Vital Energy, Inc.
Q3 2013 Earnings Call Transcript

Published: 7 Nov 2013

[Executives:]

Ron Hagood Randy A. Foutch - Founder, Chairman and Chief Executive Officer Jay P. Still - President, Chief Operating Officer and Director Richard C. Buterbaugh - Chief Financial Officer, Principal Accounting Officer and Executive Vice President

[Analysts:]

Brad Carpenter - Wells Fargo Securities, LLC, Research Division Gilbert K. Yang - DISCERN Investment Analytics, Inc Ipsit Mohanty - Canaccord Genuity, Research Division Jeffrey Campbell - Tuohy Brothers Investment Research, Inc. James Sullivan - Alembic Global Advisors Kerr Friedman - Simmons & Company International, Research Division Sven Del Pozzo - IHS Herold, Inc. John P. Herrlin - Societe Generale Cross Asset Research

[Operator:]

Good day, ladies and gentlemen, and welcome to Laredo Petroleum Holdings, Inc's. Third Quarter 2013 Earnings Conference Call. My name is Lisa, and I'll be your operator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. It is my pleasure to introduce Mr. Ron Hagood, Director, Investor Relations. You may proceed, sir.

[Ron Hagood:]

Thank you, Lisa, and good morning. Joining me today are Randy Foutch, Chairman and Chief Executive Officer; Jay Still, President and Chief Operating Officer; Rick Buterbaugh, Executive Vice President and Chief Financial Officer; Pat Curth, Senior Vice President, Exploration and Land; as well as additional members of our management team. Before we begin this morning, let me remind you that in today's call we will be making forward-looking statements. These statements, including those describing our beliefs, goals, expectations, forecasts 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 those forward-looking statements for a variety of reasons, many of which are beyond our control. In addition, we will be making references to adjusted net income and adjusted EBITDA, which are non-GAAP financial measures. Reconciliations of GAAP net income and these non-GAAP financial measures are included in today's news release. Also as a reminder, Laredo reports operating and financial results, including reserves and production, on a 2-stream basis, which accurately portrays our ownership of the oil and natural gas produced. Therefore, the value of the natural gas liquids is included in the natural gas stream and pricing, not as part of oil and condensate or included in a combined liquids total. If reported on a 3-stream basis, Laredo's barrel of oil equivalent volumes for reserves and production, including initial production rates and EURs, would increase by approximately 20%, which you should keep in mind when comparing to companies that report on a 3-stream basis. Similarly, Laredo's unit cost metrics will appear higher when compared to companies that report on a 3-stream basis. However, the true economic value is the same. Earlier this morning, the company issued a news release detailing its financial and operating results for the third quarter of 2013. If you do not have a copy of this news release, you may access it on the company's website at www.laredopetro.com. In this morning's release, Laredo reported net income for the third quarter 2013 of $12.5 million or $0.09 per diluted share, and adjusted net income, a non-GAAP financial measure, of $20.7 million or $0.15 per diluted share. Adjusted net income includes a total derivative financial instrument loss of approximately $9.8 million, including $1.4 million net cash received on settlements of matured derivative financial instruments and early settlements of derivative financial instruments, as previously reported. I'll now turn the call over to Randy Foutch, Chairman and Chief Executive Officer.

[Randy A. Foutch:]

Thank you for joining us for Laredo's third quarter 2013 earnings conference call. We do appreciate your time. In the third quarter, Laredo made significant progress in its multizone development plan for the Permian-Garden City asset from both an operational and financial perspective, and we continue to pursue a disciplined data-driven approach to maximize the value of our acreage. During the quarter, as we have previously communicated as our plan, we drilled and began completion operations on the company's first 3 stacked laterals that, coupled with our horizontal spacing test last quarter, will significantly enhance our understanding of the most efficient and scalable multizone development program. Additionally, we remain focused on delineating our initial 4 zones across our entire acreage position, but also horizontally testing promising new zones, such as the Spraberry and the ABW. Our extensive analysis of petrophysical and geological data continues to drive our excellent well results. This quarter, we completed our best Cline horizontal well to-date and continued to have success in all 4 initially targeted zones. We exit the third quarter exceptionally well-positioned financially. After closing the Anadarko Basin sale and executing a follow-on equity offering, the company has the financial resources to efficiently develop the Permian-Garden City asset. Now I'll turn the call over to Jay Still, President and Chief Operating Officer, for an operational update.

[Jay P. Still:]

Thank you, Andy. Operationally, the company had a good quarter as we grew Permian production from the prior-year third quarter and in line with the guidance. We continue to deliver strong well results and make progress in our testing of vertical spacing of horizontal pad drill wellbores. During the third quarter, we completed 6 horizontal wells, with 5 having enough data for an average 30-day IP rate. At this point, I would like to supplement the data from the well results chart in the press release, with some 3-stream rates, and reiterate our expected EURs from each zones. There were 2 wells completed in the Upper Wolfcamp, the Glass-Glass 10 #152HU and the Bodine-C30-1HU. The Glass-Glass achieved a 3-stream peak 24-hour IP of 902 barrel of oil equivalent per day and a 30-day average IP of 782 barrel of oil equivalent per day. The Bodine achieved 3-stream rates of 1,586 barrel of oil equivalent per day and 836 barrel of oil equivalent per day. Our Upper Wolfcamp 3-stream type curve is 924,000 BOEs. There were 2 Middle Wolfcamp wells we completed in the quarter. The Sugg-B-131/Holt E 2HM, the Bodine C-30-2HM. The Sugg-B had a 3-stream peak IP rate of 1,229 barrel of oil equivalent per day and a 30-day average IP of 663 barrel of oil equivalent per day. The Bodine achieved a 3-stream rate of 1,106 barrel of oil equivalent per day and 605 barrel of oil equivalent per day. Our Wolfcamp -- our Middle Wolfcamp 3-stream type curve is 793,000 BOEs. While we had no Lower Wolfcamp completions in the quarter, our 3-stream type curve for the zone is 814,000 BOEs. Last, but definitely not least, in the Cline we completed the Glass-Glass 10 #153H well. This is our best Cline horizontal well and accompanied with a 3-stream peak 24-hour IP of 1,888 barrel of oil equivalent per day and a 3-stream 30-day average IP of 1,408 barrel of oil equivalent per day. Our 3-stream type curve for the Cline is 796,000 BOE. This well is currently producing significantly above that type curve. The Cline remains an important part of our development plan as supported by other industry activity. Additionally in the third quarter, we began drilling and completion pad operations on our first 3 stacked lateral tests that drill laterals in the Upper, Middle and Lower Wolfcamp zones. We finished completion operations and began flowback in mid-October. While it's still very early in the history of the wells, we are encouraged by the initial combined peak 24-hour IP rate of 3,318 barrel of oil equivalent per day on a 2-stream basis or 3,778 barrel of oil equivalent per day on a 3-stream basis. This result is in line with the respective type curves, and we will use the longer-term results to fine tune our vertical spacing assumptions for stacked horizontal wells. As we continue our progress in optimizing our multizone development plan, we will be drilling combinations of stacked laterals in multiple zones and multiple laterals in the same zone. This will continue to impact the timing of our production and create quarter-to-quarter lumpiness. We have experienced a few issues that had an impact on third quarter production and will likely put fourth quarter production at the low end of guidance. An instance of stuck pipe that resulted in the required side track to another zone has delayed the completion of the well from the third quarter to the end of the fourth quarter. Another well with a casing integrity issue while stimulating, will also have its completion delayed until the latter part of fourth quarter. Additionally, last week, there was a fire that destroyed our of Reagan truck station, resulting in the shut-in of nearby wells and will delay the tie-in of several new wells. Fortunately, our infrastructure investments allow us the flexibility to provide alternative sales outlets and reduce the downtime and delays. However, all of these events contribute to production impacts in the third and fourth quarters. Overall, I feel like we've had an outstanding quarter operationally, as we continue to improve and refine our oil and gas manufacturing process. I would now like to turn it over to Rick Buterbaugh, our CFO.

[Richard C. Buterbaugh:]

Thanks, Jay, and good morning. Our quarterly results, once again, were basically in line with our expectations for production, pricing and overall unit cost, resulting in adjusted net income of $20.7 million for the quarter or $0.15 per diluted share, and adjusted EBITDA of approximately $119 million, both of which are non-GAAP financial measures. Please note that this amount for adjusted EBITDA in the third quarter has been corrected from this morning's initial press release and an amended Form 10-Q is being submitted to the SEC. Total daily production for the third quarter was 28,361 barrels of oil equivalent per day, which includes volumes from the Anadarko Basin properties, only through the closing date of August 1. Third quarter 2013 Permian production was 24,332 barrels of oil equivalent per day, up 17% from prior-year volumes for these properties. Total oil and gas sales were $171 million approximately for the third quarter, up 19% from the third quarter of 2012. While total production for the quarter was down year-over-year due to the divestment of the Anadarko Basin properties, sales were up, as oil volumes as a percent of total production rose from 42% in the 2012 quarter to 49% in the 2013 quarter, and average price realizations rose 29%. Lease operating expense increased at a slightly lower rate of 18% year-over-year, as we began to realize the benefits of some of the best practices initiatives that are being implemented in the field. As a result, unit lease operating expense was $7.50 per barrel of oil equivalent, which was about $0.50 below the midpoint of our guidance. General and administrative costs increased approximately $2.5 million from the second quarter of 2013, primarily due to higher salaries and one-time relocation expenses associated with the hiring of field and technical personnel, as we prepare to ramp up our pad and -- multi-well pad and development drilling activities in the Permian. These costs, coupled with lower volumes following the Anadarko Basin divestiture, resulted in unit G&A expense of $7.10 per barrel of oil equivalent. Additionally, noncash stock-based compensation expense increased approximately $1.4 million from the second quarter of this year, primarily associated with the recent appreciation in Laredo's stock value. The combined impact of more oil-weighted volumes, stronger commodity prices and implementing best operating practices more than offset the temporary increase in unit G&A, resulting in cash margins of $46.39 per barrel of oil equivalent, up 27% from the prior-year period. During the quarter, we closed the sale of our Anadarko Basin assets and completed a follow-on equity offering of 13 million shares. The net effect of those events raised approximately $736 million that was used to completely repay our senior secured credit facility and prefund a portion of our 2014 capital program. Today, the existing cash and our undrawn credit facility provides Laredo with liquidity of more than $1 billion. To underpin our cash flows and capital program going forward, Laredo maintains a very active hedging program. For the fourth quarter of 2013, we have derivatives in place covering a substantial portion of our projected oil production, including 816,000 barrels of oil swapped at $100.08 per barrel and an additional 192,000 barrels that our collared with a weighted average floor price of just over $79 per barrel. For natural gas, we have approximately 3.2 million MMBtu collared with a weighted average floor price of just over $3. As detailed in our news release this morning, we have confirmed our production guidance for the fourth quarter of 2013. However, some of the operating issues that Jay detailed earlier will likely push us to the lower end of this production guidance. We have also increased our expectation for total unit G&A expense, which we expect will peak during the fourth quarter of 2014, before beginning to decline throughout -- excuse me, it'll peak in the fourth quarter of 2013 before it begins to decline throughout 2014, as increasing Permian production volumes replace those volumes that were sold in the Anadarko Basin divestiture. In closing, we believe that we have never been in a better position, both operationally and financially, to execute our multizone development plan in the most efficient manner that we see for our Permian-Garden City asset. At this time, operator, please open the lines for any questions.

[Operator:]

[Operator Instructions] Your first question comes from the line of Brad Carpenter with Wells Fargo.

[Brad Carpenter - Wells Fargo Securities, LLC, Research Division:]

I guess, just starting first on the stacked laterals, I was hoping you could provide us with some more color. I know it's early on, but if you could offer any additional details on those wells, and specifically, if you could touch on costs, and any differentiation between the rates in the 3 different zones, that would be much appreciated.

[Jay P. Still:]

Yes, this is Jay. Yes, it's -- like I said, it's early on. We're encouraged by the peak 24-hour IP. All 3 wells are producing as per their type curve, and the costs were in line with what we expected. So we're really pleased with what we see in those stacked laterals.

[Brad Carpenter - Wells Fargo Securities, LLC, Research Division:]

Okay. And will -- did you see any difference between the rates in the different zones you were completing in?

[Jay P. Still:]

Yes, that's funny. The Lower came on with oil almost immediately. The Upper and Middle took a while, they produced their flowback water a lot longer, pretty much in line with the other Upper and medium -- Middle Wolfcamps. That's the first time we've seen oil that quickly from any of the laterals in Garden City. So that was encouraging. But really, they're performing pretty much in line with their cousins.

[Brad Carpenter - Wells Fargo Securities, LLC, Research Division:]

Okay, great. And then just jumping over to CapEx, does the $725 million for '13 still stand? And I know that's on a divestiture-adjusted basis. And if it does, could you provide us with just an update, or refresh my memory at least, on where you stand on a pro forma basis for -- as of the first 9 months?

[Richard C. Buterbaugh:]

Well, for the year, we still expect to be in the range of $725 million, probably a little bit above that, as we brought -- just from the timing of when the fifth and sixth rigs are expected to come in. Now, but keep in mind that, that reflects -- the actual amount that will appear on our financial statements will include capital expenditures associated with the Anadarko Basin sale, which we were actually reimbursed for through the actual closing process. In addition, that $725 million will be supplemented by the recent acquisition, which we do not budget. And so that $37 million acquisition will be in addition to that $725 million-plus number. But in general, we're still in line for our initial budgeted amount.

[Operator:]

[Operator Instructions] Your next question comes from the line of Gil Yang with DISCERN.

[Gilbert K. Yang - DISCERN Investment Analytics, Inc:]

Could you comment on the Glass-Glass Cline well in terms of was there anything different about that well that contributed to the strong performance? And refresh, what the cost difference is versus the Wolfcamp and to the strong Glass-Glass wells renew your interest in pursuing the Cline more aggressively?

[Randy A. Foutch:]

Well, I'll let Jay answer the specifics. But yeah, we've always viewed that entire section as 2,500, 2,000, 3,000, whatever the number is, feet of section that we needed to work out a development plan for. And so early on, as you know, we were very, very happy with the Cline. As we started drilling Wolfcamp, in fact, well earlier before a lot of people, we recognized that our goal was to figure out how to develop that overall section, Upper, Middle, the Lower and the Cline. And from our view, we never lost enthusiasm for the Cline, we just needed to get data in other zones. So it's not a renewed enthusiasm. It's just that we view that the way to maximize value overall is to develop all 4 of those zones as we go forward. And we've talked about it. At some point, we need to look at some other zones that we know produce well vertically. And so we may wind up with adding to, potentially, the 4 proven zones we have, some other zones. Jay, do you want to comment on that specific well or...

[Jay P. Still:]

Yes. I mean, that well was drilled in Glasscock County. We've had some great Cline results in that area. We will continue to drill Cline wells in our 2014 development plan. The Cline wells are more expensive. They're deeper. They're probably $500,000 more expensive than our Wolfcamp wells. We are getting those current AFEs under $9 million now. So we are making improvements in our drilling costs as we move to pad drilling. But they are more expensive than the Wolfcamp zones.

[Gilbert K. Yang - DISCERN Investment Analytics, Inc:]

So that doesn't sound like there's anything different you did on that well, it's just in a particularly good neighborhood?

[Jay P. Still:]

Yes, we just get good rocks throughout our area, and they continue to deliver.

[Gilbert K. Yang - DISCERN Investment Analytics, Inc:]

Okay. But versus the other, you didn't change the frac design or anything like that?

[Randy A. Foutch:]

Gil, if you go back and look at the data we've pushed out in September and you look at the top wells drilled in the basin, our Cline wells are pretty well-represented in that list. So we're always glad to see our best well drilled to-date, but it don't surprise us in any way that the Cline is a very, very good producer.

[Gilbert K. Yang - DISCERN Investment Analytics, Inc:]

Right, okay. And looking at your DD&A guidance, it looks like it's up -- it's consistent with the third quarter guidance, but it's higher than you printed for third quarter and higher than second quarter. Is that because of the mix of losing the full Granite Wash or is there something else going on?

[Richard C. Buterbaugh:]

No, there's really nothing else going on there and that we look at it on an overall expected annualized amount. Until we get our final year-end reserves, we may adjust it at that point. But at this point, we still think we're still pretty much on track for that. It does impact -- the divestiture of the Granite Wash has impacted just the fact that we are much oil-weighted.

[Operator:]

Your next question comes from the line of Ipsit Mohanty with Canaccord.

[Ipsit Mohanty - Canaccord Genuity, Research Division:]

You mentioned about drilling the Wolfcamp in North Glasscock. Would that change your risking of your Wolfcamp acreage? I believe it was about 51% that you were disclosing Analyst Day.

[Randy A. Foutch:]

Can you repeat the question? I'm not following what you're saying.

[Ipsit Mohanty - Canaccord Genuity, Research Division:]

I'm sorry. But you mentioned in your Analyst Day that you've derisked about 50-odd percentage of your Wolfcamp, and I am wondering if -- in your press release you've stated that you're going to drill a new Wolfcamp in your northern Glasscock as a part of your lateral extension. Will that -- successful results of that, will that change your derisking of the Wolfcamp acreage?

[Randy A. Foutch:]

That's a great question. The answer and the way we look at that is, we said early on that 2012, our goal was to delineate enough acreage to really focus in and prove-up enough acreage to really know that we had some of the best acreage out in the basin. And we kind of succeeded in that. That was the reason for the outspend in '12 and so on and so forth. And our stated goal in 2013 was to principally figure out the most cost-efficient and best way to develop these multilateral, and figure out the pad-drilling process and, along with that, finish delineating to some degree the acreage that we hadn't tested and some of these other zones that we hadn't tested. So I think that -- I think the message that you should take away is that we're really concentrating on the development plan, and it will take us some time before we finish delineating and derisking the full extent of that acreage. But you need to keep in mind, the way we defined that delineation was, commercial, horizontal, production. We've got vertical wells all over it. We've got great core data. We've got great 3D data. We've got single-zone testing. We have a pretty high view of all of our acreage, and we'll slowly over time get with it. And I think, as an example, in one of our northern areas, we've done some drilling, and I think we'll start those completions pretty soon. And that'll give us some answers on some more of the derisking, but I think the derisking process is going to be methodical over the next couple of years. Jay, you want to add anything to it?

[Jay P. Still:]

No. Like Randy said, we just finished drilling a Wolfcamp well in the northern part of Glasscock, and we'll probably start the completion towards the end of November. We're just rigging down on it now, so that'll give us another data point.

[Ipsit Mohanty - Canaccord Genuity, Research Division:]

And then quick question on downspacing. They say you don't stop downspacing until you hit interference. Now, on your last call, you talked about your downspace wells beating the type curve. I was wondering, given what Pioneer is doing in Upton, Giddings, are there any plans in the near future? I know you've just come out with the downspacing results, but are there any plans to further downspace going forward?

[Randy A. Foutch:]

Our view on that is that, and let's talk about the verticals just a second, our average spacing on our vertical wells is in the order of one well for something slightly less than 200 acres. When we've talked about our upside, we've talked about how many vertical wells we have to drill down to 40-acre spacing, and that's several years of inventory. So for us, I think, we're a little more comfortable saying that we will talk about downspacing over the next couple of years, but I don't feel a lot of pressure to just add a bunch of locations by downspacing. The horizontals are a little bit more interesting in that we have -- as we've talked about, we've done a tremendous amount of work, not only internally, but also with some of the big service providers, on trying to establish what a very, very good initial spacing. All of our data are microseismic. Our joint answer with Halliburton, all of the modeling we've done says that the 120-acre spacing that we talked about at the Analyst Day and previously, which is effectively about 660 feet between a location in each zone, feels pretty good to us. The real answer on the spacing will be at some point in the future. And they way we've set up our physical surface locations and pad, if we feel like we need to go back through and drill a closer spacing, we'll be able to do so. So we're not advocating a lot of downspacing activity. We recognize that at some point, we need to focus on that and downspacing may be important to us.

[Operator:]

Your next question comes from the line of Jeffrey Campbell with Tuohy Brothers Investment Research.

[Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.:]

For my first question, I just wanted to ask you with regard to the stacked pilot that you put out data on today. Does that give you any better line of sight on the cost reductions that you're working towards on pad, or was there still a significant amount of science in this particular instance?

[Randy A. Foutch:]

We did run microseismic in the Upper Wolfcamp while we completed the Middle and Lower, so that adds some additional cost. But -- I mean, we have seen significant reductions in our drilling costs, in line with our expeditions of pad drilling. So we're pleased with the costs, and they'll continue to come down as we continue to repetitively drill these stacked laterals on pads. So, I think, we're -- I'm pleased with where we are and the progress we've made. And Jeffrey, let me just -- we tend to not -- we tend to look at what our average cost is over a series of wells. So for us to start forecasting what we might get a well to at some point down in the future is a little bit of an issue for us. So I think it takes time for us to drive down the way we look at cost.

[Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.:]

And my other question was, why did you choose Reagan County for your first Spraberry horizontal tests? And if you can comment on it, are you going to be drilling more towards the north or towards the south, or what are you doing?

[Randy A. Foutch:]

I think, we have over 800 vertical wells and a huge core -- whole core database. And we recognize that this trend is 80 miles long and 20 miles wide. I think there's potential throughout that entire acreage base. And we picked that location because we liked the geology, not that the rest of it may not be good. But we also picked it a little bit because that's where we have our best infrastructure in terms of handling fluids, including water and gas and oil. So it's a combination of things. I don't think you should view that as necessarily reflecting on the quality of the rest of the acreage yet.

[Operator:]

Your next question comes from the line of James Sullivan with Alembic Global Advisors.

[James Sullivan - Alembic Global Advisors:]

First I had a question here, the first one is on your volume thoughts for Q4 and for 2014. I'm just looking at your guidance for Q4, and I think, even if you guys are at the lower end as you guys have described or guided that you might be at for the quarter, that would still imply something better than 11.5% sequential advance over your Q3 Permian tally. And given that some of the problems in the quarter, volumetric problems in the quarter had to do not just with pad-drilling delays causing lumpiness, but were actual physical problems, fire, pipeline, et cetera, how achievable do you guys feel that Q4 number is? And do you have any thoughts on how the ramp will go in '14?

[Randy A. Foutch:]

Well, as Jay detailed, we have had a couple of operational issues, certainly not reservoir issues, that caused some delay in bringing some of the wells on in the third quarter that have carryover impact into the fourth quarter. The flexibility of our infrastructure certainly gives us optionality regarding the fire that we had at our Reagan station. It did cause some disruption, but not something that we believe is ongoing. The combination of these results, though, we think we will be pretty much right at the bottom end of that range, but still within the initial range that we gave you.

[James Sullivan - Alembic Global Advisors:]

Okay, so that's right around 27,000 BOE a day for Q4?

[Randy A. Foutch:]

Yes.

[James Sullivan - Alembic Global Advisors:]

Okay, great. And then just a follow-up was on the stack programs. So you guys gave this first 3-well stack data, which is great. But I was just curious, can you remind me -- I don't -- I must have it somewhere, but whether those were drilled on a straight kind of plainer stack like one over the other? Or was there some kind of chevron or offsetting going on, #1? And then #2, do you guys have a timeframe for testing some of your other stack configurations? I know you guys talked about doing 2-well stacks or ones in which you'd be testing other zones, including the Cline, like an upper in the Cline or maybe even the Spraberry and a Wolfcamp lateral, something like that? And I'll take it offline.

[Randy A. Foutch:]

Yes. No, the stack configuration was not a chevron. It was essentially on top of each other. Outside of the 25-foot wellhead spacing, they're essentially on top of each other. And currently, we are testing -- we're drilling -- all of our horizontal wells are drilling on pads, multi-wells on pads, and some of those are drilling north Uppers and north Upper -- north upper-Middles, south upper-Middles from staggered pads to we got another rig that's drilling an Upper and a Cline. So all of our rigs are drilling pads in different configurations.

[Operator:]

Your next question comes from the line of Kerr Friedman with Simmons & Company.

[Kerr Friedman - Simmons & Company International, Research Division:]

Yes, obviously, this earnings season, Cline wells have been pretty strong both for you guys and also to the West. I'm curious to hear your thoughts on how the interval may change West to East.

[Randy A. Foutch:]

We've consistently, I think, said that we put our bio [ph] line together based upon what we wanted to be in the center of the depositional basin; in other words, the deepest part of the basin at the time of deposition. I think there is a lot of evidence to suggest that we pretty well bought our acreage there. Clearly, as you go east, you're starting to come out of the basin and there are some changes that occur. And also, the current deepest part of the basin is to the west. But we see changes, but we've all along thought we bought at the thickest, most organic-rich part of that entire 2,000, 2,500-foot section, and we kind of like where we are.

[Kerr Friedman - Simmons & Company International, Research Division:]

Yes, great. I think that there's definitely reason to feel that way, so congrats there. And then as a follow-up, thinking towards how difficult or easy it is to access water in the Permian currently, and then if you could provide any color on how you kind of see that trending next year?

[Randy A. Foutch:]

I'll take first crack, and then I'll let Jay talk a little bit about how we're doing a bunch of infrastructure work on the water. And I think -- I mean, I've talked a little bit about how, I think, over time water is going to be precious to all of us in these plays and other places. And we're actually in a part of the Midland Basin to where we're in really good shape on water. We've got a couple of not potable, but not too salty water sources, potentially. We've been doing a lot of work on trying to figure out how best to recycle, reuse water. We're not -- I think, long term, water is an issue for all of us, but short term, we're in really good shape. And Jay, you want to talk about our...

[Jay P. Still:]

Yes, water is going to be a big part of our business. To a lot of people, we're going to be a water company with a petroleum byproduct, so we're planning for that. In all of our development areas, we are putting in pipeline corridors or offtake of oil and gas, and water. We're building -- in the process of building some very large reprocessing or water processing pits that we can reuse a lot of our flowback and produced water. In these corridors, we have pipes that go back to take water back into the drilling areas, so that we can tap in locally to complete our wells. All of our pits are daisy-chained together, so that we can accumulate water to any parts of the field where we have completion operations going on. So we've got a significant amount of investment being made right now to address water issues as our drilling intensifies in the future. But -- and as Randy mentioned, we've got San Andres water that we use from some really good water source wells in the San Andres, which is non-potable water. But more and more of our water is non-fresh and will be reprocessed water.

[Operator:]

Your next question comes from the line of Sven Del Pozzo with IHS.

[Sven Del Pozzo - IHS Herold, Inc.:]

It's Sven Del Pozzo. Again, you have Pioneer talking about those wells to the West, but they did decline. They fell off de-Cline. They did fall off pretty quick in the first month compared to the 24-hour rate. So I was wondering, do you think that's a function of depth? Or I'm sure it's more complicated than that, and I'd like to know what your opinion, if in your area you've experienced shallower declines; and if anything can be done in the completion procedure to modify those declines, or whether you feel that you've optimized it at this point?

[Randy A. Foutch:]

Well, I think the optimization process, we've done a lot of -- I think that goes on for a long time. I don't think any of us believe that we've perfectly optimized the wells. And I think -- I'm not going to comment on Pioneer's. And I think -- we tend to think in terms of 30-day or 6-month or even 2-year production as a company, because that kind of helps us see the decline. But the point that I would like to leave you with, and I'll see if Jay wants to make any, we've seen -- we've not seen any reason yet to change our type curves and our EURs on the Cline.

[Jay P. Still:]

I think one unique -- as Randy mentioned earlier in the call, we're in the deep, thickest part of the Cline. One thing of significant note of the Cline well that we've reported on our best Cline to-date, that 30-day average rate is that well still flowing up-casing. So normally, these wells come on natural flow. They'll eventually -- pressure will decline eventually where we'll run tubing and put them on gas lift. So that well, that IP and that 30-day rate are all from natural flow, which is significant in our area. It's very unlike a lot of other areas in the basin.

[Sven Del Pozzo - IHS Herold, Inc.:]

So basically, the Cline portion of your Wolfcamp interval is actually, it deepens as you move from west to east, compared to about 50 miles west of you guys where some of those wells were reported yesterday?

[Randy A. Foutch:]

Let's -- first off, the Cline is not part of the Wolfcamp, in our view. It's separated from the Wolfcamp by a 300 or 400-foot thick shale, so. And we really do tend to focus on what's happening within our acreage base.

[Sven Del Pozzo - IHS Herold, Inc.:]

Okay. Secondarily, with -- you've got a lot of vertical wells. Just generally, would you say that -- like how often are you horizontally developing zones that were actually completed in a co-mingled vertical format? Or, are you guys drilling -- developing something horizontally that's bypassed in the vertical development format? And then if you could answer that, that'd be great. That'll be it.

[Randy A. Foutch:]

In our vertical program, we're still running 5 and 6 rigs, and that with the lack of density on any drilling on some of our acreage, we're using that for data and continuous drilling obligations and so on and so forth. And in the vertical wells, we're effectively completing from the Atoka, Strawn, Ellenburger, the deepest we drill, all the way up through the Cline, Wolfcamp and Spraberry. So the vertical wells are basically completing the entire section for us. The horizontal wells, of course, we're picking one of those zones, Wolfcamp A, B or C, or dropping down to the Cline or whatever, and drilling the horizontal well in that zone. So it's a one-zone completion. And we're very pleased with the way that whole process is working for us.

[Sven Del Pozzo - IHS Herold, Inc.:]

So it is the same -- it's the same zone that you complete in a vertical format, just horizontally?

[Randy A. Foutch:]

Yes.

[Jay P. Still:]

Yes, the real -- as Randy said, when you complete all the way up that vertical well, your draining radius of that vertical well is just not that big compared to drilling a 75, 100-foot lateral in, say, the Middle Wolfcamp, and you've got a vertical well that may be producing nearby in the Middle Wolfcamp. Our main issue with the vertical wells and our horizontal wells is not depletion or interference in the zone, it's interference in the wellbore. So it's collision avoidance of vertical wells with our horizontals, but really see no production implication from vertical wells to the horizontal wells.

[Operator:]

[Operator Instructions] Your next question comes from the line of John Herrlin of Société Générale.

[John P. Herrlin - Societe Generale Cross Asset Research:]

Did you have any wells needing to be completed in the quarter that were inventoried at all?

[Jay P. Still:]

Yes, the question is do we have wells waiting on completion in the third quarter that will be completed in the fourth quarter?

[John P. Herrlin - Societe Generale Cross Asset Research:]

Correct.

[Jay P. Still:]

Yes, and there will -- probably quarter-to-quarter, we'll have wells waiting to be completed in that quarter that'll jump over to the next quarter. And that's going to drive the lumpiness of our production. And you bring wells on the last week of the quarter versus the first week of the next quarter makes a difference in your production rates. But right now we've got I think -- I'm just kind of running through the list, I think we've got 7 horizontal wells waiting -- in the process of being completed on pads or waiting their turn to be completed, that will come on in the fourth quarter.

[John P. Herrlin - Societe Generale Cross Asset Research:]

Okay, great. In your release, you mentioned that you were looking at the Lower Spraberry and the Middle Wolfcamp. Any other members or zones that you're also going to try testing as you extend your boundaries?

[Randy A. Foutch:]

We've... Thanks. That's the great question. We've -- with our 3D, we've talked about in the past and mentioned that at some point we need to go look at the Fusselman and Ellenburger in the vertical wells. We're starting to kind of work that into our plans and seeing some activity there. I think, if you look at us near term, we're probably concentrated in that ABW section and the Spraberry. But, John, we have a tremendous thick section of organic-rich shales to look at there that have the right maturation for oil. And when we think with our exploration geology hats on, we see lots of other zones that at some point we've got to go test. I don't think those are coming up any time soon. But I think, over time, this acreage base has lots of things that has great potential.

[Operator:]

I would now like to turn the presentation back over to Mr. Ron Hagood for closing remarks.

[Ron Hagood:]

Thank you, all, very much for your time and interest in Laredo this morning, and this concludes our call.

[Operator:]

Ladies and gentlemen, this concludes the presentation. You may now disconnect. Have a great day.