May 9, 2013
Executives
Richard C. Buterbaugh - Chief Financial Officer, Principal Accounting Officer and Executive Vice President Randy A.
Foutch - Founder, Chairman and Chief Executive Officer Jerry R. Schuyler - President, Chief Operating Officer and Director Dan C.
Schooley - Vice President of Marketing
Analysts
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division Mario Barraza - Tuohy Brothers Investment Research, Inc. Brian D.
Gamble - Simmons & Company International, Research Division Will Green - Stephens Inc., Research Division Gilbert K. Yang - DISCERN Investment Analytics, Inc Abhishek Sinha - BofA Merrill Lynch, Research Division Dan McSpirit - BMO Capital Markets U.S.
Jessica lee - JP Morgan Chase & Co, Research Division Joseph Bachmann - Howard Weil Incorporated, Research Division Brian Singer - Goldman Sachs Group Inc., Research Division
Operator
Good day, ladies and gentlemen, and welcome to the Laredo Petroleum Holdings Inc.' s First Quarter 2013 Earnings Conference Call.
My name is Sue, and I'll 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. Rick Buterbaugh, Executive Vice President and Chief Financial Officer.
You may proceed, sir.
Richard C. Buterbaugh
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 for 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 2-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 a combined liquids total.
If reported on a 3-stream basis, Laredo's barrel of equivalent volumes for reserves and production, including initial production rates and EURs, would increase by approximately 20%, which you should keep in mind when comparing to companies that report on a 3-stream basis. Similarly, Laredo's unit cost metrics will appear higher when compared to those companies that report on a 3-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 noncash, pretax unrealized losses on commodity derivatives of approximately $20.6 million as previously reported and an unrealized pretax 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 component of these assets are not presented as held for sale, pursuant to the rules governing full cost accounting for oil and gas properties.
We have completed the data 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'll now turn the call over to Randy Foutch, Chairman and Chief Executive Officer.
Randy A. Foutch
Thanks, Rick, and good morning, everyone. Thanks for giving us your time today.
I am very excited about the significant progress that we've 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've confirmed the presence of approximately 1,800 feet of shale in 4 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've taken a very disciplined and deliberate science-based approach for the 68 horizontal wells that we completed through the first quarter of 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're reporting the results of this well into practice as we continue to convert potential into reserves and production. We plan to maintain this disciplined approach, both operational and financially, as we move into the full-scale development of this exceptional asset to truly maximize its value to all of our shareholders.
Now I'll turn the call over to Jerry Schuyler, President and Chief Operating Officer, to update you on our operations.
Jerry R. Schuyler
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're up 24% from the first quarter of 2012.
More importantly, we have continued to deliver good well results and made significant progress on implementing best practices and cost control measures, reducing well cost. 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 continued to perform. During the quarter, we completed an additional 8 horizontal wells in Garden City, 7 of these were long laterals and one was a short lateral.
6 of these wells were in the Wolfcamp and 2 were in the Cline. One of the Cline wells, the Mercer B-6-1H, was disappointing, but we had some issues on the completion in [indiscernible] and we don't feel it's a good test of the area.
I won't reiterate all the results, which we've put in our earnings release today. But overall, our well results continued to meet or beat our expectations and we are pleased with the continued progress shown in our horizontal program in each of the 4 identified zones.
I will remind you that we report on a 2-stream basis. We typically don't give 24-hour IP rates because we believe 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 3-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 3-stream 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 had a peak 24-hour rate of 1,780 barrels of oil equivalent per day.
It 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.
The Lane Trust C/E 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 C 27-1HM 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 3-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 wells starting in early 2010. We have tested and developed many of our completion techniques in varying lateral lengths and frac densities in this zone.
The AFE cost is higher because it is deeper and it's somewhat overpressured, so we are drilling fewer of them today. Within our recent Bearkat 150-5H, 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 3-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 4 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 drilling complete cost are now running about $7.8 million for our loan 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 costs 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 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 drilling complete cost 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 5. And we are currently picking up a fourth horizontal rig.
Of these 4 horizontal rigs, 3 are capable of quicker moves between wells when the wells are on the same pad. With these rigs, we are rapidly moving towards a drilling of multiple well pads.
Our current plan is to drill about 70% of our remaining horizontal wells from this -- from these multi-well pads this year. This should help us realize even more efficiencies and result in more overall well cost reductions.
Based on 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 property. As we continue to do some necessary one-off testing, our typical pad developments in some areas will be 4 wells initially that are targeting Upper and Middle Wolfcamp development simultaneously.
Optimally, we plan to drill 2 wells to the north and then 2 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 2 wells.
This 4-well pad will optimize the production in water-handling facilities and offtake infrastructure in an area. After the first 4 wells of the Cline, the remaining 4 wells will be drilled in the future, completing then the Lower Wolfcamp and Cline zones, making the multi-well pad an 8-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 stack lateral in the third quarter. In summary, we've had a very productive quarter, we grew production weighted to our oil properties, we reduced our well cost 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'll turn it over to Rick.
Richard C. Buterbaugh
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 has now increased to approximately 46% of our total production volumes as reported on a 2-stream basis.
We remain on track to achieve our expected 15% production growth for the year. However, the quarterly production growth will appear more stairstep 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 a higher-than-anticipated unit lease operating expense.
The increase in unit lease operating expenses included higher-than-anticipated workover activities. As we continued to implement best practices throughout the field, we expanded the amount of proactive workover activity from our previously planned level in an effort to reduce our downhole failure rate.
Some of these activities have carried over in the second quarter. But we believe these activities are paying off and have begun realizing a reduction in downhole failure rates that we're anticipating.
So the number of service rigs doing general downhole 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 cost with the installation of a saltwater disposal line on a portion of our rig in county acreage that will enable us to pipe more of the saltwater directly to disposal wells and save significant trucking cost. 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 barrels 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 of 2013. Actual cash expenditures for the first quarter of 2013 will approximate $199 million.
Sue, at this time, we would like to open the lines for any questions.
Operator
[Operator Instructions] Your first question comes from the line of Ryan Oatman from SunTrust.
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
Very good Upper Wolfcamp results in the press release, and I do appreciate you guys breaking out the 24-hour IP rates on a 3-stream basis. I think that's intuitive and helpful for us.
Was just curious on these latest Upper Wolfcamp wells. How do they compare versus your type curve?
Jerry R. Schuyler
Well, the 4 that we completed in the first quarter, the first -- the 30-day IP is actually above 15% -- the average of the 4 is about 15% higher. So I mean, all of our Upper Wolfcamps are actually coming in a little higher in the early production stages.
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
Okay. And then at Sugg A 143, obviously the best well of the bid, almost 1,200 barrels a day, 30-day rate, did you do anything differently there?
Is there anything we could expect going forward in terms of productivity improvements there?
Jerry R. Schuyler
The biggest thing that we have done is we've probably gotten more and more efficient and these are longer laterals. So fundamentally, we've been using slick water for -- since early 2010 or late 2009, but bottom line, I think it's probably we're a little more efficient in these things.
We're very pretty happy with our completions.
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
Absolutely. And then this Cline well, the Mercer, about 200 barrels a day first 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 drilled other wells there? I think you guys mentioned something about a couple of mechanical issues on that.
I'm just trying to get a feel for the risking of that Sterling County acreage.
Randy A. Foutch
It's about -- this is Randy. It's about 10,000 acres, I think, more or less.
And we're -- we have vertical, we have some core information that made us want to drill that well. We still have other targets there and we're not sure that we've effectively tested the Cline.
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
Okay. And the reason you feel that it's not an effective test?
Randy A. Foutch
Just to be completely clear, we're not sure that the Cline we tested represents most of that acreage. Let me say it that way.
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
Got it. Okay.
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?
Randy A. Foutch
I don't think there's any real correlation.
Operator
Your next question comes from the line of Mario Barraza of Tuohy Brothers.
Mario Barraza - Tuohy Brothers Investment Research, Inc.
Just digging a 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?
Richard C. Buterbaugh
Yes. We've not given a target yet, not sure that we do.
We've historically, as a company, not made projections on what we may do in those areas a year or 2 down the road. We've talked about what we've done as opposed to something that we may do.
But we're actually pretty optimistic and excited that as we move toward less move [ph], less one-off drilling, less production facilities per well in terms of being able to amortize those, that we're going to have a pretty significant impact. I realize you're looking for a number, but we're not there.
Mario Barraza - Tuohy Brothers Investment Research, Inc.
Okay. No, I got you.
And then you talked about improving your -- the spud to TD on one well down to 21 days. Again, what's the average you're using for this year and where do you -- I mean, how many wells have you gotten closer to this 21-day target?
And would you be able to -- I know we're -- you're shifting more to pad drilling, but would you be able at all to accelerate the completion process?
Jerry R. Schuyler
Yes, actually, there's a couple of wells. I may not have been clear, but on the -- we drilled a couple 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 add 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 -- when rigging up to rigging off, to taking the rig off, and then we have literally 5 days in there for the moves on the 2 different ends, so that's why. I was just trying to make the point that with that 21-day average, I think that's something that we are going to be able to realize on a lot more about wells and obviously, it's going to be fairly material that we do.
Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division
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 for projections for this year, correct?
Jerry R. Schuyler
Well, yes, in the guidance, we had the amount of money and then Rick can talk to that here in a second. What we have, in essence, done is that we shifted a fair money or capital from verticals to horizontals, and this fourth rig is actually coming on in the next week or so.
Richard C. Buterbaugh
The $725 million capital program that we have for 2013 is unchanged. As Jerry mentioned, we're going to -- we are moving from 6 vertical rigs in the Permian Basin down to just 5.
We're replacing that with a horizontal rate. Those horizontal rigs are beginning to drill more pads -- multi-well pads, which, as I mentioned, is going to cost the production growth to be a little lumpier.
We're 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.
Operator
Your next question comes from the line of Brian Gamble from Simmons & Company.
Brian D. Gamble - Simmons & Company International, Research Division
Wanted to touch on those cost numbers that you were just walking through and maybe ask it a different way. When you're talking about TD times of 21 days obviously, a significant improvement from 35 days and that's what's in the plan.
How much of specifically just that component of the costs 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 are there other pieces, other big pieces to that, that we should consider when we're thinking about the -- either next quarter's cost or longer-term cost for those wells in particular?
Jerry R. Schuyler
Brian, first, let me clarify that we did not -- that the wells had averaged 21 days that cut that time off. They are not the type of well that we have modeled into that -- for the Upper Wolfcamp.
Here's 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 5 is the move on the front end and the back and. So if we were to realize these savings on wells going forward, then you'll -- all of that cost would come off of the $7.8 million that we are using.
We use actual costs that we've been able to deliver and that's what the $7.8 million comes from.
Randy A. Foutch
The reduction that we've seen so far today, as Jerry said, does not include that change in spud to finish. Some of that's been service cost, but some of that's just been things that we've done improving our processes and procedures on drilling and complete.
Jerry R. Schuyler
And Brian, the other thing that I would point out is these 2 side-by-sides, we're actually out completing them now, so they were drilled in the second quarter, and all of our Q1 information the capital was not reflected for those wells.
Brian D. Gamble - Simmons & Company International, Research Division
Well, I'm glad you've got some competitive guys, maybe all of your wells should be right next to each other so they can compete, because that 21 days is quite impressive.
Jerry R. Schuyler
Sounds like you've been talking to Randy.
Brian D. Gamble - Simmons & Company International, Research Division
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 don't want to talk too much about the sale, but the Q seem to make it pretty clear that the May comp 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's going on, is that fair?
Jerry R. Schuyler
The 10-Q is accurate as presented and as I mentioned, to begin with, that we're in the middle of the process, we have held a data room and we will make a decision regarding potential divestment of the Anadarko Basin properties later this quarter.
Brian D. Gamble - Simmons & Company International, Research Division
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?
Jerry R. Schuyler
If we divest of the Anadarko basin asset, we would issue new guidance. 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.
Operator
Your next question comes from the line of Will Green from Stephens.
Will Green - Stephens Inc., Research Division
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 frac optimization, is the 27 to 28 on that 7,000-foot pretty good?
How are -- how is that evolving?
Randy A. Foutch
We still have. We kind of view that 7,000, 7,500-foot range as a sweet spot, but we do have plans this year for some longer laterals.
And I don't think we're done yet over the next year or 2, maybe testing 1 or 2 shorter laterals. The frac optimization that we've gone through, we actually started to unslick [ph] a lot of wells out there a long time ago.
And as you know, with 400 feet between clusters and stages, we've narrowed that down, so the 25, 26, 27 for a 7,000-foot is kind of what we think the sweet spot is, but we're not completely done doing some experimenting there. Jerry, is there anything you want to add to that?
Jerry R. Schuyler
No, I think that's good, Randy.
Randy A. Foutch
Will, does that help you out?
Will Green - Stephens Inc., Research Division
That definitely helps. And then maybe we could touch on lease holding.
I know you guys have been, I guess, I would say less efficient. I think you guys have made that remark and that's part of the reason you're seeing these reductions as you guys are moving more towards pad drilling.
How should we think about leasehold drilling this year? You mentioned you're doing pure[ph] Cline tests.
How do you stand there? And then is the beneficiary of this more Upper Wolfcamp wells that look like those were the -- those obviously look like the best results you saw in the first quarter.
How should we think about leasehold drilling this year and as that winds down?
Randy A. Foutch
Not exactly sure what you mean by leasehold drilling, but our plans are to still run 5 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 I think we've drilling one-off locations, very, very deliberately, very, very much in terms of getting the right data spatially across that 80-mile long acreage block we have there.
I think our plans in '13, we wanted to -- we've stated -- plan in '12 was to delineate acreage. We've 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?
Jerry R. Schuyler
36.
Randy A. Foutch
36 wells. So we wanted to build our entire Wolfcamp database and I think '13 going forward will be more Wolfcamp Upper, Middle and Lower drilling than Cline simply because we have a lot of Cline data and that's what we need, to give us the full-fledge development plan in going forward.
Will Green - Stephens Inc., Research Division
Sure. And I guess my point was -- because 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 front.
Richard C. Buterbaugh
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're now moving more into 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.
Operator
Your next question comes from the line of Gil Yang from DISCERN.
Gilbert K. Yang - DISCERN Investment Analytics, Inc
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 sort of reflecting your pad, the commentary about the pad drilling. What percentage of drilling was going to be on pads prior -- previously?
You're saying 70% now?
Richard C. Buterbaugh
We're saying -- well, that 70% for the remainder for the second, third and fourth quarter.
Gilbert K. Yang - DISCERN Investment Analytics, Inc
Okay. And what has been the earnings for that?
Richard C. Buterbaugh
I don't think we had a percentage or -- as we've stated a couple of times, the goal in '13 was to move towards more of a full-field development pad line drilling. And I think when we started the year and announced the budget, we contemplated that we'd 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 more one-off locations, which is one of the reasons why we anticipate that our capital intensity will come down for the second half of this year.
Gilbert K. Yang - DISCERN Investment Analytics, Inc
Okay. And that -- so basically [ph] it's going from 0% to 70% in a way, but in that -- and that capital intensity is dropping from the $7.8 million level as well?
Richard C. Buterbaugh
Yes, that's the -- remember the capital costs 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 costs that we have demonstrated. I think that's an important way to make our decisions going forward, that's how we invest our money, not on dollars we hope to get to and determine if it's economic on a hope-to number.
But the cost that we have demonstrated have continued to improve our economics and we think it is reflective of what we're able to do on the thousands of wells that we anticipate that we will need to drill to fully develop this field.
Gilbert K. Yang - DISCERN Investment Analytics, Inc
Okay. Given that there's more efficiency to come, do you -- and the savings versus your CapEx budget the same, yet the well costs are down 5% to 10% with more to come, do you anticipate that you would be able to drill more wells for the same capital budget or -- and maybe drill faster than 15%, or do you think that maybe you moderate the spending and sort of stick to that 15% target?
Richard C. Buterbaugh
We feel pretty confident today with our 15% target, even though we'll 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.
Gilbert K. Yang - DISCERN Investment Analytics, Inc
Okay. And then last question is are you seeing any benefits to the costs and performance in the vertical wells you're drilling as well?
Richard C. Buterbaugh
We were already pretty good at that because we have 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're a long way today from saying you ought to look at reduced cost on the vertical.
Gilbert K. Yang - DISCERN Investment Analytics, Inc
And performance-wise for the wells, they're pretty consistent with what they've been, so no, you're not able to imply -- employ any learnings that get better volumes or anything like that?
Jerry R. Schuyler
Yes, we are -- this is Jerry. The -- we are improving the performance.
We continue to fine-tune how we're doing the completions on the verticals as well. And in the first quarter, we did realize that there was significant improvement, so we are still making headway there.
Gilbert K. Yang - DISCERN Investment Analytics, Inc
Can you quantify that, Jerry, percentage-wise?
Jerry R. Schuyler
No, no. I mean, rate of return rise in the type curves, I think we showed in the 15% range and I'd say, hey, it's in the 15% to 20% type of range for rate [ph] to return on those wells.
Operator
Your next question comes from the line of Abi Sinha from Bank of America.
Abhishek Sinha - BofA Merrill Lynch, Research Division
Just wanted to touch base on the asset sale. I know you said you don't want to talk in detail, but all I wanted to ask is like assuming that sale goes through successfully, what are your plans for the rigs that you [indiscernible] base and the 3 rigs would be?
Would you lay down, [ph]? Would you move it to Wolfcamp, or any color on that?
Richard C. Buterbaugh
Yes. Abi, as I mentioned earlier, any discussion regarding that potential transaction has already been made.
If there's anything, from a transaction standpoint, we would obviously give updated guidance at that point.
Abhishek Sinha - BofA Merrill Lynch, Research Division
That's fair enough. Okay.
Another thing I wanted to ask is basically, we have been hearing from many companies this quarter, they're experiencing a lot of production curtailment due to capacity constraints in the Permian. I mean, how comfortable are you right now with your productive capacity versus the processing and takeaway capacities available to you?
Randy A. Foutch
I'll let Rick and then Dan take a shot at that.
Richard C. Buterbaugh
Yes, Abi, we spend a lot of time on that to make sure that we have appropriate takeaway capacity. So it's something that we very actively manage, but I will let Dan give you the specifics of that.
Dan C. Schooley
Yes, Abi, we're pretty encouraged. As you've 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 or first quarter of next year.
So within -- by the end of the first quarter of '14, we will have increased processing capacity that's directly connected our production by over half a Bcf a day, so we feel pretty bullish about the processing capacity and the takeaway capacity in the areas where we operate.
Operator
The next question comes from the line of Dan McSpirit of BMO Capital Markets.
Dan McSpirit - BMO Capital Markets U.S.
So your 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 would it be better reflected in the share price?
Randy A. Foutch
I'll 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've tended to, as a company, as it goes [ph] to talk about what we've done and I think that's a big difference. We're not making projections on what AFEs could be.
We're still, we think very appropriately, a 2-stream reporter. I think we've been pretty disciplined in how we go about our business, and I think that's reflected in what we tell everybody involved.
Rick, do you want to add to...
Richard C. Buterbaugh
As we've discussed and we take a very disciplined and deliberate approach of how we've attacked this asset. It's not unlike anything that Randy and his management team have done differently for the 20, 30 years that they have been 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, 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's important. Other producers may have taken approach of 1 or 2 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 than it actually was.
Our wells were a little bit 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've 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's 4 derisked 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're going to maximize the value of all that resource and the ultimate value of the company, not just doing what may appear to be the biggest headline for the near term.
We do not expect any change in our overall operating philosophy.
Dan McSpirit - BMO Capital Markets U.S.
Got it, understood. And as my single follow-up here, it appears -- and just turning to the balance sheet, it appears you're about 36% borrowed on the revolver today, although you do have abundant liquidity.
That compares to about 20% at year end. What's your comfort level with borrowings?
Richard C. Buterbaugh
I'm very comfortable with where we're at today. We're currently in the process of our semiannual bank redetermination, so that $825 million borrowing base that we currently have does not yet reflect our year end 2012 reserves, which, as you recall, increased substantially not only to the actual volume of reserves increased, but the value of those reserves as we move 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.
Dan McSpirit - BMO Capital Markets U.S.
Got it. 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?
Randy A. Foutch
In total, Dan, it's about 60 million a day Mcf equivalent. On a reserve basis, those Anadarko Basin properties represented about 15% of our 2012 reserves.
Dan McSpirit - BMO Capital Markets U.S.
Okay. And do you have the makeup of NGLs versus natural gas, just...
Randy A. Foutch
Natural gas is going to be about 66%, 65%. NGLs, at probably 28% or so.
Operator
Your next question comes from the line of Joe Allman from JPMorgan.
Jessica lee - JP Morgan Chase & Co, Research Division
This is Jessica Lee from Joe Allman's team. We had a few quick questions on your 6 horizontal Wolfcamp wells and your Permian acreage.
Was that drilled in the 80,000 derisked locations, derisked acreage position that you guys talked about previously?
Jerry R. Schuyler
Yes, Jessica, they were all in the derisked areas.
Jessica lee - JP Morgan Chase & Co, Research Division
And does that also include the Mercer well in Sterling County? Is that also included in that 80,000 derisked acreage?
Jerry R. Schuyler
Well, the Mercer is a Cline well and the Mercer is in the derisked acreage that we have shown publicly.
Jessica lee - JP Morgan Chase & Co, Research Division
All right. So this year, are you planning to drill horizontal Wolfcamp wells outside of your 80,000 derisked acreage position [ph] in towards the north of your acreage?
Jerry R. Schuyler
Jessica, you've 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 derisked areas.
Jessica lee - JP Morgan Chase & Co, Research Division
Okay. And if I may just fit one more question in.
In terms of your the China Grove acreage and the 2 wells there, when would we expect to hear about these well results?
Randy A. Foutch
Yes, I think we're still -- our criteria, they have to -- we have to think that is good as what we have within Garden City and our Garden City properties keep getting better. So I think we've tried to talk about the -- 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 2 projects get there. We just haven't determined that yet.
Jessica lee - JP Morgan Chase & Co, Research Division
Okay. So have you completed that well that you were completing back in April?
And you have the well result for that?
Jerry R. Schuyler
Jessica, well, it was actually, I think, late last year and we do have a horizontal well completed out there. It is making hydrocarbons.
We're trying to understand a lot of things and like Randy is saying, it's -- we do know we have a high hurdle to compare against, when we look at the Garden City results.
Operator
Your next question comes from the line of Jeb Bachmann from Howard Weil.
Joseph Bachmann - Howard Weil Incorporated, Research Division
Just one question for me on your Wolfcamp wells. I apologize if you already answered this, but 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 the recovery or ultimate recovery on these wells.
Have you guys done that with your program or kind of what are your thoughts on that?
Jerry R. Schuyler
Yes, Jeb. We are definitely still testing some -- we use 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.
Joseph Bachmann - Howard Weil Incorporated, Research Division
Have you guys come to a -- or gotten to a situation where you figure one's better than the other or you're still working on that?
Jerry R. Schuyler
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're still using flood [ph] pumps.
Randy A. Foutch
That's 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's the best way to flow back these wells. And again, like Jerry said, we were using gas lift in submersibles a couple of years ago.
We got some pretty good data in certain areas what we think's best.
Operator
Your next question comes from the line of Brian Singer from Goldman Sachs.
Brian Singer - Goldman Sachs Group Inc., Research Division
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 rating. We're 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 perspective for the client as you go extensively east and northeast versus what may be condemned, if anything?
Randy A. Foutch
We've always kind of said, I think, publicly and internally and mentally and culturally that one well -- that one good well or one bad well doesn't make they play [ph]. Obviously, we were disappointed in that, that Cline, but we are now at the opinion that maybe it wasn't a pretty -- an effective test of the Cline.
We sort of resolved that completely to my satisfaction. There are other things there that we want to test, so it's a disappointment, but we're still -- we're a long way from being done with the Cline and certainly, a long way from being done with some of the Wolfcamp there.
Jerry R. Schuyler
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 would -- we typically would do, so there's numerous things there that have caused us to scratch our head and say, "What really do we have out there?" We're not totally sure.
Brian Singer - Goldman Sachs Group Inc., Research Division
That's helpful. And then as you think about asset sales, you've talked about the Anadarko Basin potential divestment.
Are you considering or still considering a potential JV partner inside the Permian?
Randy A. Foutch
I think we continually look at how we best should fund the company long term. I don't think a JV partner's off the table.
Our view of all those different financings is that they all cost barrels and we need to figure out what's the best way for our shareholders long term. So we haven't progressed very far with that.
We haven't taken it off the table. It's one of the things that we look at pretty often.
Operator
Thank you for your questions, ladies and gentlemen. I would now like to turn the call over to Rick Buterbaugh for closing remarks.
Richard C. Buterbaugh
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.
Operator
Thank you for your participation in today's conference. This concludes the presentation.
You may now disconnect. Thank you for joining and good day.