Vital Energy Inc (VTLE) 2013 Q3 法說會逐字稿

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 will 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.

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 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 reference 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 two-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 three-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 the companies that report on a three-stream basis. Similarly, Laredo's unit cost metrics will appear higher when compared to companies that report on a three-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 will turn the call over to Randy Foutch, Chairman and Chief Executive Officer.

Thanks, Ron and good morning everyone. 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 multi-zone development plan for the Permian-Garden City asset from both an operational and financial perspective. 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 three stacked laterals that, coupled with our horizontal spacing test last quarter, will significantly enhance our understanding of the most efficient and scalable multi-zone development program. Additionally we will remain focused on delineating our initial four 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 four 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 will turn the call over to Jay Still, President and Chief Operating Officer for an operational update.

Thank you, Randy. 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 six horizontal wells with five 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 three-stream rates and reiterate our expected EURs from each zone. There were two wells completed in the Upper Wolfcamp, Glass-Glass 10 #152HU and the Bodine-C-30-1HU.

The Glass-Glass achieved a three-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 a day. The Bodine achieved 3-stream rates of 1,586 barrel of oil equivalent per day, and 836 barrel oil equivalent per day. Our Upper Wolfcamp three-stream type curve is 924,000 BOEs.

There were two Middle Wolfcamp wells we completed in the quarter, the Sugg-B-131/Holt E 2HM and the Bodine-C-30-2HM. The Sugg-B had at three-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 day.

The Bodine achieved a three-stream rate of 1,106 barrel of oil equivalent per day, and 605 barrel of oil equivalent per day. Our Middle Wolfcamp three-stream type curve is 793,000 BOEs.

While we had no Lower Wolfcamp completions in the quarter, our three- 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 in the Company with a three-stream peak 24-hour IP of 1,888 barrel of oil equivalent per day, and a three-stream 30-day average IP of 1,408 barrel of oil equivalent per day.

Our three-stream type curve for the Cline is 796,000 BOE, which 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 three-stack lateral test to drill laterals in the Upper, Middle and Lower Wolfcamp zones. We finished completion operations and began flow back 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 two-stream basis or 3,778 barrel of oil equivalent per day on a three-stream basis. This result is in line with respective type curves and we will use the longer term results to fine tune our vertical spacing assumptions for stack horizontal wells.

As we continue our progress in optimizing our multi-zone 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've 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 sidetrack 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 have its completion delayed until the latter part of the fourth quarter.

Additionally, last week there was a fire that destroyed our 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 down time and delays. However, all of these events contribute to production impacts in the third quarter and fourth quarters.

Overall I feel like we have had an outstanding quarter operationally as we continue to improve and refine our oil, gas -- our oil and gas manufacturing process.

I would like to turn it over to Rick Buterbaugh, our CFO.

Thanks, Jay, and good morning. Our quarterly results once again were basically in-line with expectations for production, pricing and overall unit costs 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 had prepared to ramp up our 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 equivalent.

Additionally, non-cash stock based compensation expense increased approximately $1.4 million from the second quarter of this year, primarily associated with the recent appreciation in Laredo 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 pre-fund a portion of our 2014 capital program.

Today, 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 are collared with the 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 will 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 multi-zone 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 Instructions)

Your first question comes from the line of Brad Carpenter with Wells Fargo.

Hi. Good morning, everyone. Thanks for taking my question.

Good morning.

I guess, starting first on the stacked laterals, I was hoping you could provide us with some more color. I know it's early on. 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 three different zones, that would be much appreciated.

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

Okay. Did you see any difference between the rates in the different zones you were completing in?

Yeah, it's funny, the Lower came on with oil almost immediately but the Upper and Middle took a while. They produced their flow-back water a lot longer, pretty much in line with the other Upper and medium -- Middle Wolfcamp. That's the first time we have seen oil that quickly from any of their laterals in Garden City, so that was encouraging. But, really, they are performing pretty much in line with their cousins.

Okay. Great. And then jumping over to CapEx, does the $725 million for 2013 still stand? I know that's on a divestiture-adjusted basis. And if it does, could you provide us with an update or refresh my memory at least on where you stand on a pro-forma basis as of the first nine months?

For the year we still expect to be in the range of $725 million, probably a little bit above that as we brought -- from the timing of when the fifth and sixth rigs are expected to come in. But keep in mind that that reflects the amount that will appear on our financial statements will include capital expenditures associated with the Anadarko Basin sale which we were reimbursed for through the 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. In general, we are still in line for our initial budgeted amount.

Okay. I appreciate it. Thank you much.

(Operator Instructions)

Your next question comes from the line of Gil Yang with Discern. Please proceed.

Good morning, everyone.

Good morning, Gil. How are you?

Fine, thanks. 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 in first the Wolfcamp and did strong Glass-Glass well renew your interest in pursuing the Cline more aggressively?

I will let Jay answer the specifics. But we have always viewed that entire section as 25, 2,000, 3,000 whatever the number is, feet of section that we needed to work out a development plan for. 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, 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 that we view the way to maximize value overall is to develop all four of those zones as we go forward, and we have talked about it at some point we need to look at some other zones that we know produce well, vertically. So, we may wind up with adding to potentially the four proven zones we have, some other zones. Jay, do you want to comment on that specific well?

Yeah, 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.

So, it doesn't sounds like there is anything different you did on that well, it was just in a particularly good neighborhood.

Yeah, we just got good rocks throughout our area and they continue to deliver.

Okay, but versus the others, you didn't change the frac design or anything like that?

Gil, if you go back and look at the data we 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 are always glad to see our best well drilled to date, but it doesn't surprise us in any way that the Cline is a very, very good producer.

Right, okay. Looking at your DD&A guidance, it looks like it's up consistent with 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?

No, there is 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 are 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 more oil rated.

Okay. Great. Thanks.

Thank you.

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

Good morning, guys.

Good morning.

Good morning. 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 are disclosing and listing.

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

I'm sorry. You mentioned on Analyst Day that you've de-risked about 50-odd percentage of your Wolfcamp. I'm wondering if -- in your press release you've stated that you want 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 data scheme of the Wolfcamp acreage?

That's a great question. The answer and the way we look at that, 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 succeeded in that. That was the reason for the out spin in 2012, and so on and so forth. 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. I think the message that you should take away is that we are really concentrating on the development plan and it will take us some time before we finish delineating and de-risking the full extent of that acreage.

But you need to keep in mind the way we defined that delineation was commercial, horizontal, production. We got vertical wells all over it. We got great core data. We've got great 3-D data, we've got single zone testing. We have a pretty high view of all of our acreage and we will slowly, over time, get with it. I think as an example, in one of our northern areas we have done drilling and I think we will start those completions pretty soon. That will give us some answers on some more of the de-risking. But I think the de-risking process is going to be methodical over the next couple of years. Jay, do you want to add anything?

Like Randy said, we just finished drilling a Wolfcamp well in the northern part of Glasscock and we will probably start the completion toward the end of November. We are just rigging down on it now. That will give us another data point.

All right. Thank you for the details. And then quick question on down-spacing. They say you don't stop down-spacing until you hit interference. On your last call you talked about your down space was beating the type curves. 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 down-spacing results but are there any plans to further down space going forward?

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 are a little more comfortable saying that we will talk about down-spacing over the next couple of years, but I don't feel a lot of pressure to add a bunch of locations by down-spacing.

The horizontals are a little -- a little bit more interesting in that we have, as we've talked about, we have 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, our micro-seismic, our joint venture with Halliburton, all of the modeling we have 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. The way we've set up our physical surface locations and pads, if we feel like we need to go back through and drill a closer spacing, we will be able to do so. We are not advocating a lot of down-spacing activity. We recognize that at some point we need to focus on that and down-spacing may be important to us.

Great, thanks for the color.

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

Thank you, good morning. 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 site on the cost reductions that you are working towards in pad or was there still a significant amount of science in this particular instance?

Well, we did run micro-seismic in the Upper Wolfcamp while we completed the Middle and Lower. That adds some additional costs. But, we have seen significant -- the reductions in our drilling costs in line with our expectations of pad drilling. So we are pleased with the costs. They will continue to come down as we continue to repetitively drill these stacked laterals on pads. I'm pleased with where we are and the progress we've made.

Thanks.

Jeffrey, let me just -- we tend to -- 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. I think it takes time for us to drive down the way we look at costs.

Thank you. My other question was why did you choose Reagan County for your first Spraberry horizontal test, 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? Thank you.

You know, I think we have over 800 vertical wells and a huge core [lat] -- whole core database. And we have recognized this trend is 80 miles long, and 20 miles wide. I think there is potential throughout that entire acreage base. 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.

Okay. Thank you.

Your next question is from the line of James Sullivan with Alembic Global Advisors. Please proceed.

Hi guys. Good morning.

Good morning.

I had a question here. First one is on your volume thoughts for Q4 and for 2014. I'm 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. 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 2014?

As Jay detailed, we have had a couple operational issues, certainly not reservoir issues that caused some delay in bringing some of the wells on in the third quarter that have a 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. A combination of these results that 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.

Okay. So that is right around 27,000 BOE a day for Q4?

Yes.

Okay. Great. And then the follow-up was on the stack programs. So you guys gave this first three well stack data which is great. But I was curious, could you remind me, I must have it somewhere, but whether those were drilled on a straight, plainer stack, like one over the other? Or was there some kind a Chevron or offsetting going on, number one? And then number two, do you guys have a timeframe for testing some of your other stack configurations? I know you guys talked about two-well stacks or ones in which you would be testing other zones including a Cline, like an upper in a Cline, or maybe even a Spraberry and a Wolfcamp lateral, something like that? Then I will take it off line.

No, the stack configuration was not a Chevron. It was essentially on top of each other, outside of the 25-foot well head spacing, they are 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 -- North Upper Middle, South Upper Middles from staggered pads to -- we've got another rig that is drilling an Upper and a Cline so that all of our rigs are drilling pads in different configurations.

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

Good morning, guys.

Good morning.

So obviously this earnings season the Cline wells have been pretty strong, both where you guys are, and also to the west. I'm curious to hear your thoughts on how the interval may change, west to east?

We've consistently said that we put our buyout line together based upon -- 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 are 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. We see changes but we have all along thought we bought at the thickest, most organic-rich part of that entire 2,000, 2,500-foot section. We kind of like where we are.

Yeah, great. I think there is definitely a 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 see that trending next year?

I'll take first crack then let I'll Jay talk a little bit about how we are doing a bunch of infrastructure work on the water. I think I have been -- 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 are actually in a part of the Midland Basin where we are in really good shape on water. We got a couple of ,not potable but not too salty, water sources potentially. We have been doing a lot of work on trying to figure out how best to recycle, reuse water. We are not -- I think long-term water is an issue for all of us. But short term we are in really good shape. Jay, do you want to talk about --

Water is going to be a big part of our business. I keep telling a lot of people that we're going to be a water company with a petroleum byproduct. So we are planning for that. In all of our development areas, we are putting in pipeline corridors for off-take 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 flow back 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. And as Randy mentioned, we've got San Andreas water that we use, some really good water source wells in the San Andreas which is non-potable water. More and more of our water is non-fresh and will be reprocessed water.

That's helpful. Thanks, guys.

Your next question is from the line of Sven Del Pozzo with IHS. Please proceed.

How are you doing?

Good morning.

It's Sven, Sven Del Pozzo. Anyway, again you have Pioneer talking about those wells to the west, but they did decline, they fell off, decline, 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. I would like to know 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 have optimized it at this point?

I think the optimization process we have done a lot of -- I think that goes on for a long time. I don't think any of us believe that we 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 six month or even two-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, then see if Jay wants to make any -- we have not seen any reason yet to change our type curves and our EURs on the Cline.

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

So even though -- so basically the Cline portion of your Wolfcamp interval is actually -- it deepens as you move from west to east compared to well, 50 miles west of you guys where the wells were reported yesterday?

First off, the Cline is not part of the Wolfcamp in our view. It's separated from the Wolfcamp by 300 or 400-foot thick shale. So -- and we really do tend to focus on what is happening within our acreage basin.

Okay. Secondarily, you've got a lot of vertical wells. Just generally, 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? If you can answer that, that would be great, that will be it.

In our vertical program, we are still running five and six rigs, and with the lack of density on any drilling on some of our acreage, we are using that for data and continuous drilling obligations and so on and so forth. And then those vertical wells, we are effectively completing from the Atoka, Strawn, Ellenberger, 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 are 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. We are very pleased with the way that whole process is working for us.

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

Yes.

Yeah, the real -- as Randy said, when you complete all the way up that vertical well, your drainage 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 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. It's collision avoidance of the vertical wells with our horizontals. But really see no production implication from vertical wells to the horizontal wells.

All right. Okay. Thank you.

Thank you.

(Operator Instructions)

Your next question comes from the line of John Herrlin of Societe Generale. Please proceed.

Yeah, hi guys.

Good morning, John.

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

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

Correct.

Yes. And we will probably, quarter to quarter, we will have wells waiting to be completed in that quarter that will jump over to the next quarter. That going to drive the lumpiness of our production -- we bring wells on the last week of the quarter versus the first week of the next quarter. You know, it makes a difference in your production rates.

Okay. Got it.

Right now we've got, I think -- just going, running through the list, I think we've got seven 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.

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 are also going to try testing as you extend your boundaries?

Thanks, that's a great question. We have -- with our 3-D, we've talked about in the past and mentioned it at some point, we need to go look at the Fusselman and Ellenberger and the vertical wells. We are starting to work that into our plans and seeing some activity there. I think if you look at us near-term we are probably concentrated in the ABW section in 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 have 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.

Great, thanks, Randy.

Thank you, sir.

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

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

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