Vital Energy Inc (VTLE) 2013 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Laredo Petroleum Holdings Inc. first-quarter 2013 earnings conference call. My name is Sue 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. Rick Buterbaugh, Executive Vice President and Chief Financial Officer. You may proceed, sir.

Thank you, Sue, and good morning. Joining me today are Randy Foutch, Chairman and Chief Executive Officer; Jerry Schuyler, President and Chief Operating Officer; Pat Curth, Senior Vice President of Exploration and Land; John Minton, Senior Vice President of Reservoir Engineering; 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 of the Private Securities Litigation Reform Act of 1995. The company's actual results may differ from these forward-looking statements for a variety of reasons, many of which are beyond our control. Additional information concerning certain risks and uncertainties relating to our business prospects and results are available on the company's filings with the SEC. 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 in 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 our combined liquids total. If reported on a three-stream basis, Laredo's barrel-of-oil equivalent volumes for reserves and production, including initial production rates [and volumes], would increase by approximately 20%, which you should keep in mind when comparing to companies that report on a three-stream basis. Similarly, Laredo's unit-cost metrics will appear higher when compared to those companies that report on a three-stream basis. However, the true economic value is the same.

Earlier today, the company issued a news release detailing its financial and operating results for the first quarter of 2013. You may have noted that the wire service had an issue this morning with a number of various companies' news releases, which caused them to reissue these releases to correct some of their formatting. The actual release is available on the company's website at www.laredopetro.com. In this news release, Laredo reported net income of $1.4 million, or $0.01 per diluted share, for the first quarter of 2013. This includes non-cash, pre-tax, unrealized losses on commodity derivatives of approximately $20.6 million, as previously reported, and an unrealized pre-tax gain of approximately $100,000 on interest-rate derivatives. Excluding these net unrealized losses, our adjusted net income for the quarter was $14.6 million, or $0.11 per diluted share.

As a reminder, as previously announced, the company is pursuing the potential disposition of our operations and assets in the Anadarko Basin. Therefore, the associated pipeline and other related assets, property, and equipment are presented as discontinued operations in our financial statements. The oil and gas properties that are a component of these assets are not presented as held-for-sale, pursuant to the rules governed in full-cost accounting for oil and gas properties. We have completed the data room portion of this process, but we will not be discussing this process during today's call. We expect to reach a determination regarding this potential disposition during the current quarter.

I will now turn the call over to Randy Foutch, Chairman and Chief Executive Officer.

Thanks, Rick, and good morning, everyone. Thanks for giving us your time today.

I am very excited about the significant progress that we have already made this year, as Laredo moves closer to full-scale development of our Permian-Garden City asset. We had a very successful year in 2012, accomplishing our goal to meaningfully delineate this acreage, and we have confirmed the presence of approximately 1800 feet of shale in four stacked zones, each zone capable of commercial horizontal production. We expect to delineate our remaining acreage in time. Our focus in 2013 is directed toward accelerating the development of this rich asset, while maximizing its overall return. We are shifting capital toward horizontal development, and have expanded our technical staff to support this effort in a cost-efficient manner. We are already seeing documented improvements in the capital cost of our horizontal program, and expect to further realize improvements over time.

Since our initial activities in the Garden City in 2008, we have taken a very disciplined and deliberate, science-based approach for the 68 horizontal wells that we have completed through the first quarter this year. The knowledge from this activity, and the investment we made in gathering data, is paying dividends through our partnership with Halliburton. Together, we have now created a detailed subsurface model of our Permian-Garden City acreage. We can simulate reservoir performance to help maximize the overall value of this entire resource. We are putting the results of this work into practice, as we continue to convert potential into reserves and production. We plan to maintain this disciplined approach, both operationally and financially, as we move into the full-scale development of this exceptional asset to truly maximize its value for all of our shareholders.

Now I will turn the call over to Jerry Schuyler, President and Chief Operating Officer, to update you on our operations.

Thank you, Randy, and good morning, everyone.

Operationally, we had a good first quarter. We grew production, as we had forecast. We were up 4% from the fourth quarter of 2012, and we were up 24% from the first quarter 2012. More importantly, we have continued to deliver good well results and make significant progress on implementing best practices and cost control measures, reducing well costs. Additionally, we are transitioning the majority of our future drilling to multi-well pads, which we will help -- which will help us realize even more well-cost reductions, and we have established initial development plans for portions of our Garden City properties.

Our horizontal wells in the Wolfcamp and Cline continue to perform. During the quarter, we completed an additional eight horizontal wells in Garden City. Seven of these were long lateral's, and one was a short lateral. Six of these wells were in the Wolfcamp, and two were in the Cline. One of the Cline wells, the Mercer B-6-1H, was disappointing, but we had some issues on the completions in flow back, and we don't feel it is a good test of the area. I won't reiterate all of the results, which we put in our earnings release today, but overall our well results continue to meet or beat our expectations, and we are pleased with the continued progress shown in our horizontal program in each of the four identified zones. I will remind you that we report on a two-stream basis.

We typically don't give 24-hour IP rates, because we believe that 30-day average IPs are more meaningful in understanding well performance. However, we know a number of operators do give peak rates, and several of them report in three-stream volumes. So today, I will give you comparable well results for some of our very recent activity, showing 24-hour peak rates and cumulative recoveries in theoretical three-steam volumes at the wellhead. However, I do want to make it clear we do not intend to update this information routinely in the future.

In the Upper Wolfcamp, our SUGG-A-143-2HU at a peak 24-hour rate of 1,780 barrels-of-oil-equivalent per day that was 89% liquids. It is a first-quarter well, and has produced 50,700 barrels-of-oil-equivalent in its first 45 days of production. In the Lane Trust CE-42-1HU is another Upper Wolfcamp well, and had a 24-hour peak rate of 1,371 barrels-of-oil-equivalent per day. It was also 89% liquids, and produced 122,300 barrels-of-oil-equivalent in its first 100 days. In the Middle Wolfcamp, our SUGG-C27-1HM had a peak 24-hour rate of 1,423 barrels-of-oil-equivalent per day. It was 90% liquids and had a cumulative production of 99,800 barrels-of-oil equivalent in its first 100 days. In the Lower Wolfcamp, our SUGG-D-106-2L had a peak 24-hour rate of 1,287 barrels-of-oil-equivalent per day. It was 88% liquids and has a cumulative production of 81,700 barrels-of-oil-equivalent in its first 100 days of production.

Admittedly, these are some of our better wells; however, in the 12 months ending March 31, 2013, we had completed 25 wells in the Wolfcamp. This includes the Upper, Middle and Lower. And the average peak 24-hour IP on a theoretical three-stream basis was approximately 1,050 barrels-of-oil-equivalent per day, with an average of 89% liquids. And in the Cline, we have completed 36 horizontal well, starting in early 2010. We have tested and developed many of our completion techniques and varying lateral length and frack densities in this zone. The AFE cost is higher because it is deeper and it is somewhat over-pressured, so we are drilling fewer of them today. But in our recent BEARKAT-1505H, we had a peak 24-hour rate of 1,364 barrels-of-oil-equivalent per day. It was 87% liquids and had a cumulative production of 78,800 barrels-of-oil-equivalent in the first 100 days. The results were right in-line with our average Cline performance type curve. I hope these theoretical three-stream rates and cumulative production examples help illustrate why we believe we are achieving some of the best well performance in the Midland Basin in these four plays.

Now I'd like to update you on our cost. We have reduced our actual horizontal well cost by 5% to 10%, with more to come. Our recent drill-and-complete costs are now running about $7.8 million for our long lateral Upper and Middle Wolfcamp wells, about $8.5 million for our Lower Wolfcamp wells, and about $9 million for our long lateral Clines. Keep in mind these are all in cost, and include things like associated production facilities. It is worth noting that none of these costs reflect the benefits we expect to realize in our current transition to multi-well pad drilling or additional drilling efficiencies that we are currently targeting and starting to realize. We recently drilled a couple of horizontal wells in record time in Garden City, with our first Upper Wolfcamp side-by-side long lateral well test in an average of 21 days spud to TD. This is about 7 to 8 days less than what is built in our drill-and-complete costs that I just covered with you. Therefore, we believe this continued focus on best practices and cost control should result in additional cost reductions and even better economics.

As an example, the rate of return on the Upper Wolfcamp wells improves about 5% for every $500,000 of cost reduction. When you combine our improving drilling and completion cost with our strong well performance, the economics of these wells just keep getting better. As we mentioned in our release, we have successfully reduced the number of vertical wells from our original budget plan, and we are reallocating that capital to more horizontal well drilling. In the Permian, we therefore released one of our vertical rigs in the end of February, leaving us five, and we are currently picking up a fourth horizontal rig. Of these four horizontal rigs, three are capable of quicker moves between wells, when the wells are on the same pad. With these rigs, we are rapidly moving towards the drilling of multiple-well pads. Our current plan is to drill about 70% of our remaining horizontal wells from these multi-well pads this year. This should help us realize even more efficiencies, and result in more overall well-cost reduction.

Based on our production results today, our extensive amount of data collection and our recent joint modeling efforts with Halliburton, we have established initial development plans for portions of our Garden City properties. As we continue to do some necessary one-off testing, our typical pad developments in some areas will be four wells initially that are targeting Upper and Middle Wolfcamp development simultaneously. Optimally, we plan to drill two wells to the north, and then two wells to the south while we are completing the wells that were just drilled to the north. This drilling-and-completion sequence will limit the amount of time a new well has to remain shut-in prior to being completed and brought online, to just two wells. This four-well pad will optimize the production in water-handling facilities and off-take infrastructure in an area. After the first four wells have declined, the remaining four wells will be drilled in the future, completing in the Lower Wolfcamp and Cline zones, making the multi-well pad an eight-well pad.

Our modeling indicates a lateral spacing of 660 feet and an optimum lateral length of around 7,500 feet, so that is where we will start. We have several tests scheduled later this year to verify the spacing. The testing of our side-by-side lateral is expected to be completed later this month, and our first stacked lateral in the third quarter. In a summary, we had a very productive quarter. We grew production weighted to our oil properties; we reduced our well costs and expect further reductions; we started the transition to multi-pad drilling; and we established initial development plans for portions of our Garden City area.

With that, I will turn it over to Rick.

Thank you, Jerry.

As was just discussed, the success of our oil-rich Permian-Garden City drilling program drove the increase in total production to a record 3.1 million barrels-of-oil-equivalent, roughly, slightly above the midpoint of our guidance, as expected. This equates to 24% increase in total daily production, versus the prior-year quarter, and a 4% increase from the fourth-quarter rate. Importantly, crude oil production grew 35% and 8% for those same periods, and is now increased to approximately 46% of our total production volumes, as reported on a two-stream basis. We remain on track to achieve our expected 15% production growth for the year; however, the quarterly production growth will appear more stair-stepped as we transition to multi-well pad development.

Our strong production growth in the first quarter was offset in part by lower realized prices for both crude oil and our liquids-rich natural gas, which came in at the low end of our guidance. As a result, total oil and gas revenues increased to approximately $164 million, up about 10% from the prior-year quarter. Total unit operating expense of $37.76 per barrel-of-oil-equivalent came in at the low end of our guidance range of approximately $38 to $39 per BOE; however, the individual components did vary from our expectations, with lower-unit DD&A expense offsetting higher-than-anticipated unit lease operating expense. The increase in unit-lease operating expenses included higher-than-anticipated work-over activities.

As we continue to implement best practices throughout the field, we expanded the amount of proactive work-over activity from our previously-planned level, in an effort to reduce our down-hole failure rate. Some of these activities have carried over into the second quarter. But we believe these activities are paying off, and have begun realizing a reduction in down-hole failure rates that we are anticipating. So the number of service rigs doing general down-hole repair work and tubing upgrades in the Garden City area has now been reduced from 12 rigs to just 5 rigs. We believe that these investments in the early part of 2013 will improve overall well performance and have a positive impact on our unit cost, going forward. We also expect to begin realizing reduction in saltwater disposal costs with the installation of a saltwater disposal line on a portion of our Reagan County acreage that will enable us to pipe more of the saltwater directly to disposal wells, and save significant trucking costs. As disclosed in detail in this morning's news release, we expect second-quarter total unit operating expenses, including lease operating, production taxes, G&A, and DD&A, to be in the range of $37 to $38.50 per barrel-of-equivalent, comparable to the first-quarter rate.

During the first quarter, Laredo invested total capital of approximately $177 million. As previously mentioned, we are increasing our horizontal rig count while decreasing our vertical rig count in the Permian Basin. With this change and the previously-discussed capital reductions for our horizontal program, we remain on-track to meet our budgeted expenditures of approximately $725 million for the full-year 2013. Actual cash expenditures for the first quarter of 2013 were approximately $199 million.

Sue, at this time, we would like to open the lines for any questions.

(Operator Instructions)

Ryan Oatman, SunTrust.

Very good Upper Wolfcamp results in the press release, and I do appreciate you guys breaking out the 24-hour IP rates on a three-stream basis. I think that is intuitive and helpful for us. I was just curious, on these latest Upper Wolfcamp wells, how do they compare versus your type curve?

The four that we completed in the first quarter, the 30-day IP is actually about 15 -- the average of the four is about 15% higher, so all of our Upper Wolfcamp's are actually coming in a little higher in the early production stages.

Okay. And then that SUGG-A-143, obviously, the best well of the -- almost 1,200 barrels per day, 30-day rate -- did you do anything differently there? Is there anything that we could expect going forward, in terms of productivity performance there?

You know, the biggest thing that we have done is, we have probably gotten more and more efficient, and these are longer laterals, so fundamentally -- you know, we have been using slick water since the early 2010 or late 2009, but the bottom line, I think, is we probably a little more efficient in these things, but we are pretty happy with our completions.

Absolutely. And then this Cline well, the Mercer -- about 200 barrels a day for its 30-day rate -- I believe that was completed in Sterling County. Can you just remind us how many acres you have there, and if you have drilled other wells there? I think you guys mentioned something about a couple mechanical issues on that. I'm just trying to get a feel for the risking of that Sterling County acreage.

It is about -- this is Randy -- is about 10,000 acres, I think, more or less, and we have vertical, we have some core information that made us want to drill that well. We still have other targets there. And we are not sure that we have effectively tested the Cline.

Okay. And the reason that you feel that it is not an effective test?

Just to be completely clear, we are not sure that the Cline we tested represents most of that acreage. Let me state it that way.

Got it. And then, does that inform the view of the China Grove acreage at all? Or is that, given the distance, really just not much of an impact there?

I do not think there is any real correlation.

Fair enough. Absolutely. Well, I appreciate the color, and I'll hop back in the queue.

Mario Barraza, Tuohy Brothers.

Digging in little deeper on the efficiency, what would be your long-term target for your well costs for the different Wolfcamp zones and for the Cline?

We have not given a target yet, not sure that we do. We have historically, as a company, not made projections on what we may do in those areas a year or two down the road. We have talked about what we have done, as opposed to something that we may do. We are actually pretty optimistic and excited that as we move toward less one-off drilling, less production facilities per well, in terms of being able to amortize it, we're going to have a pretty significant impact. And I realize you're looking for a number, but we are not there.

Okay. Got you. You talked about improving your -- the spud-to-TD on one well down to 21 days -- again, what is the average you're using for this year and where do you -- how many wells have you gotten closer to this 21-day target, and would you be able to -- I know you are shifting more to pad drilling, but would you be able at all to accelerate the completion process?

Actually, there's a couple of wells -- I may not have been clear, but on the -- we drilled a couple of wells in an average of 21 days, spud-to-TD. And they were drilling side-by-side, so we kind of had them in a race. But that was compared to -- you would have added about 7 to 8 days, if you looked into our plan of spud-to-TD. To clarify, though, on our Upper Wolfcamp and Middle Wolfcamp wells, using the conventional rigs without pad drilling, we have 35 days typically built into our budget. We have 30 days from rigging up to rigging off, to taking the rig off, and then we have literally five days in there for the moves on the two different ends. So that is why -- I was just trying to make the point that with that 21 day average, I think that is something that we are going to be able to realize on a lot more of our wells, and obviously it is going to be fairly material, if we do.

Okay. And then, lastly, when do you plan on getting this, the fourth rig hooked up, and that, obviously, isn't factored into -- that was not factored into your initial guidance, per projections for this year, correct?

Yes, in the guidance, we had the amount of money, and Rick can talk to that here in a second. What we have in essence done is that we have shifted a fair amount of money or capital from vertical to horizontals, and this fourth rig is actually coming on in the next week or so.

The $725 million capital program that we have for 2013 is unchanged. As Jerry mentioned, we are going to -- we are moving from six vertical rigs in the Permian Basin down to just five. We are replacing that with a horizontal rig. Those horizontal rigs are beginning to drill more multi-well pads, which as I mentioned, is going to cause the production growth to be a little lumpier. We are still on track to be able to reach our goals overall for 2013 on our production growth, and do that within our capital budget of $725 million.

Okay. I appreciate it. I have a few more, but I'll hop back in the queue.

Brian Gamble, Simmons and Company.

I wanted to touch on those costs that you were just walking through, and maybe ask it in a different way. When you are talking about TD times, the 21 days, obviously -- significant improvement from 35 days, if that is what is in the plan. How much of, specifically, just that component of the cost allowed the pretty significant decrease in quarter-on-quarter Upper and Middle Wolfcamp cost, down from that $8.5 million down to that $7.8 million. Was it mostly that, or were there other pieces, other big pieces to that, that we should consider when we are thinking about the either next quarter's cost or longer-term cost for those wells in particular.

Brian, first let me clarify that we did not -- that the wells that averaged 21 days, that cut that time off -- they are not the type of well that we have modeled into that -- you know, for Upper Wolfcamp, here is an example -- the Upper Wolfcamp, we have at $7.8 million. In that $7.8 million, we typically have 35 days, and 30 of it is from rigging up to rigging off, and then five is the move on the front end and the back end. So if we were to realize these savings on wells going forward, then all of that cost would come off of the $7.8 million that we are using. We use actual costs that we have been able to deliver, and that is what the $7.8 million comes from.

And that -- the reduction that we have seen so far to-date, which as Jerry said, does not include that change in spud to finish -- some of that has been service cost, but some of that has just been things we have done, improving our processes and procedures on drilling and complete.

And Brian, the other thing that I would point out is that these two side-by-sides -- we are actually out completing them, now so they were drilled in the second quarter. So in all of our Q1 information, the capital [loss] is not reflected for those wells.

Well, you've got some competitive guys, maybe all your well should be right next to each other, so they can compete, because that 21 days is quite impressive.

Sounds like you've been talking to Randy. [Laughter]

Competitive guys know how to get things done. The other question I wanted to touch on -- I was just reading in the Q, and I know you do not want to talk too much about the sale, but the Q seemed to make it pretty clear that the [Mid-Con properties] would be sold in the second quarter. Just a little bit more definitive than you mentioned in your prepared remarks. I don't want to put any words in your mouth, but the Q is an accurate reflection of what is going on -- is that fair?

The 10-Q is accurate as presented, and as I mentioned to begin with, that we are in the middle of the process, we have held [a data room] and we will make a decision regarding the potential divestment of the Anadarko Basin properties later this quarter.

Great. And then just to clarify one thing on the guidance. The guidance for second quarter does reflect your expectations for that asset, or would change based on what happens with that asset during the quarter?

If we divest of the Anadarko Basin asset, we would issue new guidance, but at this point, the guidance that was reflected in today's news release, as well as our expectations for the year, assumes the continuance of operations as they are today.

Great. That's perfect. Thank you.

Will Green, Stephens.

We have seen laterals as long as 10,000 feet in the basin. It looks like you guys have settled on 7,000 recently. Is that the way to think about these going forward, and how should we think about frack optimization? Is the 27 to 28 on 7,000 foot pretty good? How is that evolving?

We still have -- we kind of view that 7,000 to 7,500 range as the sweet spot, but we do have plans of this year for some longer laterals, and I don't think we are done yet, over the next year or two, maybe testing one or two shorter laterals. The frack optimization that we have gone through -- we actually started in slick water wells out there a long time ago, and as you know, with 400 feet between clusters and stages, we have narrowed that down, so that 25, 26, 27 for a 7,000 foot is kind of what we think the sweet spot is, but we are not completely done doing some experimenting there. Jerry, is there anything you want to add to that?

No, think that is good.

Will, does that help you out?

That definitely helps. Maybe we could touch on lease holding. I know you guys have been -- I guess I would say less efficient, and I think you guys have made that remark, and that's part of the reason you're seeing these reductions, is that you guys are moving more toward pad drilling. How should we think about lease-hold drilling this year? You mentioned you are doing fewer Cline tests. How do stand there? And then, is the beneficiary of this more Upper Wolfcamp wells that look like those? Those obviously look like the best results you saw the first quarter. How should we think about lease-hold drilling this year and as that winds down?

I am not exactly sure which mean by lease-hold drilling, but our plans are to still run five vertical wells, which do help us, in terms of our continuous drilling obligation. I don't know that I necessarily agree with the least efficient comment, as much as I think we've been drilling one-off locations very, very deliberately, very, very much in terms of getting the right data, especially across that 80-mile-long acreage block we have there. I think our plans, in '13 we wanted to -- we have stated our plan in '12 was to delineate acreage. We have done that. Our plan in '13 was work on a development plan. We have a lot of Cline information -- what, 30 something, what is it?

36.

36 wells. So we wanted to build our entire Wolfcamp database, and I think '13 going forward will be doing more Wolfcamp Upper, Middle, and Lower drilling than Cline, simply because we have a lot of Cline data. And that is what we need to get us to the full-field development plan and going forward.

Sure. I guess my point was -- it sounds like the pad drilling is occurring, because you guys have delineated and held a lot of this. I was just trying to get an update on that. That part of it.

Yes. As we've talked in the past -- 2012, we were doing a lot of delineation. It was a much broader, more of a shotgun type approach, on a very specific basis, to be able to identify the extent of the Cline, Upper, Middle, and Lower Wolfcamp. With the delineation that took place in 2012, we are now moving more into a more traditional development mode, which will end up with better utilization of our rigs, shorter rig moves when necessary, multi-well pads, the efficiencies associated with those multi-well pads. So we do expect our capital intensity to come down on a per-well basis.

Great. I appreciate that. Thanks.

Gil Yang, Discern.

Rick, you made the comment, I think, in answer to a previous question that your $725 million CapEx budget is unchanged. Production is going to be lumpier because of the transition to a little bit more horizontal drilling. And I think that is reflected in your pad, the commentary about the pad drilling. What percentage of drilling was going to be in pads prior to -- previously? You are saying 70% now?

We are saying -- well, that 70% for the remainder, for the second, third and fourth quarter.

And what happened [prior to that]?

Gil, I don't think we had a percentage, or a -- as we have stated a couple of times, the goal in '13 was to move toward more of a full-field, development-pad-like drilling, and I think when we started the year and announced the budget, we contemplated that we would be migrating toward pad drilling, but I don't think we had a percentage fixed up until now.

Yes. And prior to the second quarter of this year, there really were no multi-well pads that we had done. They were all one-off locations, which is one of the reasons why we anticipate that our capital intensity will come down for the remainder -- the second half of the year.

Okay. And that -- so think of it as going from 0% to 70%, in a way, but -- and that capital intensity is dropping from the $7.8 million level, as well?

Yes. The numbers -- the capital cost that Jerry mentioned today and that were included in our press release represent demonstrated results through the end of the first quarter. The additional savings that we anticipate from multi-well pad development, as well as some of the faster drilling times, have not been reflected in those numbers. As you are aware, Laredo reports actual cost that we have demonstrated. And that is an important way to make our decisions going forward, as well as how we invest our money -- not on dollars we hope to get to, and determine if it is economic on a hope-to number. The costs that we have demonstrated have continued to improve our economics, and we think it is reflective of what we are able to do on the thousands of wells that we anticipate that we will need to drill to fully develop this field.

Okay. Given that there are more efficiencies to come, do you -- and the savings versus your CapEx budget is the same, yet the well costs are down 5% to 10%, with more to come -- do you anticipate that you would be up to drill more wells for the same capital budget, and maybe grow faster than 15%, or do think that maybe you moderate the spending and stick to that 15% target?

We feel pretty confident today with our 15% target, even though we will be drilling more horizontal wells because of the multi-well pads. We may not get some of the benefit of that until 2014, as far as from a production growth standpoint.

Okay. And then the last question is -- are you seeing any benefits to the costs and performance in the vertical well that you are drilling, as well?

We were already pretty good at that, because we had drilled 250 or so vertical wells, deep ones. And I think we're seeing some things that are going to lead us to maybe reducing that cost, maybe not, but I wouldn't -- we are long way today from saying, we ought to look at reduced cost on the vertical.

And performance-wise for the wells -- they are pretty consistent with what they've been? So no -- you are not able to imply -- employ any learnings that give better volumes or anything like that?

Yes, we are -- yes, this is Jerry. We are improving the performance. We continue to fine-tune how we are doing the completions on the verticals, as well. And in the first quarter, we did realize that there is a very significant improvement, so we are still making headway there.

Can you quantify that, Jerry? Percentage-wise?

No. Rate-of-return-wise and in the [type curves], I think we show in the 15% range, and I would say it is in the 15% to 20% type of range for rates of return on those wells.

Okay. Great. Thank you.

Abhi Sinha, Bank of America.

Just wanted to touch base on the asset sale. I know you said you do not want to talk in detail, but all I wanted to ask is, assuming that sale goes through [fully], what are your plans for the rigs that you are (inaudible)]? Would you [lay it down], would you move it to Wolfcamp, or any color on that?

Abhi, as I mentioned earlier, any discussion regarding that potential transaction has already been made. If there is anything from a transaction standpoint, we would obviously give updated guidance at that point.

That's fair enough. The other thing I want to ask is basically -- we have been hearing from many companies this quarter that are experiencing a lot of [fluctuation curtailment] due to capacity constraints in the Permian. How comfortable are you right now with your productive capacity, versus the processing and [particular] capacities available to you?

I will let Rick and then Dan take a shot at that.

Yes. Abhi, we spend a lot of time on that, to make sure that we have appropriate takeaway capacity. So it is something that we very actively manage, but I will let Dan give you the specifics of that.

Yes. Abhi, we're pretty encouraged -- as you have heard Randy say before, processing capacity is local. And we have -- since the start of the year, $230 million a day of processing capacity has been directly added to by the purchasers that are directly connected to Laredo's production in the Midland Basin. And we have under construction an additional $275 million a day that should be done sometime by the end of the year, first quarter of next year. So within -- by the end of the first quarter of '14, we will have increased processing capacity that is directly connected to our production by over 0.5 BCF's a day. So we feel pretty bullish about the processing capacity and the takeaway capacity in the areas where we operate.

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

Dan McSpirit, BMO Capital Markets.

Current trading levels today of the stock are not far removed from the December 2011 IPO price. Randy, what do you believe has changed most since that time, that the market is missing today? And maybe as important, what should we anticipate changing that could better showcase the value, and with it be better reflected in the share price?

I will let Rick address some of that. In my view, I think we've been a little slow to talk about what we might do. We have tended to, as a company, (inaudible) talk about what we have done. And I think that is a big difference. We are not making projections on what [AFEs] could be. We still, we think very appropriately, a two-stream reporter. I think we have been pretty disciplined in how we go about our business, and I think that is reflected in what we tell everybody involved. Rick, do you want to add to that?

As we've discussed -- and we take a very disciplined and deliberate approach of how we have attacked this asset -- it is not unlike anything that Randy and his management team have done differently for the 20, 30 years that they have the developing other companies, as well. We think in the long run, that certainly pays off and is value-enhancing. In 2012, we spent a lot of time fully-delineating -- well, not fully, but certainly a major portion of our acreage in the Permian-Garden City area has been delineated, and we will work on the others, on the rest of that acreage, over time. We think that is important. Other producers may have taken approach of one or two wells, may have called it all good. We wanted to understand it. There was a lot of data collection in the process. As a result, our capital efficiency appeared higher, and actually was -- our wells were a little more expensive because of the data-collection process.

I think you're going to start seeing the benefits of this. Through our efforts with Halliburton, we have been able to utilize all that knowledge, build our subsurface model, which we think is going to be very beneficial in how we attack the full development of this asset. It is a very rich asset, but it has some complexities to it. There is four de-risked zones that are stacked on top of each other, making up that 1,800 feet of shale potential there. We want to make sure that we are going to maximize the value of all of that resource, and the ultimate value of the company, not just doing what may appear to be the biggest headline toward the near term.

Got it. I appreciate that answer. Thanks.

I would not expect any change in our overall operating philosophy.

Got it. Understood. Thanks. As my single follow up here -- it appears then -- just turning to the balance sheet -- it appears you are about 36% borrowed on the revolver today, although you do have abundant liquidity. That compares to about 20% at year-end. What is your comfort level with borrowings?

I'm very comfortable with where we are at today. We are currently in the process of our semiannual bank re-determination, so that $825 million of borrowing base that we currently have does not yet reflect our year-end 2012 reserves, which, as you recall, increased substantially. Not only did the actual volume of reserves increase, but the value of those reserves, as we've moved to higher-value oil properties, has increased on an even greater extent. Even at our $825 million existing borrowing capacity, or borrowing base, and where we are drawn, I'm very comfortable that the liquidity is more than adequate over the next 18 months or so.

Got it. Thanks. And if I could just fit one more in here, just as a reminder to me, for modeling purposes -- if you could just remind us of the product mix of the Anadarko Basin assets, the Granite Wash assets -- that is, how much NGLs, how much natural gas?

In total Dan, about 60 million a day [MCF] of equivalents.

But on a reserve bases, those Anadarko Basin properties represented about 15% of our 2012 reserves.

Okay. And do you have the makeup of [NGLs] versus natural gas?

Natural gas is going to be about 66%, 65%. NGLs at probably 28% or so.

Got it. Thank you.

Joe Allman, JPMorgan.

This is Jessica Lee from Joe Allman's team. We had a few quick questions on your six horizontal Wolfcamp wells and your Permian acreage. Was that drilled in the 80,000 de-risk locations, de-risk acreage position that you guys talked about previously?

Yes, Jessica, they were all in the de-risk areas.

Does that also include the Mercer well in Sterling County? Is that also included in that 80,000 US acreage position?

The Mercer is a Cline well. And the Mercer is in the de-risked acreage that we have shown publicly.

This year, are you planning to drill horizontal Wolfcamp wells outside of your 80,000 de-risked acreage position? And towards the north of your acreage?

Jessica, you have worked with us a lot. We may drill a few, but I'd say most of our focus is definitely going to be in our de-risked areas.

Okay. And if I may fit one more question in -- in terms of your -- the China Grove acreage and the two wells there, when will we expect to hear about these well results?

I think we are still -- our criteria are, we have to think they are as good as what we have within Garden City, and if Garden City properties keep getting better. So I think we have tried to talk about that those things are about 5% of our capital budget, 5% to 7% I think. And while we're going to maintain some activity there, our clear focus is going to be on Garden City, unless something looks to be as good economically, and I don't know that those two projects get there. We just haven't determined that yet.

Okay. So have you completed that well that you were completing back in April? And you have the well result for that?

Jessica, just -- [what was] actually I think late last year, and we do have a horizontal well completed out there. It is making hydrocarbons. We are trying to understand a lot of things, and like Randy was saying, we do know we have a higher hurdle to compare against, when we look at the Garden City results.

Okay. Great. Thank you.

Jeb Bachmann, Howard Weil.

Just one question for me on your Wolfcamp wells, and I apologize if you already answered this. Looking at some of the other operators in the Basin, they've recently been talking about the use of submersible pumps versus gas lift, and seem to be leaning more towards submersible pumps, in terms of improving their recovery, or ultimate recovery, on these wells. Have you guys done that with your program? Or what are your thoughts on that?

Yes, Jeb, we are definitely still testing some -- we use some submersible pumps, and we are testing different artificial lift techniques. We actually started with some submersible pumps several years ago. So yes, we are definitely testing the various types of artificial lift.

Have you guys come to, or gotten to a situation where you figure one is better than the other? Or are you still working on that?

I don't think we have concluded that one is better everywhere. In some areas, it may make more sense for us to use submersibles. In other areas, it may make more sense for us to use gas lift. Some areas we are still using [drop] pumps.

That is one of the examples of data that we spent time and money on -- literally a couple of years ago, starting the effort to figure out what is the best way to flow back these wells. And again, like Jerry said, we were using gas lift and submersibles a couple years ago. We have some pretty good data in certain areas of what we think is best.

All right. Great. Thanks, guys.

Brian Singer, Goldman Sachs.

Apologies if this came up earlier, but can you add a little more color on the extension Cline well that you highlighted? It got a lower rate, and I was just trying to get some context on what that was -- what and where that was trying to extend, and what that may leave as still open and potentially prospective for the Cline as you go extensively east and northeast, versus what may be condemned, if anything.

We have always said, I think publicly and internally and mentally and culturally, that one well -- one good well or one bad well -- doesn't make the play. Obviously, we were disappointed in that Cline, but we are now of the opinion that maybe it wasn't an effective test of the Cline. We have still not resolved that completely to my satisfaction. There are other things there that we want to test. So it is a disappointment, but we are still -- we are a long way from being done with the Cline, and certainly a long way from being done with some of the Wolfcamp there.

Brian, one of the things I mentioned in my comments is that there were some things on the completion that didn't go exactly like we typically would do. So there's numerous things there that caused us to scratch our head and say -- what really do we have out there? We're not totally sure.

Okay. Thanks. That's helpful. And then, as you think about asset sales -- you talked about the Anadarko Basin potential divestment -- are you considering, or still considering, a potential JV partner inside the Permian?

I think we continually look at how we best should fund the company long-term. I don't think a JV partner is off the table. Our view of all those different financings is that they all cost barrels, and we need to figure out what is the best way for our shareholders long-term. So we haven't progressed very far with that, and we haven't taken it off the table. It is one of the things that we look at pretty often.

Thank you.

Thank you for your questions, ladies and gentlemen. I would now like to turn the call over to Rick Buterbaugh for closing remarks.

I would like to thank you for your time and interest in Laredo this morning. Just as a reminder, we will be releasing second-quarter results on August 8. If you have any follow-up questions, we would be happy to take them later today. Thank you.

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Thank you for joining, and good day.