Vital Energy Inc (VTLE) 2013 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to Laredo Petroleum Holdings Inc second quarter 2013 earnings conference call. My name is DaLou and I will be your operator for today. At this time all participants are in 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, DaLou, 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; and Dan Schooley Vice President of Marketing as well as additional members of our management team. Before we begin, let me remind that during 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 to 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. The value of the natural gas liquids is included in the natural gas stream and pricing, not as part of oil and condensate are 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 would increase by approximately 20%, which you should also keep in mind when comparing to companies that report on a three-stream basis.

Also Laredo's unit cost metrics will look 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 second 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 of $35.8 million or $0.27 per diluted share for second quarter 2013. This includes non-cash, pretax unrealized gains on commodity derivatives of approximately $22.9 million as previously reported. Excluding this net unrealized gain, our adjusted net income was $21.1 million or $0.16 per diluted share. I will now turn the call over to Randy Foutch, Chairman and Chief Executive Officer.

Thanks, Ron, and good morning, everyone. I'm excited as Laredo begins the next chapter of the Company, a company focused purely on the Permian Basin. Posted of closing of the sale of our Anadarko Basin assets that we completed on August 1. We are beginning to accelerate the pace of development of our tremendous Permian-Garden City asset. During the second quarter we made significant progress on our development plan by transitioning three rigs to drilling on multi-well pads and completing the initial side-by-side horizontal testing of 660 foot spacing. As we redeploy capital and personnel through the remainder of 2013, we will add our fifth and sixth horizontal rigs in the Permian Basin and continue to optimize our development plans by drilling tests of stacked laterals in multiple zones from multiple well pads. Some exploration capital expenditures will be directed to extensional acreage and at testing new zones such as the Sprayberry and Atoka. Our disciplined, deliberate and data-driven approach to the development is paying dividends. We continue to drill wells that are among our top performers and some of the best in the Midland Basin. Additionally, we have identified cost savings that can significantly lower per well capital expenditures by the end of 2014. As we progress through the early stages of development of Permian-Garden City, we intend to maintain this discipline to maximize its value. Now I will turn the call over to Jay Still, President and Chief Operating Officer, to update you on our operations.

Thank you, Randy. I've been on the job now for five weeks. I want to start my remarks with how impressed I am with the quality and quantity of Laredo's asset base and the outstanding technical and operations personnel we have working it. It's really great to be here. Operationally, the Company had a good quarter as we grew total production above guidance, held oil production relatively flat as we transitioned three of our four horizontal rigs to multi-well pad drilling. We continue to deliver strong well results and anticipate further reducing our drilling and completion costs by the end of the year. During the second quarter we completed seven wells, six having enough data for an average 30 day IP rate. The results are detailed in our earnings release this morning.

I'd like to highlight one of our wells and provide some additional insight on our initial side-by-side horizontal test at 660-foot spacing between the laterals. The Lane Trust well is a horizontal well drilled into the Lower Wolfcamp in southern Glasscock and northern Reagan Counties. On a two-stream basis it posted a 30 day IP rate of 1,217 barrel oil equivalent per day, a Company record for the Permian horizontal. For comparison to other operators, a peak 24-hour rate on a two-stream basis of our Lane Trust well went 1,912 barrel of oil a day and on a three-stream basis it was 2,148 barrel of oil equivalent per day. Not only is this the best Permian horizontal for Laredo but I believe it's among the best in the Basin. The side-by-side test is the culmination of a joint modeling and development planning project with Halliburton. The project uses Laredo's well results for a more than 250 deep vertical and more than 70 horizontals combined with extensive geologic -- geophysical and petrophysical data to develop a proprietary 3D geologic and engineering subsurface model for the Company's acreage.

Aided by the joint modeling effort, we designed the side-by-side test to validate our model of appropriate spacing between the laterals. The results so far have been extremely positive. Both wells involved in the test, Sugg A 143 3 and the Sugg A 143 4, located in Reagan County are performing above our upper Wolfcamp type curve. Based on the production of microseismic data we see no negative interference between the wells. The data fits our model and it is another confirmation of the resource potential in the Permian-Garden City asset. The ongoing modeling project with Halliburton was also used to guide the first test of a stacked lateral well bores in the middle, upper middle and lower Wolfcamp to test vertical spacing and to identify the best landing area within the formations. We expanded this test from two laterals to three and are now finishing the drilling operations on the third well and expect to bring these wells on production by the end of the quarter.

Our transition to drilling multi-well pads results in our stair step production growth for the remainder of the year. Small timing differences can have a huge impact on quarterly production. We currently have six horizontal wells in inventory waiting on associated pad drilling to finish so the wells can be completed and brought on production later in the third quarter. They will have very impactful for a fourth quarter but will contribute very little to the third quarter production. Our dedication to collecting well data in this early stage of development also impacts timing. The process of running additional open hole logs and microseismic add to the cycle time from spud to sales.

While we are cognizant of the increase in the cycle time, we believe it is extremely important information that will be used to most efficiently develop our large resource base for the years to come. Another impact on production of moving into develop mode is the impact of fracking on adjacent wells. Adjacent wells to wells being fracked are impacted for a few weeks before they recover to their original production levels. This is a reality that we have to factor into our production forecasts. Additionally, we have experienced production downtime and additional costs from workover activities in legacy vertical wells. These wells were not isolated in the San Andreas formation and we have seen casing failures caused by corrosion. We are working proactively to minimize these failures.

While I have pointed out some issues that cause lumpiness in our production from quarter to quarter, they should not impact our annual expectations. I would like to reiterate that we are still expecting to have a 25% production growth in our Permian asset for 2013 and even faster growth moving into 2014. Moving onto cost, later -- last quarter we reduced our actual horizontal well costs for all zones and stated there were more reductions to come. We now anticipate that we can reduce these costs by another 10% to 15% by the end of 2014. I believe these further cost reductions are achievable as our current cost estimates do not include any benefit from multi-well pad drilling, they don't include the cost reduction and pumping services we recently negotiated, nor did they include any additional reductions and drilling down times, which our team is very focused on. I would now like to turn the call over to Rick.

Thank you, Jay, and good morning. In total, results for the second quarter were essentially as projected. Total production volumes slightly exceeded the top end of our guidance and unit operating costs and expenses came in at the low end of expectations. These positive factors were offset in part by lower than anticipated realized price premiums on our liquids rich natural gas. As a result, Laredo reported the adjusted net income of $21.1 million or $0.16 per diluted shares for the second quarter and generated adjusted EBITDA of approximately $130 million in cash flow from operations before changes in working capital of approximately $103 million. Before taking a more detailed look at the quarter, I would like to remind you of the financial reporting associated with our recently closed sale of the Anadarko Basin properties and assets.

The sale had an effective date of April 1 but was closed on August 1. Effective at closing, the operations and cash flows associated with the Anadarko Basin properties and assets were eliminated from the ongoing operations of the Company and the Company does not have continuing involvement in the operations of these properties. The oil and natural gas properties that are a component of the sale are not presented as held per sale, nor are the results of operations presented as discontinued operations pursuant to the rules governing full cost accounting for oil and gas properties. The associated pipeline assets and various other associated property and equipment qualified as held for sale as of June 30, 2013. The results of operations of the associated pipeline assets and various other associated property and equipment are presented as results of discontinued operations net of tax in the unaudited consolidated financial statements. Accordingly, the Company has reclassified the financial results and the related notes for all prior periods presented to reflect these operations as discontinued.

Our total daily production for the second quarter was 35,494 barrels of oil equivalent. This is up 13% from the prior-year quarter and up about 2% from the first quarter rate. Excluding the volumes associated with the Anadarko Basin properties, volumes were essentially all Permian and averaged 25,458 barrels of oil equivalent per day, an approximate 25% increase from the prior-year quarter and up approximately 3% from the first quarter rate. You'll recall that we had anticipated this low quarter-on-quarter production growth for the Permian as we began the shift to multi-well pad drilling. As Jay detailed, this creates some lumpiness in our quarterly production growth as the cycle time from these pads increases per spud to first production.

As projected in our guidance that we released this morning for the third and fourth quarters of 2013, we expect Permian quarterly production volumes to grow essentially -- sequentially from the second quarter, approximately 5%, into the third quarter and up approximately 9% in the fourth quarter. In total, we believe we remain on track to achieve approximately 25% production growth from the Permian in 2013 and then there is similar growth rate for total Company oil production despite the sale of the Anadarko Basin properties. Total oil and gas sales for the second quarter of $177 million were up more than 8% sequentially from the first quarter. Although both oil and gas volumes and prices were slightly higher in the second quarter versus the first quarter of this year, the realized premium that we received on our liquids rich natural gas relative to NYMEX was only 113%, which was less than anticipated.

This lower than anticipated premium was primarily due to downtime at various natural gas processing plants. Those gas processing plants are currently operating normally and our expectations for the third quarter price realizations for our liquids rich natural gas is in the range of 130% to 140% of NYMEX based upon current strip prices. Operating expense components came in at or below our guidance with total unit operating expense of $36.74 per barrel of equivalent, down from $37.76 per BOE last quarter. I'd like to draw your particular attention to the decrease in lease operating expense, which declined to $6.87 per barrel of equivalent from $7.18 in the prior quarter. As the expanded work over activities from the first quarter were completed, the number of service rigs operating in the Permian-Garden City area were reduced and we believe the benefits from this work over program will benefit unit costs going forward.

During the second quarter, Laredo invested total capital of approximately $178 million but approximately $25 million of this was spent in the Anadarko Basin. Since we are reimbursed for Anadarko Basin capital expenditures incurred after April 1, we plan to redeploy that capital into the Permian Basin by adding a fifth and sixth horizontal rig. With these adjustments, we believe we remain on track for total capital expenditures in 2013 of approximately $725 million as we originally budgeted. With the addition of the fifth and sixth horizontal rigs, we believe the Company will replace the EBITDA associated with the Anadarko Basin properties by midyear 2014. Keep in mind that these rigs will likely be drilling multi-well pads and the cycle time from spud to first production will be extended, creating the stair step growth not only in production but also in EBITDA. Looking forward, our preliminary plan for 2014 is to retain the six horizontal rigs throughout the year. This activity, coupled with our vertical program of five rigs plus the associated facilities and gathering infrastructure, implies a capital spend rate for 2014 in the range of $900 million to $1 billion.

However, we do not expect to finalize our 2014 program and capital budget until late this year. Using this preliminary capital investment rate for 2014, we anticipate an annual production growth rate of more than 30% on a divestment-adjusted basis. We believe that our existing liquidity and growing cash flow will more than be adequate to fund this growth. As mentioned, we closed the sale of the Anadarko Basin properties on August 1 and used the proceeds to completely repay our senior secured credit facility. Today this facility, which has a borrowing base of $825 million based upon our December 2012 reserves is undrawn and fully available to the Company. We expect that this borrowing base will increase over time as we continue to expand our proved reserves.

Our next redetermination of the borrowing base will be in the November timeframe and include the strong results of our drilling program through June 30. Today our total debt less cash is approximately $1 billion or about 2.6 times the trailing 12 months EBITDA from just the Permian Basin. This is a metric that we are very comfortable with today and we expect to be able to reduce this multiple over time as we methodically grow our EBITDA. As detailed in this morning's news release, we have provided guidance for the third and fourth quarters of 2013. Keep in mind that the guidance for the third quarter includes one month of operations from the Anadarko Basin while guidance for the fourth quarter fully reflects the Anadarko Basin divestment.

Post the sale of the Anadarko Basin, our production volumes will be approximately 60% crude oil, up from about 44% in the second quarter. This is expected to drive higher realizations on a BOE basis that will be offset in part by higher unit operating expenses, although the net -- they will net into a higher cash margins on a BOE basis. In addition, keep in mind that Laredo maintains an active derivative program and we have hedged approximately 76% and 68% of our anticipated oil production for the third and fourth quarters of 2013, respectively, at a weighted average floor price of slightly above $85 per barrel. We also have floor protection on our expected natural gas production for the third and fourth quarters covering approximately 54% and 49%, respectively, at a weighted average floor prices of about $3 per MCF. In summary, we believe we have made significant progress through the first half of 2013, both operationally and financially that well positions the Company to capitalize on the growth opportunities that we have uncovered in the Permian Basin. At this time, operator, we would like to open the lines for any questions.

Thank you.

(Operator Instructions )

Ryan Oatman, SunTrust.

Hi, good morning.

Good morning, Ryan.

I wanted to follow-up on the prepared remarks on 2014, understanding it's preliminary. I just wanted to make sure I understood correctly. Assuming a $900 million to $1 billion capital plan in 2014, the Company would expect for 4Q 2014 volumes to be up approximately 30% over the 4Q 2013 volumes. Is that a fair summary there?

That's roughly in line on a year-over-year basis looking at just the Permian Basin in 2012 -- or 2013 versus 2014, we would expect it up about 30%.

Got you. So that's just the Permian there. Okay. Okay. And I was encouraged to see the Company's shift about 50% -- 15% of capital to testing new zones and areas. Can you speak more specifically about your exploration plans for the back half of 2013?

Ryan, we feel like we have years and years of work already identified on our acreage with our drilling to date. We have a lot of data, we have got 3D over our acreage, we've got a number of vertical wells, I think it 800 or so complete over the entire acreage base, so we think we have a lot of additional extensional, I don't want to call it pure exploration to do, we have a lot of data that supports it. But given the huge inventory of things that we've already captured, I'm not sure how aggressive we are going to be about extending our knowledge of that acreage with horizontal wells. We do intend to probably look at Sprayberry zone this year, I'm not sure that Atoka is 2013 but it's -- we know at some point we've got to do it and at some point we have pretty strong support from our database that we need to drill horizontal wells on some areas that we haven't drilled yet. So, I think 15% for us looks to be about the right cadence for the next year or two. Probably test the Sprayberry, not sure what else we will do.

Got you. That's helpful. So I take it in the vertical wells that you have drilled, the Sprayberry I guess looks the most prospective and then maybe you'd put Atoka after that if that's a fair characterization. What about China Grove? Any plans to get after that acreage again?

Let me just make a comment that the fact that we are focusing on the Sprayberry first does not diminish our enthusiasm for some of the other zones. It has more to do with how we think about developing our development plan and how we view the data we need to start really figuring out how to drill multiple horizontal wells off the pad. The Sprayberry looks pretty good but I don't want to take away from some of the others zones.

Understood.

We've said pretty consistently that for us to put a lot of our capital in the China Grove and the Dalhart Basin and some of the other areas, they've got to compete in terms of capital efficiency and rate of return and economics with Garden City. And what we are seeing is that Garden City is continuing to look good. We have some wells that are significantly better than our model so I don't anticipate the Company putting a lot of capital into China Grove or for that matter the Dalhart. And at some point we have to make a decision about what we do with that acreage. We are not ready to do that yet.

Got you. And then one last one for me on the northern part of your Garden City acreage, do you see the Wolfcamp A, B and C as prospective and you have any tests planned on that acreage, maybe in the back half of this year in early 2014?

That's kind of the answer that I gave on terms of the 15% that we're spending in exploration/extension/derisking. I don't know how aggressively we are but we know at some point we've got to go with the support of our vertical well drilling and our 3D. We do need to get up there and drill some horizontal wells more than we've done.

Got you. Thank you. That's it for me.

(Operator Instructions ).

Will Green, Stephens Inc.

Good morning, guys.

Good morning, Will.

I wonder if we could expand on that with the Atoka and I know you've talked a lot about it but you guys do have a lot of vertical wells as you mentioned down there. How does the Atoka look on a thickness standpoint across your acreage and how do you view it from, say, and oil-in-place basis versus the Wolfcamp?

I think the way we look at that is that we have a fair bit of data and not just Atoka but perhaps Strawn. We know there is some Fusselman production. We have a lot of data on the Sprayberry and we have been saying now for several quarters that at some point we are going to have to start the process of evaluating those with something other than vertical single zone tests and so on and so forth. And so I don't think we view the process as anything that we have not been talking about for probably a year or so ago. The oil in place numbers are -- the thickness is somewhere 350 feet, 400 feet or so. Pat, is that about right?

Yes.

And you know the oil in place numbers which again I think we've stated that on a resource play you want to have plenty of oil in place but I'm not sure how meaningful that is in terms of what the wells actually will do and it's got plenty of oil in place, 30, 40, 50 million barrels, 45, 55 million barrels per section. But again I'm not sure that's a critical number.

Got you. And then from a vertical standpoint, do you guys have any guess as to what the contribution on an average Wolfberry well is? Do you think you're getting most of the contribution from the Wolfcamp and that's the reason it's been the most productive zone to date? It sounds like you guys feel pretty strongly about the Sprayberry and we've obviously seen some pretty good industry Sprayberry wells so far. How do you guys think about that in terms of a productivity on a vertical well bore if there a --?

I will let Jay back me up on this if I -- but we -- as you know, we've tested many of these zones in the single zone completion in a vertical well. In other words we'll drill of vertical well instead of testing -- producing the entire section we would stop and test one zone, frac it, 30, 60, 90 days, some cases longer. And so we have a pretty good database on what zones contribute. We've also talked about how over this 80-mile long acreage base there will be some variances although it's consistently pretty consistent depositionally. We've seen a few areas where the Sprayberry tests very well, we've seen a few areas where the Wolfcamp is stronger, we have seen a few areas where the Atoka has been pretty nice. But overall the point that we would like to -- the way we look at it is so far we have proven up something like 1,800 feet of shale that is a resource play with the A, B, C Wolfcamp and Cline. We know that the Sprayberry produces very well. We know that the Atoka produces. So our job and for that matter we do have some Strawn production out there in a couple of horizontal wells. So our view is that we have got to take this 1,800 feet and expand on it, our knowledge base and add to that as we think through our development plan. Jay?

I agree, Randy, as you mentioned we've got 20 miles, close to 90 miles of area to delineate. And there's 3,700 foot of resource between the Sprayberry and the Atoka [bin], so there's a lot of resource in the Permian Basin. We had done some recent single zone testing of our Sprayberry formation in Reagan County and are extremely encouraged and that's why we will be picking up a rig in September and the first well we will be drilling is a horizontal test into Sprayberry. But it's just another one of the many zones that look very prospective and we are developing horizontally.

That's great to hear, I appreciate all that color, guys. Thanks. That's it for me.

Thank you.

John Herrlin of Societe Generale

Yes. Hi. Sugg wells you've had better initial results. Any sense of where the EURs is going?

We -- on -- you kind of know how we view changing our economic model and AFEs and EURs and I think as we -- we're very pleased that they are performing as well as they are. We have stated more than one time that one or two wells does not make a play good or bad. And I think the answer to that is as we start working on our 2014 budget or as we finish the work on the 2014 budget, we will probably want to look at EURs and AFEs and if we -- we'll update those and if we need to adjust we will adjust them then. So we are very happy with the results of those wells.

Well it was worth a shot. Regarding your stacked laterals on pads, do you have any sense of aerial spacing, what kind of spacing you'd have between wells if you had multiple stack pay developments? Would it still be 660?

I will let Jay take the first crack at that.

Yes, we feel pretty comfortable on the 660 spacing. It's a -- we did a lot of work in our earth model simulations and geophysical studies to land on the 660 and have empirically proven that up with our side-by-side sugg wells and so we feel really comfortable with the 660. Now we are working on development of, is that three stack, four stack, the order you drill those in, pad design all those intricacies as you launch rigs into pad development that are critical optimize and capitalize on the cost efficiencies that you can gain from pad drilling.

Okay last one for me is on the Mercer well, is it too early to not condemn but throw caution on the middle Wolfcamp giving your upper and lower results. That's it, thanks.

No, we don't think it's too early at all. We've always given you good news and bad news. The Mercer well is -- in fact it's too early for our view to really understand it ourselves. It's a long way from any existing production but some of our better wells out there are middle Wolfcamp wells so I don't view it as -- Yes, I wish it was a better well but I certainly am not prepared to say that it in any way influences our view over most of the middle Wolfcamp.

Great, thank you.

Thank you.

Dan McSpirit of BMO Capital Markets.

Thank you, folks. Good morning.

Good morning, Dan.

If we could just touch on capital efficiency and maybe rate of change here. It appears that production rates are improving or at the very least becoming more consistent all on lower costs. Is that rate of change expected to slow any time soon or do you believe you are in the early innings of driving better returns and margins and maybe in answering that question maybe if you could speak to drilling and complete costs here going forward.

Yes, Dan, the -- and that's where we touched on efficiencies of pad drilling. The simple things in pad drilling, you remove your mode and de-mode costs. All the rigs that we have are walking rigs where you can drill all your vertical sections at once with the same mud systems, change mud systems out, drill all your horizontal sections in series. And so there's just efficiency drives a lot of cost savings from on the pad work. On the completion side you start moving to zipper fracks where you are completing two or more wells at once while you are fracking one well and you're doing plugs and doing wire line work on the next and you have manifold, you switch back and forth. And all of those drive cost reductions through time improvement. So those simple tangible things in pad drilling will continue to drive costs down. And at the same time when you're -- when you start moving into pad drilling and drilling stacked laterals or adjacent laterals you can really work on efficiencies in single areas and you can start optimizing your completion designs because you can start testing and have a lab setup with the rock properties are the same and now you can start optimizing your cluster spacing, your sand, your carrying fluids, all those kinds of things can have tremendous impact in your production. That's the benefit of moving into pads to -- as we're going to see going forward. So that's why I'm really comfortable that we can drive down our drill and complete costs.

And you would describe your effort where it stands today as being in the early innings, is that a fair assessment?

I think we are just starting on our first -- finishing up our first stacked multilateral pad about 80%, 85% of our rig and capital next year will be in stacked laterals on pad drilling so we're in the early innings and expect a lot of improvements from that.

Okay, great, and then as a follow-up, Jay, what did you see at LPI that prompted you to make the move? That is, what did you see at LPI that compares to what Pioneer is drilling in the Midland Basin?

You mean besides me? (laughter)

I'll tell you, well, Randy, of course. Laredo is a -- they kept great, great assets and Midland Basin is -- all the players in the Midland Basin are blessed with great assets, some are going to be better than others. I think at the end of the day how you execute on those assets, you're going to -- the cream is going to rise to the top on that. But [out song a later] just a great opportunity of a growing Company with great assets and great technical staff as I mentioned in my own opening remarks to grow. And Rick is -- you've got to throw him in as well. (laughter) It's been a --

Everybody here is holding their hand up waving. (laughter)

Just been a great ride so far.

Very good, thank you.

Ipsit Mohanty of Canaccord.

Good morning, guys.

Good morning, Ipsit.

If you look at the lower Wolfcamp two wells that you've given, one in April, one in June but a big difference in their 30 day IP. So if you could talk a little but about maybe what you saw in the first well that you maybe implemented in the second, lessons learned from one to the other. And on the same type what is it producing in the Mercer well that's quite not working for it. Thank you.

The Mercer well, I think it's a little too early to -- we don't have 30 days production on it so I'm not want to focus on it very much. The initial production was down some but we don't yet know the decline curve, we don't know yet a lot of things about it so we really don't have any comments other than we just wanted to be 100% fair and point it out that the initial few days of production are less than our curve. Do you want to answer the lower Wolfcamp question between the two wells? I think in general, what we're seeing is some pretty good consistency in terms of being very, very economic wells and highlighting that the thing is working across the board so I don't know how much more we will want to go into comparing one well to another one.

We've got a really large acreage position and all of the -- there's -- although you are in the lower Wolfcamp from the top to the bottom over 90 miles, the rocks change, are slightly different as you move around the basin and that's going to -- goes into our type curves. All of them are great wells economically. Some are going to be enormous wells. But the average of them is what drives the type curve and the type curve in the lower Wolfcamp is extremely economic and a pretty higher return on investment.

And just to point out that the lower Wolfcamp well we completed in April. It's right on type curve. Nothing to be -- we think that's pretty exceptional, pretty good, pretty economic. So the fact that we have a well that's significantly better is good but I'll take either one of those two wells.

Would you have a timing on your vertical lateral stacked results? When would you be comfortable providing some and if it's successful would you still drill the Cline as a part of it or just leave it to the three Wolfcamp zones?

The vertical program I think we are running five rigs and we are going to -- the vertical stacked, oh, I'm sorry.

The vertical stacked, where we're going to bring those. We're going to bring those -- we will have those completed, all of those completed towards the middle of next month. So at the time you bring those on and they cleanup I'm not sure if you're going to have meaningful production data by the end of the quarter. But it's going to be pushing. That's why I don't believe those are going to be impactful for third quarter production, but they will be impactful for fourth quarter. The question on the Cline is -- moves more into an operational question in that operationally is it better to drill all of your stacked potential at once or drill across your acreage position into, say, the top two or the bottom two benches that you want to develop. We are still working on that and that will be something that we will probably have a better answer for by the end of this quarter.

Great, thanks. I will stick to the two queue -- two question rule and leave it at that.

Thank you.

Joe Allman of JPMorgan.

Good morning.

Good morning.

This is Jessica Lee for Joe Allman today. I just had a few questions and one particularly on the Mercer well in Sterling County, and I know it's really early on but I think last quarter you guys had a cline well that IP'd at around 200 barrels per day and I'm just curious, does the rock quality change as you go east or how should we interpret that data so far?

Well, one, I don't think you should interpret the data because it's too early. It would be my view. You know we mentioned while we weren't completely comfortable with the cline well being an effective test it's too early on this well. But you know that that acreage over in Sterling represents, I don't know, less than 9%, 8% of our total acreage base. We do need to test it and figure out what we got but it's -- that -- we're going to get to it in due course of our business of figuring out our development plan there. I am not yet ready to do anything other than say we wanted to point out it's not performing to plan but it doesn't necessarily mean we're not going to continue to have a good play there.

Okay. My next question is on your additional potential zones. And you mentioned Sprayberry and Atoka and I was just curious is Joe Mill also prospective on your acreage and even within the Sprayberry, I think some other operators have talked about a lower Sprayberry and middle Sprayberry and an upper Sprayberry. Would that also be prospective in your acreage position?

There's actually a couple of different Sprayberry zones that we are looking at. As we go across the area there we think we have lower Sprayberry perhaps some things further up the hole than that. We do have production from vertical wells in the upper and the lower Sprayberry. Argumentatively there is a couple of more lower Sprayberry zones. The Joe Mills doesn't correlate across all of that acreage. That's a pretty localized name as a member of the Sprayberry. Pat, do you want to add anything to that?

We -- based on our correlations, Randy is right, there's a -- the Joe Mill tends to pinch out as you move farther east into the Midland Basin to the east over towards our properties. Our first Sprayberry test, it's time wise is in the same stratographic equivalent as the Joe Mill but it's a slightly different sand.

Great. That's really helpful, thank you. That's it for me.

Jeffrey Connelly from Brean Capital.

Hi, good morning, guys.

Good morning, Jeff.

Can you just remind us about what you are expecting for cycle times spud to production on these multi-well pads?

We are probably looking at probably 100 to 110 days. That's taking like a three-stack lateral. So we were taking the drill time is -- and depending on what you include in the stacked lateral they range anywhere from 30 to 45 days and you stack three of those up and probably ten day to two week frac cycle on those and that kind of gets you to that number.

All right, thank you very much. Everything else I had has been answered already.

Thank you, Jeff.

Brian Singer from Goldman Sachs.

Good morning.

Good morning, Brian.

Your production in the Permian has been a little bit more flattish here recently but you're projecting it looks like about a 3,000 BOE a day increase in the fourth quarter and it would seem like on your 30% guidance that would imply 2,000 to 3,000 BOE a day per quarter beyond that. What's driving the inflection? Is it just the commitment of more capital or are you seeing the benefits from efficiencies in the well performance and backlog reduction?

As far as the production growth in the Permian, we had stated in the first quarter call that we had anticipated that production was going to be relatively flat and that you would see a little bit more of a pickup while we were anticipating a little bit bigger pickup in the third quarter. Within that we talked about the fact that we were moving to these multi-well pads in our initial stacked lateral pad was planned to be a test of just two zones. We have extended that to a three zone test and as a result as Jay just mentioned the cycle time has extended a little bit. We now anticipate that first three-well stacked lateral pad to come on production late in the third quarter.

So it is going to have basically no impact in production for the third quarter but you're going to get a full quarter benefit of that in the fourth quarter. So the lumpiness that we've referred to and I think you've heard many other producers talk about as they start drilling multi-well pads, you're going to have a little bit ladder production quarter to quarter. And then it's going to have a bigger stair step as those pads come on with multiple wells coming on at one time. So we've upsized the growth to the fourth quarter but we're still remain on track for our total production growth for the year. At the size of where we are today, bringing on a three well pad at any time is going to have a meaningful impact to us. And if that comes on two weeks earlier than anticipated or two weeks later, if it shifts over quarter it can have a meaningful or noticeable impact in our production volumes for those quarters. But overall for the year, we believe we are right on track, even with the divestment of the Anadarko Basin properties.

Great, and when you think about financing $900 million to $1 billion of CapEx next year is that just from the proceeds of the Anadarko Basin acquisition and debts or would you consider either further asset sales or equity?

We talked about the fact that we have maintained multiple options for additional capital. We listed out a number of those options previously where we had the opportunity for asset sales. We had -- you saw that we filed shelf registration earlier in this year for the potential issuance of additional debt or equity and there's always the possibility of joint ventures. We look at each one of those pretty much in a similar fashion and we are looking at the impact of what any one of those things would do to our existing shareholders. And it's going to be very sensitive based upon the specific values of any one of those transactions, the pricing that may be used or the use of proceeds and how prepared are we to accelerate activities.

So you've seen over the first half of the year that we have made significant progress and the Company is really at an inflection point of having the understanding of this asset. And as we've discussed on the work that has been done on the side-by-side laterals we are getting more data here shortly on how the vertical stacked laterals will perform. And we will continue to look at any one of those options for additional sources of financing. Through that process, we started really in April of looking at the potential divestment of the Anadarko Basin properties. And based upon the valuation at the time, we felt that the divestment of those properties would truly be value enhancing based upon the arbitrage that we saw of being able to redeploy the value from those assets into what we believe are much higher returning assets in the Permian basin. So, we are very comfortable with the liquidity that we have today and we will continue to look at any one of these other options or needs as we go into the future.

Thank you.

Hubert van der Heijden from Tudor Pickering Holt.

Good morning, guys.

Good morning.

Just real quickly thinking about your northern Glasscock acreage position and then based on your vertical well control and the 3D seismic and the other geological parameters database that you have, can you talk roughly how that compares to your southern focus area currently and what you think will be the most likely horizon there for early delineation?

We still think that ultimately there will be four horizontal potentially on that acreage. And that may grow depending on what we see on some of our additional delineation and extensional work. Again as we alluded to a couple times and Jay alluded to it, that's a 90-mile long trend and while it was depositionally pretty stable at the time of deposition there'll probably be some minor changes. But I think our view today is that we ought to be expecting, based upon the vertical program, based upon our cores, based upon the 3D, based upon our single zone testing, that we think most of that core acreage will get tested in a horizontal in those four zones. We do have cline up there that is pretty well delineated already.

Right. Okay. Thank you. And then the one other thing I wanted to ask you is on the gas price realizations was there anything in particular this quarter that drove those down and was there some kind of midstream constraint or?

As I mentioned earlier, we did see -- there were a little -- some downtime at some of the natural gas processing facilities. Those issues have been resolved and those plants are currently back up to full operations. As a result of that downtime we did not receive the full value of the natural gas liquids within our natural gas stream and as a result is why we ended up at about 113% premium to NYMEX relative to our initial expectations closer to 130%.

Okay. Perfect. But all of that is up and running again?

Yes.

Okay. Thank you. That's all for me.

Brian Gamble from Simmons and Company.

Hi, guys.

Good morning.

I just wanted to follow-up on -- you guys were just touching on when you mentioned options for more capital, you've gone through the list of possibilities, does the -- and, Randy, this is kind of harking back to something you said. You're reaching your inflection point, you have more capital going towards stacked laterals, you've got a lot more data -- you've had data for a long time but does that shift create a I guess inflection point from a JV-ing standpoints from just an outside interest? Plenty of interest in the Midland Basin, plenty of excellent well results across the Basin. Are you seeing more people coming in, are you having any more conversations or was everything at this point still theoretical exercise as far as what you are looking at first for additional capitalization moving forward.

I think we view -- we're a little bit agnostic on how we finance the Company in terms of approaches. We want to do what we think is best for the Company financially and our shareholders. Our view on the joint ventures which was expressed -- we've had a lot of calls and we've had conversations at least one fairly recently like in the last three weeks. But as we've stated before, all of these have a cost in barrels. If it's debt we've got to set aside barrels, if it's equity, diluted barrels. A joint venture if you think that you've really captured a lot of barrels, whatever that means, then you're giving up barrels to the other -- to your partner in a joint ventures so -- and that's a -- we view that as a real cost also. So I think should we run down the path of any one of those things it will be because we think that's the most efficient way for us at this point in time to finance the Company in terms of what it ultimately costs us and the long-term benefit to shareholders. We have not held our hand up saying we want to do a joint venture.

Fair enough. And then on the capital side I know you're still in the preliminary stages of finalizing the $900 million to $1 billion but Jay you mentioned it's still in the early days of recognizing cost efficiencies and you have a firm rate count assumption baked into that preliminary CapEx guidance. Can you kind of walk us through what sort of well count that implies given the hopeful well cost reductions as you walk into next year?

I'm really not prepared to give a number on that. We are still working on that and working on the number of rigs that want to bring in and deploy. So we will have a lot more color on that next quarter when we are little further along.

Okay. No problem at all. Have a good one, guys. Thanks.

Thank you.

Abhishek Sinha, BofA Merrill Lynch.

Good morning, guys. Most of my questions have been already answered. Just one quick one on the cost. When I look at the guidance I see LOE trending up so I'm just trying to see what the driving behind that?

We would anticipate certainly an increase in LOE as we become more of a dominant oil producer relative to natural gas. First half of the year we had the Granite Wash properties and only 40% to 44% of our production was crude oil. We are moving more towards 60% of our production being crude oil which naturally has a higher unit operating cost and lifting cost than natural gas does. Keep in mind though that the overall realizations on a BOE basis will increase significantly as well too just from the weighting of our post production relative to our gas production. So on a net cash margin basin -- basis we would expect those to actually improve. So you have to keep in mind that both the realizations as well as the cost structure.

All right. Sure. Very good. That's all I have. Thank you very much.

Thank you. Gentlemen, we have no further questions in queue. I will now hand back to the Company for closing remarks.

In closing let me remind you that the Company will be hosting an Investor Day on Tuesday, September 17, where we will discuss in detail our operations and expectations as a pure play Permian producer. We also anticipate announcing third quarter results on Thursday, November 7. Thank you for your time and interest in Laredo this morning, and this concludes our call.

Thank you, ladies and gentlemen, for your participation in today's conference call. You may now disconnect. Have a great day.