 well was drilled, it looks like more on the western edge of that section. But given that option acreage is only extending 1 mile to the east, do you have any incremental color on just that 1 mile to the east of additions? Or are you talking more about a greater risk as you move even further east in that east option acreage?

Well, unfortunately, our business, as you get around the edge of a shale field, you begin to have geologic risk. And we try to set ourselves up where the geologic risk is minimal. There's more than 1 section involved, as you know, from if you look at the maps. Yes, there's significantly more risk the further east that you go. And if you get down to the office sometime, I'd like to show you the shuttle log on that well. I think we've got it in the presentation, or we did. But if we stretch it out for you, you can really see. It's really strange, you can see that the zone gets thinner and there's a little more indication of carbonate flow. But it's an awesome well. So that means the frac job was really contained extremely well, as you try to get all frac jobs contained. So we don't have to -- that thing is exercisable up until the 31st of May. We'll make our -- March, I mean. We'll make our determination as time goes. But it's a great well.

Okay. And can you just, on the water infrastructure side, you made it a point and it was evidenced during the field trip of the infrastructure spending particularly on the water side, but also just all the infrastructure at Monument Draw. Is there something similar planned for West Quito? Or were some of those systems already in place, given Shell's footprint there?

I think Jon's on the line. Jon, you've been out there personally. I haven't been there yet. But why don't you make a few comments about your plans for infrastructure and takeaway at West Quito?

Sure. Thanks, Floyd. Ron, for the Shell acreage position, we'll be installing our own water system. So similar to what you saw on the field trip, our standard recycling facilities, SWDs, will have main trunk lines for water handling for both produced water and recycling water. We'll be laying in our own power grid. So we'll provide our own access to Tex New Mexico Oncor. But we'll be laying in our own power across the acreage position. We'll make some determinations as we move forward on the oil side. The gas is dedicated, and gas is sold at the lease site. So we won't be handling gas in any type of central production facility or [will be required] to gather our own gas. That's it.

Okay, great. And maybe, Jon, since you're son, can you provide any incremental comments on the slide showing the type curve at Hackberry Draw in terms of your wells versus the 25 legacy wells and that relatively stronger performance given a change in artificial lift design, just to provide a little bit more support for that newer type curve?

That's Slide 18, Jon, if you don't have it up.

I've got it here, Floyd. Yes, so the legacy wells, about 20 Wolfcamp A-type wells, with over 600 days of production gives us a pretty good handle on this type curve matching the production performance. With regards to our HK drilled and completed wells, which are showing up to 200 days at this point, we're performing above the type curve overall. A lot of the more recent wells further support this. Our focus there is optimization of artificial lift. This is really the blocking and tackling piece. And this is where we were able to make big inroads in the PDP base for those legacy wells this past year, where we're able to increase that production on those PDP wells by range of 60%. And the EURs on those individual wells up to 40% on average. So a lot of work going on there. We've had a lot of success with ESPs. We'll be running jet pumps this year. We've got experience that we bring from the Bakken with that type of lift technique. So, yes, a lot of good things are happening in Hackberry Draw. I think that the Slide 18 really supports our type curve and the decline rates that you see there through 600 days.

And our next question is from John White with Roth Capital.

I believe you mentioned very briefly the possibility of a deeper test maybe later in the year. I think you've talked about this before, and, as I recall, it's a conventional reservoir. If that's what you're talking about, can you give us the basics of that again?

John, there's 2 distinct deep plays on our acreage in our analysis. At Hackberry, it's a deeper Wolfcamp zone that's a conventional. It's a sand. We've done a lot of work on this and it's pretty exciting. It's a pretty gassy zone, but very prolific with quite a bit of crude oil, we think. It's been drilled historically with vertical wells. We think that you could drill a horizontal well in it and perhaps do quite well. It's kind of a channel system of Wolfcamp sands down at about maybe only another 1,000 or 1,500 feet deeper than where we are. So we're going to drill at least a pilot well down through there. And if we find what we think we find, we go ahead and complete it there, full well knowing that we could use that wellbore for something else. Now that is a conventional reservoir, and we're very interested in that because it would just add a new play, another play to much of that acreage. Over at Monument, it's a different cat. It's a Woodford shale. And it has been drilled in the past and drilled through and it's been drilled vertically. And in fact, recently, one of our good peer companies has drilled a short lateral Woodford well in that area with a very strong IP, I think over a couple thousand Boe per day. So that's a different kind of thing. And again it's not that deep. It's only another 1,500 or so feet deeper than where we're going to be anyway. So we'll intend to test that idea sometime this year with a well, call it a pilot. And if we like what we see, we'll complete down there. And if we don't, we'll use the wellbore for our Wolfcamp well. We'll stock it up in either the A or the B area or maybe even Bone Spring, and complete it up there. I wouldn't put anything in a model about all that. But it's our business to make sure that we gauge all the possibilities at all depths in acreage that we own, and we'll do that.

Sounds exciting. And thanks for taking my question. And thanks again for the hospitality out in Fort Stockton last month; enjoyed it.

You're welcome. Operator, I think that's all the question and time that we have. If anybody on the line thinks of something that we didn't cover, just give us a call. And thank you.

And this concludes today's call. Thank you for your participation. You may now disconnect.