Vital Energy, Inc.
Q2 2013 Earnings Call Transcript

Published: 8 Aug 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 Patrick J. Curth - Senior Vice President of Exploration & Land

[Analysts:]

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division Will Green - Stephens Inc., Research Division John P. Herrlin - Societe Generale Cross Asset Research Dan McSpirit - BMO Capital Markets U.S. Ipsit Mohanty - Canaccord Genuity, Research Division Jessica lee - JP Morgan Chase & Co, Research Division Jeffrey Connolly - Brean Capital LLC, Research Division Brian Singer - Goldman Sachs Group Inc., Research Division Hubert Van der Heijden - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division Brian D. Gamble - Simmons & Company International, Research Division Abhishek Sinha - BofA Merrill Lynch, Research Division

[Operator:]

Good day, ladies and gentlemen, and welcome to Laredo Petroleum Holdings, Inc. Second Quarter 2013 Earnings Conference Call. My name is Malou, and I will be your operator for today. [Operator Instructions] 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.

[Ron Hagood:]

Thank you, Malou, 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 this morning, let me remind you 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 under 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 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, will increase by approximately 20%, which you should also keep in mind when comparing to companies that report on a 3-stream basis. Also, Laredo's unit cost metrics will appear higher when comparing 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 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 noncash pretax unrealized gains on commodity derivatives of approximately $22.9 million, as previously reported. Excluding this net unrealized gain, our adjusted net income for the quarter was $21.1 million or $0.16 per diluted share. I would now -- I will now turn the call over to Randy Foutch, Chairman and Chief Executive Officer.

[Randy A. Foutch:]

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. Post to closing of the sale of our Granite -- 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 3 rigs to drilling a 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 test of stacked laterals in multiple zones from multiple-well pads. Some exploration capital expenditures will be directed to extensional acreage and at a testing new zones, such as the Spraberry 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'll turn the call over to Jay Still, President and Chief Operating Officer, to update you on our operations.

[Jay P. Still:]

Thank you, Randy. I've been on the job now for 5 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 that 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 and held oil production relatively flat as we transition 3 of our 4 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 7 wells, 6 having enough data, with an average 30-day IP rate. The results were 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 and Southern Glasscock and Northern Reagan countries. On a 2-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 2-stream basis of our Lane Trust well was 1,912 barrel of oil a day. And on a 3-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 a 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 of the company's acreage. Aided by the joint modeling effort, we designed a 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, the 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 on microseismic data, we see no negative interference between the wells. The data fits our model and is another confirmation of the resource potential in the Permian-Garden City asset. The ongoing modeling project with Halliburton was also used to guide first test of a stacked lateral wellbores 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 2 laterals to 3 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 a stair-step production growth for the remainder of the year. Small timing differences can have a huge impact on quarterly production. We currently have 6 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 cycle time, we believe it is extremely important information that will be used to most efficiently develop our large resource base for years to come. Another impact on production of moving into develop mode is the impact of frac-ing on adjacent well. Adjacent wells to wells being frac-ed 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 cost from workover activities in legacy vertical wells. These wells were not isolated in the San Andres formation, and we have seen casing failures caused by corrosion. We are working proactively to minimize these failures. While I've pointed out some issues that cause lumpiness in our production from quarter to quarter, they should not impact our annual expectations. I'd like to reiterate that we're still expecting to have a 25% production growth in our Permian asset for 2013 and even faster growth moving into 2014. Moving on to cost. Later -- last quarter, we reduced our actual horizontal well cost 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 total cost reductions are achievable because 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 do they include any additional reductions in drilling downtimes, which our team is very focused on. Now I'd like to turn the call over to Rick.

[Richard C. Buterbaugh:]

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 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 and 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-for-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 will 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 for 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 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 are 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 workover 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 workover program will benefit unit cost going forward. During the second quarter, Laredo invested total capital of approximately $180 million -- $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 Anadarko Basin properties by mid-year 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 6 horizontal rigs throughout the year. This activity, coupled with our vertical program of 5 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 time frame and include the strong results of our drilling program through June 30. Today, our total debt, less cash, is approximately $1 billion or about 2.6x 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 1 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 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.

[Operator:]

[Operator Instructions] Stand by for your first question, and it comes from the line of Ryan Oatman of SunTrust.

[Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division:]

I wanted to follow up on the prepared remarks on 2014, understanding it's preliminary. 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 '14 volumes to be up approximately 30% over the 4Q '13 volumes. Is that a fair summary there?

[Jay P. Still:]

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%.

[Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division:]

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?

[Randy A. Foutch:]

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've got 3D over our acreage. We've got a number of vertical wells, I think 800 or so complete over the entire base. So we think we have a lot of additional kind of 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're going to be about extending our knowledge of that acreage with horizontal wells. We do intend to probably look at Spraberry zone this year, not sure that Atoka is '13. But it's -- we know, at some point, we've got to do it. And at some point, we have a 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 2. We'll probably test the Spraberry. Not sure what else we'll do.

[Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division:]

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

[Randy A. Foutch:]

Well, let me just make the comment that the fact that we're focusing on the Spraberry first doesn't 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 a pad. So the Spraberry looks pretty good, but I don't want to take away from some of the other zones. We've said pretty consistently that for us to put a lot of our capital into 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're 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'd do with that acreage. We're not ready to do that yet.

[Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division:]

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 do you have any tests planned on that acreage, maybe in the back half of this year or in early 2014?

[Randy A. Foutch:]

That's kind of the answer that I gave in 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.

[Operator:]

[Operator Instructions] And the next question is from the line of Will Green of Stephens.

[Will Green - Stephens Inc., Research Division:]

I wonder if we could expand on that with the Atoka. 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, an oil in place basis versus the Wolfcamp?

[Randy A. Foutch:]

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

[Patrick J. Curth:]

Yes. [indiscernible]

[Randy A. Foutch:]

And the oil in place numbers, which, again, I think I've -- we've kind of 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 million, 40 million, 50 million barrels, 45 million, 55 million barrels per section. But again, I'm not sure that's a critical number.

[Will Green - Stephens Inc., Research Division:]

Got you. And then from a vertical standpoint, what -- do you guys have any guess as to what the contribution on kind of an average Wolfberry well is? I mean, 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? Or do you -- I mean, it sounds like you guys feel pretty strongly about the Spraberry, and we've obviously seen some pretty good industry Spraberry wells so far. But how do you guys think about that in terms of productivity on a vertical wellbore if there is a [indiscernible].

[Randy A. Foutch:]

I'll let Jay back me up on this, if I -- but we -- as you know, we've tested many of these zones in a single-zone completion in a vertical well. In other words, we would drill a vertical well, instead of testing, producing the entire section, we would stop and test one zone, frac it 30, 60, 90 days. In some cases, longer. And so we have a pretty good database on what zones contribute. And we've also talked about how with this 80-mile-long acreage base, there'll be some variances, although it's consistently -- pretty consistent depositionally. We've seen a few areas where the Spraberry tests very well. We've seen a few areas were the Wolfcamp is stronger. We've 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've 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 Spraberry produces very well. We know that the Atoka produces. So our job -- and for that matter, we do have some strong production out there a the horizontal -- a couple of horizontal wells. So our view is that we've 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 P. Still:]

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

[Operator:]

The next question is from John Herrlin of Societe Generale.

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

The Sugg wells, you've had better initial results. Any sense on where the EUR is going?

[Randy A. Foutch:]

We -- on -- I mean, 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're performing as well as they are. We've stated more than one time that 1 or 2 wells doesn't 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'll probably want to look at EURs and AFEs. And if we -- we'll update those. And if we need to adjust, we'll adjust them then. So, we're very happy with the results of those wells.

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

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

[Randy A. Foutch:]

I'll let Jay take a first crack at that.

[Jay P. Still:]

Yes. We feel comfortable on the 660 spacing. It's -- 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 3 stack, 4 stack, the order you drill those in, pad design, all those intricacies as you launch rigs into the pad development that are critical to optimize and capitalize on the cost efficiencies that you can gain from pad drilling.

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

Okay. Last one for me is on the Mercer well. Is it too early to -- not condemn, but throw a caution on the Middle Wolfcamp, given your Upper and Lower results?

[Randy A. Foutch:]

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 -- I wish it was a better well, but I certainly am not prepared to say it, in any way, influences our view over most of the Middle Wolfcamp.

[Operator:]

Next question is from Dan McSpirit of BMO Capital Markets.

[Dan McSpirit - BMO Capital Markets U.S.:]

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 anytime soon? Or do you believe you're in the early innings of driving better returns and margins? And maybe in answering that question, maybe if you could speak to drill and complete costs here going forward?

[Jay P. Still:]

Dan, the -- and that's where we touched on the efficiencies of pad drilling. I mean, the simple things in pad drilling, you remove your mob and demob costs. All these 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. So I mean, there's just -- efficiency drives a lot of cost savings from -- on the pad work. On the completion side, you start moving to zipper fracs, where you're completing 2 or more wells at once, while you're frac-ing one well and you're doing plugs and doing wireline work on the next, and you have a manifold, you switch back and forth. All of those drive cost reductions through time improvement. So those simple, tangible things in pad drilling will continue to drive cost 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 start testing -- you kind of have a lab set up, with the rock properties are the same. And now you can start optimizing your cluster space, seeing your sand, your carrying fluids. All those kinds of things can have tremendous impact in your production. So that's the benefit of moving into pads to -- that we're going to see going forward. That's why I'm really comfortable that we can drive down our drill and complete cost.

[Dan McSpirit - BMO Capital Markets U.S.:]

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

[Jay P. Still:]

I think -- we're just starting on our first -- finish up -- finishing up our first stacked multi-lateral 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.

[Dan McSpirit - BMO Capital Markets U.S.:]

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?

[Randy A. Foutch:]

You mean besides me? Is that...

[Jay P. Still:]

I'd say, well, Randy, of course. I mean, Laredo is -- they take 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 -- who's going to rise to the top on that. But I saw in Laredo just a great opportunity of a growing company with great assets and great technical staff. I mentioned in my opening remarks, to grow. So -- and Rick is -- got to throw him in, as well.

[Richard C. Buterbaugh:]

It's been -- everybody here is holding their hand up.

[Jay P. Still:]

It's just been a great ride so far.

[Operator:]

The next question is from Ipsit Mohanty of Canaccord.

[Ipsit Mohanty - Canaccord Genuity, Research Division:]

Let's see, so if you look at the Lower Wolfcamp 2 wells that you've given, 1 in April, 1 in June, but a big difference in their 30-day IP. So if you could talk a little bit about maybe what you saw in the first well that you kind of maybe implement it in the second lessons learned from one to the other? And on the same time, what is it producing in the Mercer well that's quite not working for it?

[Randy A. Foutch:]

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 wanting 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 2 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's working across the board. So I don't know how much more we want to go into comparing one well to another one.

[Jay P. Still:]

I mean, we've got a really large acreage position in all -- there's -- although you are in the Lower Wolfcamp from the top to the bottom over 90 miles, that -- the rocks change, are slightly different as you move around the basin. And that's kind of what goes into our type curve. All of them are great wells economically, some of 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 pretty high return on investment.

[Randy A. Foutch:]

It's -- I'd just point out that the Lower Wolfcamp well we completed in April, it's right on type curve. It's 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 mean, I'll take either one of those 2 wells.

[Ipsit Mohanty - Canaccord Genuity, Research Division:]

And 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 3 Wolfcamp zones?

[Randy A. Foutch:]

The vertical program, I think we're running 5 rigs and we're going to -- the vertical stack? Oh, I'm sorry...

[Jay P. Still:]

[indiscernible] stack, if we're going to bring those...

[Randy A. Foutch:]

I'll let you...

[Jay P. Still:]

We're going to bring those -- we will have those completed, all of those completed towards the middle of next month. So by the time you bring those on and they clean up, I'm not sure we're going to have meaningful production data by the end of the quarter, but it's going to be a pushing us well. I believe those are going to be impactful for third quarter production. They will be impactful for fourth quarter. The question on the Cline is -- moves more to an operational question in that, operationally, is it better to drill all of your stack potential at once or drill across your acreage position into, say, the top 2 or the bottom 2 benches that you want to develop? We're still working on that, and that will be something that we will probably have a better answer for by the end of this quarter.

[Operator:]

Next question from the line of Joe Allman of JPMorgan.

[Jessica lee - JP Morgan Chase & Co, Research Division:]

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-ed at around 200 barrels per day. I'm just curious, does the rock quality change as you go east? Or how should we interpret that data so far?

[Randy A. Foutch:]

Well, one, I don't think you should interpret the data because it's too early, would be my view. We mentioned, while we weren't completely comfortable with the Cline well being at effective test, it's too early on this well. But 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 -- we're going to get to it in due course of our business of figuring out our development plan there. So I'm 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.

[Jessica lee - JP Morgan Chase & Co, Research Division:]

Okay. And my next question is on your additional potential zones, and you mentioned Spraberry and Atoka. And I was just curious, is Jo Mill also prospective on your acreage? And even within the Spraberry, I think some other operators have talked about a Lower Spraberry and a Middle Spraberry and an Upper Spraberry. Would that also be prospective in your acreage position?

[Randy A. Foutch:]

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

[Patrick J. Curth:]

We're -- based on our correlations, Randy is right. There's a -- the Jo Mill tends to pinch out as you move farther east in the Midland Basin to the east over towards our property. So our first Spraberry test will -- it's, time-wise, is in the same stratigraphic equivalent as the Jo Mill, but it's slightly different sand.

[Operator:]

Next question is from Jeffrey Connolly from Brean Capital.

[Jeffrey Connolly - Brean Capital LLC, Research Division:]

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

[Randy A. Foutch:]

We're probably looking at probably 100 to 110 days. Well, that's taking like a 3-stacked lateral. So we're taking the drill time as -- and depending on what you include in the stacked lateral, will range anywhere from 30 to 45 days. And if you stack 3 of those up and that will probably -- a 10-day to 2-week frac cycle on those, and that kind of gets you that number.

[Operator:]

The next question is from Brian Singer from Goldman Sachs.

[Brian Singer - Goldman Sachs Group Inc., Research Division:]

Your production at 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 kind of 2,000 or 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?

[Randy A. Foutch:]

As far as the production growth in the Permian, we had stated in our 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 or we were anticipating a little bit bigger pickup in the third quarter. We didn't add -- we talked about the fact that we were moving to these multi-well pads and our initial stacked lateral pad was planned to be a test of just 2 zones. We have extended that to a 3-zone test. And as a result, as Jay just mentioned, the cycle time has extended a little bit. We now anticipate that first 3-well stacked lateral pad to come on production late in the third quarter. So it's 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 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 kind of the growth to the fourth quarter but we'll still remain on track for our total production growth for the year. At the size of where we are today, bringing on a 3-well pad at any time is going to have a meaningful impact to us. And if that comes on 2 weeks earlier than anticipated or 2 weeks later, if it shifts over a quarter, it can have a meaningful or noticeable impact in our production volumes for those quarters. But overall for the year, we believe we're right on track, even with the divestment of the Anadarko Basin properties.

[Brian Singer - Goldman Sachs Group Inc., Research Division:]

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 debt? Or would you consider either further asset sales or equity?

[Richard C. Buterbaugh:]

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 a 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're 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've 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 -- what has been done. On the side-by-side laterals, we're getting more data here shortly on how the vertical stacked laterals will perform, and we'll 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're very comfortable with the liquidity that we have today, and we'll continue to look at any one of these other options for our needs, as we go into the future.

[Operator:]

Next question is from Hubert Van der Heijden from Tudor, Pickering, Holt.

[Hubert Van der Heijden - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division:]

Just real quickly, kind of 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?

[Randy A. Foutch:]

We still think that, ultimately, there will be 4 horizontal potentially on that acreage, and that may grow, depending on what we see on some of our additional delineation and kind of extensional work. Again, as we've alluded to a couple of 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 will 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 horizontal, in those 4 zones. We do have Cline up there, that pretty well delineated already.

[Hubert Van der Heijden - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division:]

Okay. And then the one other thing I wanted to ask you is on the gas price realization. Was there anything in particular this quarter that drove those down? And was there some kind of Midstream constraint? Or...

[Richard C. Buterbaugh:]

Yes. 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, it is why we ended up at about 113% premium to NYMEX relative to our initial expectations, closer to 130%.

[Hubert Van der Heijden - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division:]

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

[Randy A. Foutch:]

Yes.

[Operator:]

The next question is from Brian Gamble from Simmons & Company.

[Brian D. Gamble - Simmons & Company International, Research Division:]

Just wanted to follow up on what 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 -- I mean, you've had data for a long time. But does that shift create a, I guess, inflection point from a JV-ing standpoint 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 is everything at this point still a theoretical exercise as far as what you're looking at first for additional capitalization moving forward?

[Randy A. Foutch:]

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 3 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. The 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 the joint venture. 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'll 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 cost us and the long term benefit to shareholders. We've not held our hand up saying, "We want to do a joint venture."

[Brian D. Gamble - Simmons & Company International, Research Division:]

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 early days of recognizing cost efficiencies and you have a firm rig count assumption baked into that preliminary CapEx guidance. Can you kind of walk us through what sort of well count that implies, given hopeful well cost reductions as you walk into next year?

[Jay P. Still:]

I'm really not prepared to give a number on that. We're still working on that, working on the number of rigs we've been able to [indiscernible] and deploy. So we'll have a lot more color on that next quarter when we're a little further along.

[Operator:]

The next question is from Abi Sinha of Bank of America.

[Abhishek Sinha - BofA Merrill Lynch, Research Division:]

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's driving behind that.

[Richard C. Buterbaugh:]

Well, 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're moving more towards 60% of our production being crude oil, which has -- 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 oil 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 the 2 -- both the realizations, as well as the cost structure.

[Operator:]

Gentlemen, we have no further question in the queue. I will now hand back to the company for closing remarks.

[Ron Hagood:]

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. I thank you for your time and interest in Laredo this morning, and this concludes our call.

[Operator:]

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