Laredo Petroleum Holdings, Inc. (NYSE:LPI)
Q2 2016 Earnings Conference Call
August 04, 2016, 08:30 AM ET
Ronald Hagood - Director of Investor Relations
Randy Foutch - Chairman & Chief Executive Officer
Daniel Schooley - Senior Vice President of Midstream & Marketing
Richard Buterbaugh - Chief Financial Officer & Executive Vice President
Neal Dingmann - SunTrust Robinson Humphrey Inc.
John Herrlin - SG Americas Securities LLC
Derrick Whitfield - GMP Securities LLC
Jason Smith - Bank of America Merrill Lynch
Brian Singer - Goldman Sachs
Jeffrey Robertson - Barclays Capital
Good day, ladies and gentlemen, and welcome to Laredo Petroleum, Inc.’s Second Quarter 2016 Earnings Conference Call. My name is Chelsea, and I will be your operator for today. At this time, all participants are in a listen-only mode. We will be conducting a question-and-answer session after the financial and operations report. As a reminder, this conference is being recorded for replay purposes.
It is now my pleasure to introduce Mr. Ron Hagood, Director, Investor Relations. You may proceed, sir.
Thank you, and good morning. Joining me today are Randy Foutch, Chairman and Chief Executive Officer; Rick Buterbaugh, Executive Vice President and Chief Financial Officer; and Dan Schooley, Senior Vice President, Operations; as well as additional members of our management team.
Before we begin this morning, let me remind you that during today’s call, we’ll be making forward-looking statements. These statements, including those describing our beliefs, goals, expectations, forecast and assumptions are intended to be covered by the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. The company’s actual results may differ from these forward-looking statements for a variety of reasons, many of which are beyond our control.
In addition, we’ll be making reference to adjusted net income and adjusted EBITDA, which are non-GAAP financial measures. Reconciliations of GAAP net income to these non-GAAP financial measures are included in yesterday’s news release.
Yesterday afternoon, the company issued a news release and presentation detailing its financial and operating results for second quarter 2016. If you do not have a copy of this news release or presentation, you may access it on the company’s website, at www.laredopetro.com.
I’ll now turn the call over to Randy Foutch, Chairman and Chief Executive Officer.
Thanks, Ron, and good morning, everyone. Thank you for joining Laredo’s second quarter 2016 earnings conference call.
The second quarter proved to be another successful quarter for Laredo on all fronts. Production exceeded the top end of the guidance as the Earth Model, coupled with optimized completions, drove substantial outperformance of type curves on new wells, and field infrastructure investments minimized production downtimes on our producing wells. Cash margins benefited from another 30%-plus year-over-year decrease in LOE and hedges increased our realized price per barrel of oil equivalent by approximately 44%.
The performance of the 29 wells drilled employing our Earth Model, in conjunction with optimized completions, is improving at approximate 34% oil production uplift versus the Laredo oil type curves. The outperformance of our new wells and the reduced downtime of our base production leads us again to raise our production guidance for 2016, while maintaining a three-rig program.
The new guidance midpoint of 17.15 million barrels of oil equivalent is an 11% increase compared to our original 2016 guidance midpoint of 15.5 million barrels of oil equivalent. This new range indicates an annual production growth rate of 4% to 6%. We continue to take advantage of our contiguous locked-up acreage based and increase capital efficiencies by drilling long lateral horizontal wells with our working interest.
Second quarter completions averaged approximately 9,700 feet of completed lateral length and third quarter completions are expected to average approximately 11,000 feet. Additionally, we will be completing four laterals of 13,000 feet or longer.
A few weeks ago, we announced a transaction that enables the highly efficient development of the block of acreage, primarily operated by Laredo in western Glasscock County. We’ve long had a positive view of the development potential of this acreage and worked to execute a transaction to increase our working interest across the acreage block and acquire additional Spraberry rights.
This block can be developed entirely with 10,000-foot or longer laterals, and very importantly, we own surface rights on five sections of this acreage block, enabling us to source our own water at a very low cost, saving us approximately $300,000 per well.
We will also be building our western Glasscock production corridor, which is expected to provide additional operational efficiencies and savings. We expect that with the well cost for the Spraberry and upper and middle Wolfcamp horizontals in the $5.8 million to $5.9 million range versus the current $6.3 million average, returns on this block could surpass those drilled in other of our production corridors. As we evaluate opportunities and timing to accelerate activities, additional rigs are expected to focus on this block.
The last nine months has marked a return to Laredo traditional operation excellency after what were admittedly some hiccups in 2014 and early 2015. The step-change in results, backed up by strong production and peer-leading operating cost, has been driven by multiyear investments in data and infrastructure and the determined efforts of the dedicated professionals at Laredo.
We believe our best-in-class operations, coupled with our strong hedge position, a flexible balance sheet with no term debt maturities until 2022 and ample liquidity, enable the creation of repeatable value for shareholders in this volatile commodity price backdrop.
I would now like to turn it over to Dan for an operational update.
Thank you, Randy, and good morning. As Randy mentioned, the second quarter was a continuation of Laredo’s return to operational excellence, as demonstrated by the positive step-change in the results over the last nine months.
Total production of 4.34 million BOE exceeded the midpoint of guidance by 3%. An average daily production of 47,667 BOE per day was a company record. Average daily production increased 3% from the first quarter of 2016.
We completed 16 horizontal wells during the quarter, all utilizing our Earth Model and optimized completions, with 10 having achieved peak 30-day average IP rates. On average, the 10 wells performed at 135% of type curve based on their 30-day rates, even with 8 of those wells on managed flow-back.
We’re seeing the wells’ performance continue to improve as they are currently performing at approximately 140% of type curve. The four-well Holt package has improved from 164% of type curve based on its peak 30-day average IP to 166% currently, and the four-well Cox package has improved from 102% of type curve based on peak 30-day average IP to 113% currently.
On the cost side, we continue to make improvements in lowering operating costs. We reduced LOE to $4.43 per BOE in the second quarter, a decrease of 36% from the second quarter of 2015 and a decrease of 9% from the prior quarter. While we benefited from aggressive management of our service and product costs, the primary driver of our peer-leading LOE is our prior investments in field infrastructure, especially in our production corridors. We estimate the savings from these prior investments has reduced LOE for the second quarter by $0.72 per BOE.
We continue to dramatically improve our drilling and completion efficiencies. In the second quarter of 2015 from rig accept to rig release, our rigs drilled an average of 596 feet per day. That has improved to 990 feet per day in the second quarter of 2016. This improvement decreased drilling time from a well from approximately 26 days in the second quarter of 2015 to approximately 16 days in the second quarter of 2016, while increasing lateral length approximately 26% over the same time period.
The net effect of these improvements, combined with completions efficiency improvements and service cost reductions, has been to decrease total drill and complete cost per foot from $936 per foot in the second quarter of 2015 to $634 per foot in the second quarter of 2016, even as we utilized optimized completions and higher sand concentration.
As presented at our Investor Meeting in mid-June, our well cost for the upper and middle Wolfcamp 10,000 foot laterals, with optimized completions and 1,800 pounds of sand per foot, was approximately $6.3 million. Not only have we achieved this, some of our most recent wells have been down in the mid-$5 million range, including optimized completions and more sand.
We are focused on longer, more capital-efficient wells, which are enabled by our highly contiguous acreage position. In the third quarter, the average lateral length increased by 13% to approximately 11,000 feet. We’ve already drilled four wells with lateral lengths in excess of 13,000 feet, which we will be completing in the third quarter. On average, these wells were drilled in a little over 17 days from rig accept to rig release.
In early July, we announced a transaction that increased our working interest and secured additional rights to the Sprayberry zone across an acreage block in western Glasscock County. This Laredo-operated acreage perfectly fits our development model, which includes accommodating a production corridor, having fully processed Earth Model data, development of 10,000-foot or longer laterals, and Laredo with a high working interest.
In fact, development of this acreage has an additional cost reduction advantage. We own five sections of surface within this block, enabling Laredo to drill its own water wells and access water for completions at very low cost. The combination of production corridor and water cost savings are expected to lower the cost for Sprayberry upper Wolfcamp or middle Wolfcamp 10,000-foot horizontal to a range of $5.8 million to $5.9 million.
This savings increases targeted rates of return by approximately 10% at $55 per barrel realized oil price. The western Glasscock production corridor is expected to require approximately $15 million investment, which includes the water wells and water delivery system on our surface acreage beginning in the fourth quarter of 2016.
Laredo’s infrastructure assets continued to generate substantial benefits for the company. In the second quarter of 2016, the company recognized approximately $6.4 million in cash benefits from LMS field structure assets and expects a full-year 2016 benefit to total more than $26 million. Included in this number is $0.72 per BOE and LOE savings I mentioned earlier, which equates to over $3 million in LOE savings for the quarter.
The Medallion-Midland Basin pipeline system, in which LMS owns a 49% interest, continued its rapid growth, transporting an average of 99,039 barrels of oil per day in the second quarter of 2016, an increase of approximately 19% from transported volumes in the prior quarter. It is expected that transported volumes will average approximately 120,000 barrels of oil per day in the third quarter and anticipated increase of more than 20%.
Although the number of rigs on acreage dedicated to the Medallion-Midland Basin system has decreased by approximately 30% since late 2015, transported volumes on the system have demonstrated very strong growth over that period. The system is expected to transport an average of 140,000 barrels of oil per day by the end of 2016. And given the highly productive acreage dedicated to the system, it is anticipated transported volumes will benefit should operators accelerate drilling activities.
I’ll now pass it to Rick for a financial update.
Thank you, Dan, and good morning. As reported last night in our second quarter 2016 earnings release, the company posted impressive operating and financial results. For the second quarter of 2016, we reported adjusted net income of $28.2 million or $0.13 per diluted share, exceeding street consensus by 30%. This is more than 2.5-fold increase from the prior-year quarter, and up more than 60% sequentially from the first quarter of this year.
The solid results were driven by stronger well performance from both our base production and new drilling activities, as Dan detailed, coupled with our continued focus to control all aspects of our cost structure. These items also benefited adjusted EBITDA for the period, which totaled approximately $108 million, an increase of about 12% from first quarter 2016.
Our cash flow from operations totaled approximately $83 million, more than funding the $80 million of incurred capital expenditures excluding acquisitions related to our exploration and development activities during the second quarter.
Reconciliations of GAAP net income to adjusted net income and adjusted EBITDA are included in yesterday’s news release.
Cash flows were positively impacted by the company’s exceptional operational performance, where we exceeded the high end of guidance on production volumes and the low end of guidance on both unit LOE and G&A.
Total cash cost decreased to $9.87 per barrel of equivalent in the second quarter of 2016, down about 4% sequentially from the first quarter rate. This further increased our hedge cash margin to $24.13 per BOE, up approximately 8% from the $22.38 in the first quarter of 2016.
Hedging a substantial portion of our production is a core tenet of the company’s risk management philosophy to mitigate the variability in anticipated cash flows resulting from commodity price fluctuations. Through a combination of puts, swaps and collars, Laredo has achieved this while also maintaining appreciable upside to commodity prices.
This philosophy has served the company well over the years and provides added confidence in funding a stable capital program, even during volatile commodity price cycles, which we believe is critical to retain development efficiencies.
As a reminder, none of our collars are three-way or knock-out collars. We feel that doing so would defeat the true purpose of hedging, and that is to mitigate risk. Therefore, should oil prices continue to move down, we can rely upon the value of our derivative contracts.
For the second half of 2016, the company has hedged approximately 95% of expected oil production at a weighted average floor price of $67.13. But keep in mind that, while we have protected the downside with these floors, we have retained unlimited upside on approximately 35% of our anticipated production and approximately 45% of this production has a ceiling of $90 per barrel.
Our natural gas hedges are structured as a collar with a $3 per million Btu floor and a ceiling of $5.60. In total, we have hedges covering approximately 60% of anticipated volumes on a BOE basis.
In 2017, we have hedged approximately 70% of expected oil production with weighted average floor of $57.01, retaining significant upside on approximately two-thirds of our total volumes. Details of our individual hedge contracts that run through 2018 can be found on page 15 of the presentation published on our website in conjunction with last night’s earnings release. As of July 31, the value of the company’s hedge book was approximately $155 million.
With the demonstrated success of our drilling program, we announced in May that we would retain our third operated drilling rig and continue to utilize the Earth Model to optimize all completions through the remainder of 2016. We were also successful in acquiring additional leasehold interest in a core area within our western Glasscock acreage. We funded these expansions to our capital program by accessing the equity markets.
The end result of these activities was an acceleration of drilling activities to bring forward the value recognition of our drilling inventory, an increase in our expected 2016 production and the bolt-on acquisition of top-tier acreage, while maintaining significant financial flexibility, including the $760 million of current liquidity that the company has.
Through the first six months of 2016, we have incurred approximately $180 million of capital expenditures relative to our expanded capital budget of $420 million. In addition, we invested $15 million during the second quarter to expand the Medallion pipeline system.
Although drilling efficiencies are enabling us to drill more wells, we believe the capital efficiencies will nearly offset these additional costs. Therefore, we are projecting total year capital, excluding our recent acquisition and Medallion investment, to remain within the $420 million capital budget.
At this time, I’ll turn the call back to Randy.
Thank you, Rick. As Rick pointed out, our outstanding hedge position protects our cash margin and provides financial stability and flexibility. Additionally, we have significant liquidity to fund additional drilling, although we are always careful to increase drilling in a measured manner and not outrun our data.
As you’ve also heard, our outstanding drilling results, combined with capital and operating cost reductions, are driving meaningful gains in our capital productivity. These productivity gains enable the company to drill more wells at above type curve rates, and thus, accelerate with the same number of rigs and grow production with our current three-rig program.
The company’s four current production corridor areas and planned western Glasscock production corridor area provide us with an inventory of high-return, high working interest drilling locations that can be developed with 10,000-foot or longer laterals, utilizing existing infrastructure and our Earth Model.
As we evaluate our 2017 drilling program, these locations provide a growth runway for the company where we can deploy rigs and generate high returns even at current commodity prices.
Operator, please open the lines for questions.
[Operator instructions]. Thank you. And our first question comes from the line of Neal Dingmann with SunTrust. Your line is now open.
Good morning, guys. Good color. Say, just a question, I guess, based on that, I’m looking at slide 4 and 5 specifically on just the improved results and especially around the Earth Model. I guess, number one, will you continue, is that all wells will follow that as well as the longer lateral that you’ve been talking about?
Good morning, Neal. This is Randy. The good thing about our acreage is it was blocked up and we started acquiring some of the acreage necessary for the Earth Model five years or six years or longer years ago. So I think the nature of the acreage allows us to drill more long laterals. So I would anticipate most of our drilling going forward, if not all, will have the Earth Model backing it up with the optimized completions as part of that.
And I think you should expect that almost all of our drilling is 10,000-foot or longer. We do have to true-up some acreage on the fringes, but we’ve got a long runway of drilling within our corridors that are 10,000-foot, 11,000-foot, 12,000-foot laterals, covered by the Earth Model.
And then, just a follow-up. And it does seem like - it’s great to see you guys back really to work. Your thoughts on - I think, myself, the Street really doesn’t have a big outspend for you all. How do you view, Randy, when you think about that kind of the growth you guys are seeing versus the potential outspend? I mean, are you sort of happy with the cash and liquidity you have? Or do you see potential additional non-core sales having to help fund that?
We’ve said, I think, fairly consistently that we see a lot of different ways of financing acceleration. We’ve talked about selling acreage. We’ve talked about a number of things. The interesting thing to us is when you look at our acreage from north to south and certainly on the west side, the north side, we’re seeing lots of other operators drill in and around us and make pretty good wells, and some of them are close to our acreage.
So I think our view is that we think there’s acreage that we’re going to be a long time getting to, certainly some that doesn’t lend itself perfectly to a corridor. But at some point, we’ll have to make the decision on what we do with it. But, in the meantime, we’re certainly getting lots of data from other operators, some of which is some pretty exciting drilling results.
Great details. Thanks.
Thank you. And our next question comes from the line of John Herrlin with Société Générale. Your line is now open.
Yeah. Hi. For these longer reach or extended length horizontals, what kind of fracs are you doing? Are you doing a hybrid frac? Can you do slick-water out 13,000 feet?
Yeah, John. Good morning. We still think our completions are getting better but, yes, we’ve done a very long reach slick-waters. We’ve done some of those with quite a lot of sand. We’re really trying to find the optimization there. We’ve done a little bit of hybrid work.
So what we’re seeing is that we’re able to drill those wells. We’re able to complete them very successfully and we’re still getting better and better results. So I think we’re a long way from figuring out exactly what the optimization completion is. But the good news for us is that we’re getting better and the Earth Model’s allowing us to complete and see productivity from more of that long reach lateral.
Great. Thanks, Randy.
Thank you. And our next question comes from the line of Derrick Whitfield with GMP. Your line is now open.
Yeah. Good morning, guys.
Great to see the well performances grinding higher. With regard to the middle Wolfcamp specifically, would you attribute the outperformance this quarter more to geology or process?
We think - if you just step back, we’ve said consistently for a number of years that we think we have a number of zones that are going to produce from shallow all through the Wolfcamp. Keep in mind that some of our more economic, better productive wells are Cline. We know the Canyon is going to produce a lot of our acreage.
So we’re not surprised to see the middle Wolfcamp contribute to our success. And I think it’s partially geology and I think it’s certainly a big part of our Earth Model and optimized completions. I think before we’re done, we’re going to see this 4,000-foot, 5,000 foot section of rock that we have that we know is going to produce oil, I think we’re going to see a lot of successes come out of it.
Okay. Very good. And a separate follow-up would be, so as we look at the data that you presented over the last couple of quarters as it relates to well performance versus type curve, we have noticed that the upper Wolfcamp is not responding quite as well as the others are to the optimized completions. I guess, first, is that a fair characterization, and if so, do you have a view on why?
I’m not sure that I think it’s a fair characterization. I think we’re seeing more data on the Wolfcamp with more wells. But I think what we’re seeing is pretty substantive increases everywhere we’ve used the Earth Model and the optimized completion. It doesn’t surprise me that we’re going to have some really stellar, as we’ve talked about, middle Wolfcamp.
And again, keep in mind that we’ve talked about having some pretty good Cline wells in the past. And I think it’s also fair to talk about that the upper Wolfcamp type curve was already higher than the middle Wolfcamp or other zones. So it started off at a higher base. So, if you look at it in terms of percentage, we’re getting very, very similar performance increases from the Earth Model from the upper to the middle.
Thank you. That’s all for me.
Thank you. And our next question comes from the line of Jason Smith with BofA. Your line is now open.
Hey. Good morning, everyone. Good morning, Randy.
Good morning, Jason.
So, Randy, you talked about just high expectations for western Glasscock. Can you maybe just discuss that a little bit? And I’m just curious just thoughts around what you expect for oil cut, any difference in well cost or anything else as you guys ramp up activity out to the west?
You’re talking specifically about the acquisition?
That’s an areas that we’ve covered it for four years, five years. We had the largest working interest already. We operated almost all of it. We did pick up additional Spraberry interest that we didn’t own. And so we had tried a couple times in the past to buy it.
Our view is, we had the Earth Model already across the acreage before we made this final attempt to buy it. I don’t think we see a substantive change in our oil percentage, as we’ve talked about before. We think we kind of know where that’s going to be. Also, think we’re still driving well cost lower, but I don’t see anything there that makes it remarkably different from most of our other acreage.
Got it. Thanks. And I guess, just a follow-up. So, as you mentioned, a lot of the acquisition was for Spraberry. Any plans in the near future to test Spraberry? And I’m also, I guess, just curious if you see the acreage as prospective for just lower Spraberry, or is it middle and lower Spraberry?
I think we’ll probably decide and look at some Spraberry still this year maybe on that acreage. Our Earth Model makes us think that there’s a couple of different places that we might land Spraberry wells. And we’re still homing in on exactly what our Spraberry plans are there.
Appreciate the answers. Thanks.
Thank you, Jason.
Thank you. And our next question comes from the line of Brian Singer with Goldman Sachs. Your line is now open.
Thank you. Good morning.
Good morning, Brian.
Wanted to get your thoughts on leverage versus liquidity. You talked about having substantial liquidity to have the ability to ramp up as the commodity price environment has improved or can continue to improve.
Can you just add some more color there of beyond liquidity how important leverage is or whether you kind of just look at it and say the liquidity is there, the return to the well level are there, and that’s what guides your capital investments?
We’ve had a long-term conversation with you and others, Brian, that our leverage is very, very manageable in a number of different ways. In a low-price environment, any leverage in our view is high. We were very, very careful to make sure that we pushed out the maturities on our long-term debt such that we didn’t have to do anything. We’ve been very, very careful to hedge.
So I think there’s a number of ways that we look at the leverage. We always wish it was less. But we still think the same things that we’ve been talking about in terms of how we can address that leverage with monetizing some assets. And so we’re still pretty comfortable with that.
Rick, do you want to address the liquidity?
Morning, Brian. The bulk of our debt is related to the $1.3 billion of long-term notes that we have outstanding. None of those notes are callable prior to 2017. So, although our leverage is really higher than we probably would want it to be in this environment; we believe that it’s structured in a fashion that doesn’t give us a lot of concern.
None of it, as Randy mentioned, is due prior to 2022. We have basically a nearly undrawn credit facility. Our borrowing base is $815 million. We have minimal amount drawn on it, which is what provides that $760 million of current liquidity that we have.
That, coupled with the hedges and the very strong hedge position that we have that goes out multiple years and something that we continue to look at expanding on a regular basis, gives us comfort that, although the overall leverage is higher than we may want, it is extremely manageable and not really curtailing the company.
As far as acceleration, the liquidity does give us a lot of flexibility to accelerate if we choose to, but that is not driven just by commodity prices. That’s making sure, as we’ve always done, is that we do not want to get ahead of our data. We’re obviously seeing very strong results coming in from the wells, very encouraged by how the Earth Model is positively impacting that, and all of those factors come into play in how we look at accelerating.
As we’ve talked about, we have maintained the three horizontal rigs. The efficiencies that we’re getting through our drilling activities is providing more wells per rig and we’re drilling longer wells per rig. So, even though we’re maintaining a three-rig program currently, we’re getting more wells drilled out of that and more production, resulting in higher cash flows coming in that help support that current debt level that we have.
Great. Thanks. That’s helpful. And...
[indiscernible] into 2017. Brian, let me just add one thing. A significant portion of those long-term notes do become callable and gives us additional flexibility to bring down leverage if we choose to.
Got it. Okay. Thank you. And then my follow-up is just with regards to the operating costs, which have continued to come down here. And I wondered if you can talk about what you think more normalized op costs are, if that’s a decrease or an increase from here as we think about an environment that may be a little bit better in commodity prices relative to the second quarter?
No, I think what you’re seeing is what we’ve been saying for three or four years that the way we’ve developed our infrastructure would lead us to more or less long-term permanent LOEs that are pretty exciting and have a good handle on actually really getting the benefit of what we’re talking about going forward.
I think guidance in the third quarter of $4.25 to $4.75 per barrel equivalent is an indication, Brian, of what we think about our ability to preserve and all that. And it really is, well, one, a lot of good work from some Laredo employees, but also I think it’s inherent in the way we’ve gone about our business for the last five years or six years.
Dan, you, Rick, want to add anything? Did that help, Brian?
Yes. Thank you very much.
Thank you. And our next question comes from the line of Jeff Robertson with Barclays. Your line is now open.
Thanks. Randy, just a question on lateral lengths. With the four wells you’re drilling at 13,000 feet, how long do you think it’ll take to evaluate the performance of those wells to make you - to determine whether or not that’s the right length? And if it is the right length, would you continue to push lateral lengths further?
I think - it’s interesting to me. We’ve said consistently that some of the focus on 24-hour IPs was misguided. And while we’ve talked about them in 30-day IPs, we really would like to see [ph] substantive (36:45) in history. And I think we’re seeing the company be pretty methodical and progressive in terms of lateral length.
The good thing is that we’ve drilled some 12,000s feet and so on, so forth, without any issues and the ability to complete them is there. Our acreage is set up that - I don’t know that we would do this, but we could drill 15,000-foot laterals in lots of places.
So, for us, I think we’re still in the mode where we want to optimize completion and find that sweet spot on lateral length. But what we’re seeing in general is the cost of drilling that additional lateral and the ability to optimize that completion are generating what we consider, even in this commodity price environment, really outstanding rate of return. So, if it looks like 12,000 feet is the right length or 13,000 feet or something, our acreage supports a lot of that.
And to follow up on Brian’s question, does that also lead to preserving lower LOEs?
I think it lends itself to incrementally lower LOEs, but the LOEs on a horizontal well are over the life of the well, you can kind of see what we think in the terms of the guidance. The initial year, of course, the LOE is pretty cheap on a horizontal well. We’ve got a pretty good inventory of vertical production and we’ve been very aggressively, I think, focused on the LOEs for that vertical production. But longer laterals helps all around on just better your economics across the board.
Thank you. I’m showing no further questions at this time. I would now like to turn the call back to Mr. Ron Hagood, Director, Investor Relations, for closing remarks.
We thank you for joining us for our second quarter earnings conference call and look forward to seeing you at conferences and meetings throughout the quarter. Thank you.
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.
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