HighPoint Resources Corp
Q2 2016 Earnings Call Transcript

Published: 5 Aug 2016

[Operator:]

Good day, ladies and gentlemen, and welcome to the Bill Barrett Corporation second quarter 2016 earnings conference call. At this time, all participants are in a listen only mode. Later we will conduct a question and answer session, and instructions follow at that time. As a reminder, this is conference call is recorded. I would now like to turn the conference call over to Larry Busnardo, Senior Director, Investor Relations. Please go ahead.

[Larry Busnardo:]

Good morning. And thank you for joining us today for the Bill Barrett Corporation second quarter 2016 earnings conference call. Joining me today are Scot Woodall, Chief Executive Officer, and Bill Crawford, Senior Vice President, Treasury and Finance. Before we begin, I encourage everyone to read the disclosure statement provided within the forward-looking statements our earnings release posted to the home page of our website at billbarrettcorp.com. You can find and review these disclosures as they are referenced in our filings with the SEC or in our 10-Q, which we filed yesterday afternoon. You can also find these documents on our website or at SEC.gov. With that, I'll turn the call over to Scot.

[R. Scot Woodall:]

Good morning, and thank you for joining us today to discuss our second quarter 2016 results. We are executing on a focused strategy and on the items within our control. This approach has served us well and has translated into a very good second quarter for the company, leading to sequential growth in discretionary cash flow of 34% and EBITDAX of 20% over the first quarter of 2016. In addition, we are raising the low end of our production guidance range while also reducing our capital spending for the second time this year. So a great combination. I would also highlight that the 2016 capital spending guidance is now projected to be 30% lower than our initial guidance at the midpoint. The second quarter was highlighted by production exceeding our guidance range by 14%, representing 18% sequential growth compared to the first quarter. This also marked the sixth quarter in a row that we have met or exceeded our production guidance. So a great job executed by our operations team. We maintained positive momentum with respect to cost control as a result of increased operating efficiencies as LOE, G&A, and DJ Basin oil differentials were all better than the first quarter, leading to the sequential improvement in discretionary cash flow and EBITDAX. Capital expenditures were significantly below our guidance range as a result of well costs being executed below forecast levels and the timing of capital spending related to infrastructure and other non-drilling related capital. This allows us to reduce our capital expenditure outlook for the second time this year and, as I noted earlier, represents a 30% reduction from our initial guidance. More importantly, we were cash flow positive in the second quarter, and based on our current internal projections and pricing scenarios, we are positioned to be cash flow positive the entire year. Bill will discuss in detail the positive revisions that we are making to our production, capital expenditure, and cost guidance for 2016. Financially we remain in a solid position with a strong balance sheet. We exited the second quarter with over $100 million of cash pro forma for the Utah Basin non-core property sale that was completed for cash proceeds of $30 million, a very valuable hedge position with approximately 65% to 70% of our remaining 2016 oil volumes hedged at approximately $73 a barrel, and an undrawn $335 million credit facility. I will now turn things to the operations front. During the second quarter, we placed two drilling spacing units on flowback consisting of 24 wells. 23 of these wells are extended-reach laterals. Both of these drilling spacing units are in the central southern acreage position. As outlined previously, this activity completes our current drilling and completion program, and there are no uncompleted wells remaining in our inventory. Execution and well optimization continue to be a top priority for the company. To date we have implemented targeted development of the Niobrara horizon throughout our acreage position. The primary focus of development has been on the Niobrara B across a broad section of the acreage position, while development of the Niobrara C has primarily been focused on the central portion of the acreage. In addition, we have also drilled our initial wells to the Niobrara A and the Niobrara C on the northern acreage position. Over the last two years, we have drilled and completed 75 extended-reach lateral wells. We have utilized a variety of well construction designs, including sliding sleeves, plug and perf, varying number of completion intervals, varying number of proppant sand volumes and flowback techniques. Our base design has evolved to a 55-stage plug and perf, 1,000 pounds of proppant per foot, lateral design. This has resulted in a base type curve that continues to be validated with now having over 20 months of production history on that collection of wells. At our current cost structure, these wells generate attractive rates of return at current strip pricing. In an attempt to maximize economic value of each drilling spacing unit, we have tested also several different spacing configurations. While these wells are still in various stages of initial production, we can at least observe a few trends. It appears that the tighter spaced wells have a lower initial peak production rate but shallower production declines. Additional production data will be needed to determine the optimum development plan and completion technique. We will continue to provide updates as we strive to maximize each value from each drilling spacing unit. As we look ahead to the remainder of the year, we are monitoring industry conditions to determine the appropriate time to resume our development drilling program in the second half of this year, as we remain optimistic on the outlook for crude oil for the remainder of 2016 and into 2017, based on improving supply/demand fundamentals. In summary, we are pleased with our second quarter execution. Generating positive cash flow in the current commodity price environment reinforces the strength of our assets and of our team. Also, we are positioned well for the future, with a meaningful cash position and ample liquidity that puts us in a good financial position. With that, I'll turn the call over to Bill to discuss more in detail our financial results.

[William M. Crawford:]

Thank you, and good morning. As Scot noted, we reported strong results for the second quarter that included production, earnings, cash flow, and EBITDAX all coming in better than consensus estimates. Our execution on cost control measures with respect to CapEx, LOE, and G&A also contributed to our outperformance. During the quarter we made strides with respect to improving our balance sheet. This was accomplished through a combination of higher cash flow and lower costs, but more importantly the debt exchange that reduced net debt by 12% and the mid-July closing of our Uinta Basin non-core asset sale. Overall a great job by our team of controlling the items within our control. I will now spend a few moments going over our financial highlights and key achievements for the second quarter. Quarterly production volumes totaled just over 1.6 million barrels of oil equivalent. This was 18% greater than our first quarter and exceeded our guidance of 1.4 MMBOE by 14%. Oil volumes increased 15% sequentially and exceeded consensus estimates by 9%. Second quarter production benefited from the start-up of the 16-well DSU in Section 5-62-22 that continues to ramp up to a peak initial rate. For the third quarter, an eight-well DSU initiated production in early June and will contribute to production as it ramps up. We are forecasting third quarter volumes will approximate 1.5 to 1.6 MMBOE. Our guidance reflects the loss of production associated with the sale of the Uinta Basin assets that closed in July. This amounts to approximately 100,000 barrels of oil equivalent for the second half of the year. Despite the sale, we are raising the floor of our guidance range to 5.9 to 6.2 MMBOE for 2016. Companywide oil price differentials before hedging averaged $5.66 per barrel less than WTI. DJ Basin differentials continue to tighten as infrastructure expands. For the second quarter, the DJ Basin oil price differential averaged $4.82 per barrel less than WTI, which was a 14% sequential improvement over the first quarter. Going forward, we expect our operated DJ oil differentials to average in a range of $3 to $5 per barrel off WTI. As a reminder, we do not have any volumetric delivery commitments and are realizing tighter pricing with the excess takeaway capacity in the basin. We continue to execute on our cost initiatives, primarily as a result of our increased operating efficiencies and service cost reductions. LOE averaged $5.28 per BOE in the second quarter, compared to $6.46 in the first. DJ Basin LOE averaged $3.74 per BOE compared to $4.80 per BOE in the first quarter. We are lowering our 2016 LOE guidance to $31 million to $34 million to reflect the cost reductions achieved so far and the sale of the higher-cost LOE properties from the Uinta Basin. Second quarter cash G&A totaled approximately $7 million, a $1.5 million reduction from the first quarter. We are lowering our 2016 G&A guidance to $30 million to $33 million to reflect the cost savings we have achieved to date. All of this resulted in discretionary cash flow of $33 million, a sequential increase of 34%. Year to date, we have generated $57 million in cash flow. In addition, in the second quarter we generated EBITDAX of $47 million, or a sequential increase of 20%. Second quarter CapEx totaled $16 million, which was significantly below our guidance range of $30 million to $35 million. This was primarily a result of lower XRL well costs, the timing of infrastructure-related spending, and other non-drilling related capital. As a result of the cost savings achieved to date and the expected level of spending for the remainder of the year, we are lowering our 2016 CapEx guidance to $75 million to $100 million. This represents a 30% decrease from the midpoint (11

[Operator:]

Our first question comes from Jason Wangler with Wunderlich. Your line is open.

[Jason A. Wangler:]

Hey, good morning, guys. Was just curious – you mentioned on the guidance for CapEx, the low end not bringing drilling rig back. I assume that incremental $25 million or so would just basically be bringing a rig back and the completions would happen next year. Is that fair to say?

[R. Scot Woodall:]

It's probably – a few completions would trickle into December is kind of the way we're looking at it. And so it's kind of – depending on the timing, if we started sooner rather than later, you might get some things completed this year. If you start closer to the beginning of the fourth quarter, they'll probably trickle over into the first quarter of next year. So kind of on the fence there a little bit. That's kind of why the little bit wider range there, Jason.

[Jason A. Wangler:]

No, that's fair. And looking at the DSUs you brought online recently, you had a nine, 15, eight, different pads. As you start looking forward to completion, it sounds like you're starting to kind of zone in on something pretty uniform. Have you started to think about how you want to develop these pads? Or is that something that's still kind of to be understood, depending on how many zones you target? I guess I'm just asking on the spacing side as we start to think about when we bring a rig back, the types of pads we'll be drilling in terms of how many wells for timing and those type of things.

[R. Scot Woodall:]

Sure, Jason. I think directionally we probably kind of know what we think we'd do. I think we're kind of zeroing in on something that's more in that 50- to 60-acre type of a spacing, something that's probably 1,000-plus pounds of sand. The 1,200 pounds of sand per lateral foot seem like they're outperforming the 1,000 pounds per foot, so I think we'd be kind of leaning that direction. Clearly staying with the plug and perf, and I think clearly staying with the controlled flowback is kind of the way I think that we would reinitiate our drilling program.

[Jason A. Wangler:]

Great. Thank you. I'll turn it back, Scot.

[R. Scot Woodall:]

Sure.

[Operator:]

Thank you. Our next question comes from Brian Corales with Howard Weil. Your line is open.

[Brian M. Corales:]

Yeah, just to follow on that question, what is that cost of – we'll call it that uniform well with the higher sand content?

[R. Scot Woodall:]

Yeah, we're thinking, Brian, that it's probably something about $4.25 million.

[Brian M. Corales:]

Okay.

[R. Scot Woodall:]

And we haven't gone out and gotten new service costs, but when we look at the last eight wells we did, they were in that $4 million range for that basic type of design. And so that led to the big underspend that you saw in the second quarter. So we had budgeted those wells for the $4.75 million and actually spent like $4 million. So you had a pretty good savings on everything that we've done year to date. So I think if oil stays in this type of an environment of $40 to $50, I think we think that that pricing should hold pretty firm.

[Brian M. Corales:]

Okay. And then it looks like 4Q you could have a decline without any activity. I mean, what do you need to see? I mean, obviously, it's partly commodity priced, but what are you – I mean, just, I know it's early in 2017. Could we think that you're probably putting a rig back in 4Q if oil prices strengthen a little bit?

[R. Scot Woodall:]

You know, that's probably a reasonable assumption, Brian. I think we're still talking about it. You know, obviously we want to grow EBITDAX. And to grow EBITDAX probably means that you have to drill new wells. And so at some point, we need to probably make that decision and go back to work. I mean, the economics of the wells, even in these commodity price environments, at that capital cost structure, and the EURs that we're seeing, look favorable. So at some point we need to make that decision and do that. I think we're just kind of looking for a little more certainty. If you recall last year, in 2015, we put the rig back to work in May or June, and then we kind of had the same signature as we're having right now where commodity prices went away from us. And then we laid one of the rigs back down in like the September/October timeframe. So we're just probably looking for a little bit more stability and a little bit more certainty. And then we'll go out and start contracting some services, I think.

[Brian M. Corales:]

And one more, if I can. If you're going to run a one-rig program just for a year, drilling and completing, is that roughly about $150 million?

[R. Scot Woodall:]

It's probably something much less than that. I mean, we're probably something in – well, your math may be (19

[Brian M. Corales:]

Okay. Thank you.

[Operator:]

Thank you. Our next question comes from Steve Berman with Canaccord. Your line is open.

[Stephen F. Berman:]

Thanks. Good morning. Scot, with just a few days left to the deadline to get the signatures on these initiatives in Colorado, I was just wondering if you could share any thoughts you have on that whole situation with us. And is waiting on that maybe part of deciding whether to – or when to bring the rig back?

[R. Scot Woodall:]

No, I don't think that necessarily has a decision in whether or not we bring the rig back or not. We have permits secured, and I think we're in a position to where we could resume activity kind of independent of what may happen associated with the ballot initiatives. Turning to those, the ballot initiatives, and obviously the two key ones are what's known as number 75 and number 78. You know, the intel that we kind of have is that the required number of signatures, which is about 98,000, the proponents of that must be somewhat close, I guess, in achieving that 98,000 signatures. They're due by 3 o'clock on Monday. There's probably a range of maybe they're just a little short of that number or a little bit over that number. And then I think someone has written a pretty good article recently that says if they're over the 98,000 signatures, then that does go to the Secretary of State to validate the signatures. I think most people would think that there's something around a 40% failure rate on the number of signatures. So I think people would think that you need like 160,000-ish signatures to get like 98,000 valid signatures. So depending on what happens on Monday, clearly if they're under the 98,000, they're not on the ballot. It could be that you end up in a gray area where they're over the 98,000 and you have to go through like a two-week validation process. And we may not know the final results for that for a couple of more weeks. I would say that clearly I think our industry is very well-organized and very well-funded to launch a campaign to oppose these measures, and if they did find their way on the ballot, which I think is definitely in jeopardy, I think we would be able to soundly raise a campaign of educating the voters, and I think you've got a lot of business support outside of our industry that think these two measures are something that's bad for Colorado, and I think that the likelihood that they would pass is pretty remote.

[Stephen F. Berman:]

That was very helpful. Thanks. That's all I had.

[Operator:]

Thank you. Our next question comes from Neal Dingmann with SunTrust. Your line is open.

[Neal D. Dingmann:]

Morning, Scot, Bill. Say, Scot, I just want to make sure I have this right on – you guys placed the, on the press release, showing the 24 wells on initial flowback. I'm just trying to get a sense – that to me, one, seemed certainly more than I think you guys maybe were initially thinking for the quarter. How do you see the schedule? I don't know if I have that correct, sort of for the rest of the year for those placed into flowback, as well as into 2017. Kind of for the next couple quarters.

[R. Scot Woodall:]

Yeah, no, I think that's kind of on track. Maybe the last eight wells were a little bit early in the quarter, but I think we were thinking that all of those wells would come on in the second quarter and just start the flowback operation. And then remembering that it takes several months to cut hydrocarbons and get up to the peak volume. So that's the last of the planned activity for the low end of our capital guidance. So we have no ducks out there right now. So I think that's kind of according to our schedule, at least on a quarterly basis.

[Neal D. Dingmann:]

Okay, okay. Pretty (23

[R. Scot Woodall:]

Yeah, I think we're pretty clearly sold on the plug and perf and pretty zeroed in on about that 55 stages. We have done a handful of wells at 82 stages, but they're real early in the flowback. So it's probably early to draw some conclusions there. But I think that base design of 55 stages and plug and perf will hold true as we resume activity, or when we resume activity.

[Neal D. Dingmann:]

Very good. Thank you.

[Operator:]

Thank you. Our next question comes from Derrick Whitfield with GMP Securities. Your line is open.

[Derrick Whitfield:]

Yeah, good morning, guys. Great quarter.

[R. Scot Woodall:]

Thank you.

[Derrick Whitfield:]

Just to build on Neal's point there and maybe just to dig a little deeper, if I could. Looking at Section 5-62-22, is there any color that you guys can offer on the production build for the four wells that tested the tighter frac design?

[R. Scot Woodall:]

Yeah, it's probably too early to speak specifically to those four wells right now.

[Derrick Whitfield:]

Okay. And then just moving over to the Section 4-62-9, I've heard you guys say in the past that you're targeting a new landing zone within the C, and that's more to the south. Any color you can provide regarding what you're seeing in the logs or seismic regarding this new landing zone?

[R. Scot Woodall:]

Sure. So each of these Niobrara formations have an A chalk and they have something that's called an A marl zone underneath it, and then you have a B chalk and you have a B marl and then you have the C chalk and then you have a C marl. And what contributes in that when you think about how you calculate original oil in place or calculate pay, is it just the chalk or is it the marl contributes as well. And I think our technical team thinks that marl contributes as well. And so what we did in the particular section that you're referring to, is instead of landing the lateral in the chalk, we actually landed in the marl formation in one of the wells. What that would do is just open up more H is really kind of what you're trying to accomplish by doing that. So that was something that – I guess that's probably the second well that we have tested it that way. And both of those wells are in very early stages of flowback. So it's kind of hard to comment on their productivity. But we definitely think that there's resource potential there. The logs seem to confirm the resource potential there. They seem to drill very similar to the chalk, seem to stimulate very similar to the chalk. And we're just trying to add more H, is what we're trying to accomplish.

[Derrick Whitfield:]

Got it. Thanks for that explanation. And then just up on the Will pad to the north, is there any color you guys can provide on the C interval based on what you've seen so far?

[R. Scot Woodall:]

Sure. So, like I said before, that's a real interesting pad. And so – it was our first C test up in the north and our first A test up in the north, and what we're seeing today is all of those wells seem to be performing about the same. So we really aren't seeing much difference between the A performance, the B performance, and the C performance, which really could be pretty significant of opening up some additional locations for us if that pans out or continues to hold through in the future.

[Derrick Whitfield:]

Perfect. That's all for me. Thanks, guys.

[R. Scot Woodall:]

Thanks.

[Operator:]

Thank you. Our next question comes from Chris Stevens with KeyBanc. Your line is open.

[Chris S. Stevens:]

Hey, good morning, guys. Can you just maybe touch on whether or not there's any significant cost difference from the 1,200 pounds per foot relative to the 1,000 pounds per foot? And, I mean, it seems like the well performance to date has been pretty positive on the upsized completion there. So any plans to maybe push that even higher on the next pad?

[R. Scot Woodall:]

Yeah. So I guess, Chris, I'd probably roughly say the difference between the 1,000 pounds of sand per lateral foot and the 1,200 pounds of sand per lateral foot is probably something in the $250,000 type of a range. And so I think that we would like to probably start off, if and when we resume drilling, is probably something in that 1,200 range. There's some people that are talking about going to 1,500 pounds or greater, and I think our team is kind of looking at that right now. There's a few other operators that have done that, and I think we probably would like to research the production and see if there's a cost benefit there or not. And so we're not quite sold yet that you need to go to the 1,500 but are kind of trending towards 1,200, I guess I would say.

[Chris S. Stevens:]

Okay. And I guess just on the different spacing concepts that you're testing on that Section 4-62-9, are you going to be drilling wells wider on a go-forward basis? Is that what I heard before?

[R. Scot Woodall:]

I kind of think so. And obviously the technical team would like to have a lot more data, but you're trying to balance – clearly when you put 16 wells or so in a section, you recover more reserves out of the entire drilling spacing unit, but clearly it costs more capital to do that. And so what's the balance of recovering more reserves to the additional capital? And actually that's somewhat of a moving target as commodity prices move a little bit, too. So I think, as all engineers would probably say, they want a little bit more data before you draw that absolute conclusion, but I would say on preliminary runs that I have seen, we think that we're going to be kind of targeting more of that 50, 60 acres at least initially if and when we resume activity.

[Chris S. Stevens:]

Okay. Is that like six to seven wells per zone?

[R. Scot Woodall:]

Well, if you did something that's in the 10 to 12 per drilling spacing unit, and if you have two zones there, yeah, you're talking about five or six like in the B, and five or six like in the C.

[Chris S. Stevens:]

All right. Thanks a lot, guys.

[Operator:]

Thank you. Our next question comes from David Beard with Coker Palmer. Your line is open.

[David E. Beard:]

Hi, good morning. Congratulations also on the quarter. Most of my questions have been asked, but I had a couple of smaller ones. First, just to follow on the marl landing zone. Have other companies tried wells and have done that? Have you seen any results there?

[R. Scot Woodall:]

It's kind of hard to get at some of that data, I guess would say, because what's reported to the state is just where the lateral goes horizontal. And so without the actual drilling surveys and things, it's probably hard to say if – because this chalk and this marl is only 50 or 60 feet maybe difference. So it's kind of hard to draw those conclusions if you're not a participant in the well.

[David E. Beard:]

Yeah, no, no, I understand. And then second, a little bigger question about resuming drilling. If you were to flex a rig, do you think you'd lose any efficiencies? Or would that impair your well costs at all?

[R. Scot Woodall:]

We really don't think so. As we look back in 2015 when we brought in a second rig, the second well at the time set our own internal record in terms of speed by the second well. So I think that there's enough information transfer and technology transfer that I would have the expectation that we wouldn't lose much. And I think probably, putting a compliment out to the service industry, I think through all of their layoffs they probably have kept the absolute best people, and you've got probably the most experienced people out there. And even as you saw rig count dropping over the last several quarters, our efficiencies, when we were working, was much higher just because of the maturity level and experience level of the service industry. So I would expect that we'll kind of pick right up where we left off and be able to maintain the same cost structure and efficiencies.

[David E. Beard:]

Okay. And then lastly, talked a lot about hedges over the years, your philosophy on hedging. Given where the curve is, it makes it pretty tight. Would you be willing to start-up and not hedge, or you think the two are still loosely linked?

[William M. Crawford:]

No, I think our philosophy and our strategy has paid off over time where you layer in to be 50% to 70% hedged on a forward 12- to 18-month basis. And as we look to put capital to work, we believe that we have strong economics, and we'll protect it to the extent we can. So, as usual, we'll protect the cash flow.

[David E. Beard:]

All right, good enough. Appreciate the time, and thank you.

[Operator:]

Thank you. Our next question comes from Jeff Robertson with Barclays. Your line is open.

[Jeffrey Robertson:]

Thanks. Scot, just a question on I guess drilling activity. Are you seeing anything with respect to either costs or differentials in the DJ that maybe brings down the oil price threshold that you look at to return a rig to activity?

[R. Scot Woodall:]

Yeah. Sure, Jeff. Both of those seem to be trending in our favor. As we've kind of said, the well costs coming down from that $4.75 million to like $4 million obviously goes in our favor. And then we continue to see lower and lower differentials. We were modeling something more like $7 to $9, and now I think we're thinking we're more in the $3 to $5 range. So those two things have a pretty strong, positive impact on your well economics.

[Jeffrey Robertson:]

Do you think $3 to $5 is good number going forward? Is that sustainable?

[R. Scot Woodall:]

Yeah, we sure do. That's the way we're modeling it. You've still got a lot of capacity in the basin, and that seems to be where things kind of are settling in.

[Jeffrey Robertson:]

Just a follow-up to that. Is a part of the calculus that you all are going through is just to get some data on how all these different completions you all have put in – have tried this year are affecting production? And when you restart, go with what you've learned from all that?

[R. Scot Woodall:]

Well, sure. Definitely the pause in activity allows you to get a little bit more production history. That lets you get a little bit more data to tell you how you would go forward. So I think that is an added side benefit. But I think we've been trying to manage our cash, manage our liquidity, manage our balance sheet. So that's really been, I think, the primary drivers for the spending levels that we've undertaken for this year. I think protecting the balance sheet and being able to generate cash in a quarter is something that we had a high priority on and are happy to say that we could demonstrate that.

[Jeffrey Robertson:]

And lastly, out of the DJ, Scot, up in Wyoming, is there anything going on around the Codell play that has any impact on the acreage (35

[R. Scot Woodall:]

Not really. There's still some activity up there. We're in a non-op position. And so it really has a very tiny impact on us really.

[Jeffrey Robertson:]

Okay. Thank you.

[Operator:]

Thank you. Our next questions comes from Gabe Daoud with JPMorgan. Your line is open.

[Gabriel J. Daoud:]

Hey, good morning, guys. Just a quick question, I guess. If you do resume a one-rig program in the DJ in the fourth quarter – or I guess for just 2017, assuming you run one rig, you do 35 wells, what do you think that does to DJ volumes year over year in 2017?

[R. Scot Woodall:]

They definitely would grow. Kind of what we have been saying, Gabe, is something like a 20 net well program keeps the company's production flat. So, depending on the working interest mix of that one-rig program, it could be flat to up depending on what our net working interest is.

[Gabriel J. Daoud:]

Thanks, Scot. That's helpful. And then maybe just a clarification point on inventory. You've previously stated I think 1,100 locations, other XRLs, (36

[R. Scot Woodall:]

Sure. So the 1,100 locations does have a geologic footprint on it. It probably has not been updated for perhaps the results that we're seeing on the Will pad in terms of the A activity and the C activity. So I think that's something that our geologic footprint may be moving a little bit as we continue to delineate the field and get more results. The basic premise of the 1,100 locations was on a 40-acre spacing. So it had geologic footprint and then it had an assumption of 40-acre spacing that led to those 1,100 locations.

[Gabriel J. Daoud:]

Okay, great. Thanks, Scot. That's all I had.

[Operator:]

Thank you. That does conclude today's question and answer session. I'd like to turn the call back to Larry Busnardo for closing remarks.

[Larry Busnardo:]

Great. Thank you again for joining us today. As always, please feel free to contact us if you have any additional questions. And we look forward to seeing you at future conferences. Thanks again.

[Operator:]

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