Ron Hagood - Randy A. Foutch - Founder, Chairman and Chief Executive Officer Jay P. Still - President, Chief Operating Officer and Director Daniel C. Schooley - Senior Vice President of Midstream & Marketing Richard C. Buterbaugh - Chief Financial Officer and Executive Vice President.

Brian D. Gamble - Simmons & Company International, Research Division Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division Ipsit Mohanty - GMP Securities L.P., Research Division David Martin Heikkinen - Heikkinen Energy Advisors, LLC Gilbert K.

Yang - DISCERN Investment Analytics, Inc Jeffrey Connolly - Mizuho Securities USA Inc., Research Division John P. Herrlin - Societe Generale Cross Asset Research.

Good day, ladies and gentlemen, and welcome to the Laredo Petroleum, Inc. Third Quarter 2014 Earnings Conference Call. My name is Darren, and I will be your operator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. It is now my pleasure to introduce Mr. Ron Hagood, Director, Investor Relations..

Thank you, and good morning.

Joining me today are Randy Foutch, Chairman and Chief Executive Officer; Jay Still, President and Chief Operating Officer; Dan Schooley, Senior Vice President, Midstream and Marketing; Rick Buterbaugh, Chief Financial Officer; Pat Curth, Senior Vice President, Exploration and Land; Ken Dornblaser, General Counsel; and Michael Beyer, Chief Accounting Officer.

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. 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. As a reminder, Laredo reports operating and financial results, including reserves and production, on a 2-stream basis, which accurately portrays our ownership of the oil and natural gas produced.

Therefore, the value of the natural gas liquids is included in the natural gas stream and pricing, not as part of oil and condensate or included in a combined liquids total.

If reported on a 3-stream basis, Laredo's barrel of oil equivalent volumes for reserves and production, including initial production rates and EURs, would increase by 15% to 20%, which you should keep in mind when comparing to companies that report on a 3-stream basis.

Also, Laredo's unit cost metrics will appear higher when compared to companies that report on a 3-stream basis. However, the true economic value is the same. Earlier this morning, the company issued a news release detailing its financial and operating results for the third quarter of 2014.

If you do not have a copy of this news release, you may access it on the company's website at www.laredopetro.com. I'll now turn the call over to Randy Foutch, Chairman and Chief Executive Officer..

Thanks, Ron, and good morning, everyone. Thank you for joining Laredo's earnings call today. I am very pleased with our execution in the third quarter.

As we forecasted, a large number of multi-well pads that began drilling early this year were brought online during the quarter and achieved peak production resulting in 15% production growth from the second quarter of 2014 and up 36% from the prior year quarter.

Also, as we forecasted, this trend is expected to continue in the fourth quarter as we expect to grow production an additional 10% or so from our record volumes achieved in the third quarter. We made tremendous progress reducing our inventory, both horizontal and vertical wells waiting on completion.

Our efforts to access additional completion crews in the contract as spot markets were successful, and we reduced inventories of both horizontal and vertical wells waiting on completion to optimum levels.

As we plan our capital expenditures for 2015 in a volatile commodity price environment, our risk management strategies have given the company significant operational flexibility with more than 90% of our expected oil production and more than 60% of expected gas production hedged in 2015.

Coupled with Reagan service contracts with terms of less than 1 year, we have the ability to make immediate adjustments to our capital plan as needed.

In 2012, as we delineated our Permian-Garden City acreage in anticipation of a full-field development strategy, our efforts resulted in the majority of the acreage delineated from multi-zone development being concentrated in the southern portion of our acreage.

To capitalize on the efficiencies of developing our contiguous acreage position, growing our production and cash flows, we embarked on a strategy of constructing production corridors in the southern portion of our acreage, and we focused the drilling of stacked laterals on multi-well pads along these corridors.

Recent success in industry drilling activities and continued interpretation and ongoing refinement of our technical database has now helped to delineate the resource potential in the northern parts of our acreage.

This, coupled with our proven corridor development program, has put us in a position from a technical standpoint to accelerate development across our entire acreage position. However, this will require additional capital.

We believe our development strategy is the most capital efficient way to access the resource potential of our Permian-Garden City asset and generates the most value for shareholders.

As we've stated in the past, we continually monitor market conditions for potential sources, terms and availability of capital, which would assist us in accelerating the development and value of our Permian assets.

In this regard, we engaged an advisor to assist us on structuring a possible transaction involving a portion of our northern Garden City acreage. We are in the early stages of analyzing possible scenarios and timing regarding such a transaction.

And therefore, at this time, we're not able to provide further guidance and or comment on the likelihood that such a transaction may or may not be consummated or, if consummated, the nature and scope of such transaction. We will have no further comment on possible transaction unless and until we have something definitive to disclose.

I will now hand the call over to Jay for an operations update..

Thank you, Randy. During the third quarter, the company completed 26 horizontal wells [indiscernible]. This doubles the number of horizontal wells we completed during the first half of 2014 to a total of 52.

18 of the 26 completions achieved at least a full month of peak production during the third quarter, leading to production of 32,970 barrels of oil equivalent per day, an increase of 15% in the second quarter of 2014.

14 of these wells were drilled in stacked laterals forming an average of 96% of their respective type curves based on their peak 30-day average IP rates. Year-to-date, we have completed approximately 60% of our horizontal wells in stacked laterals on multi-well pads.

The long-term performance of our horizontal wells continued to confirm the type curves we established for each zone almost 3 years ago. Through the third quarter of 2014, the company has drilled approximately 150 horizontal wells in its Permian-Garden City acreage.

98 which were completed with lateral lengths greater than 6,000 feet in 24 or more frac stages. The 56 horizontal wells with at least 180 days of production history are performing on average at 101% of their respective type curves, while the average of the 37 wells with at least 365 days production history is at 105% type curve.

The company made significant progress in reducing the inventory wells waiting on completion at the end of the second quarter. Completion operations have been running on schedule and reduced our inventory of horizontal and vertical wells waiting on completions to optimal levels that facilitate efficient completion schedule.

Combined LOE [indiscernible] midstream services expense in the third quarter was slightly higher than forecasted. Proactive measures protect well casing leak and higher-than-normal rod repairs in areas exposed to the corrosive San Andres formation led to the additional expense.

Nitrogen injection to mitigate offset fracking pads and additional production logging contributed as well.

Our full field development strategy of drilling stacked laterals on multi-well pads along our production corridors continues to drive efficiencies as we have completed approximately 70% of our horizontal wells along the production corridors in 2014.

Multi-well pad drilling along with our corridor infrastructures significantly improved our capital and LOE efficiencies through reduced trucking cost, centralized compression, water management, and natural gas fuels for our rigs.

Transitioning from trucking to our gathering systems provide a realized pricing increase of $0.95 a barrel and generates gathering service revenue for LMS of $0.75 per barrel from third-party purchasers.

23% of our oil production in the third quarter was shipped through our production corridors, resulting in approximately 800,000 in total benefits to Laredo. Oil production through the corridors is expected to increase to 50% by the end of the year.

Water management infrastructure is provided by LMS, which ensures sufficient water supply, processing and recovery throughout our southern Garden City development area where large volumes of water are necessary to complete multi-well pad.

The first recycling plant is expected to be operational in the first quarter of 2015 with significant benefits expected to accrue to Laredo. Every barrel gathered and recycled within the corridor serviced by the plant will reduce LOE by approximately $0.85 to $0.90 per barrel. I will now turn the call over to Dan for additional update on LMS..

Thank you, Jay. The core principle of Laredo's business strategy has always been to create the optionality to sell product into the most liquid price advantage markets available. For Midland Basin operators, this means avoiding the congested Midland market and being able to access Cushing or Gulf Coast pricing.

To accomplish this, LMS has invested and owns a 49% interest in 88-mile Medallion pipeline that links Laredo's Glasscock and Reagan Oil Stations with Colorado City, Texas. Construction of the initial phase in the pipeline was completed in the third quarter and line-fill was begun.

The pipeline has subsequently become operational and has an initial capacity of 65,000 barrels of oil per day, expandable to 130,000 barrels of oil per day. Smaller expansions to pick up more Laredo and third-party volumes are currently under construction.

Laredo is a committed shipper on the Medallion Pipeline with 10,000 barrels of oil per day of firm capacity that grows to 30,000 barrels of oil per day in 3 years.

Laredo's current expectation is that with additional infrastructure at the our Glasscock and Reagan Oil Stations, substantially all of our crude oil production could be delivered via the Medallion Pipeline, providing us access to Cushing or Gulf Coast pricing and effectively eliminating our exposure to the Midland market by the first quarter of 2015, if desired.

We believe this adds additional flexibility and optionality in marketing product with the best value.

The potential impact on Laredo's netback wellhead pricing, utilizing the Medallion Pipeline to transport our crude oil to Colorado City during the third quarter of 2014, could have enabled us to sell our crude oil into the Cushing and Gulf Coast markets at a premium to the Midland market of between $4 and $5 per barrel.

As a 49% owner of the Medallion Pipeline, LMS shares in the proportionate economics of the pipeline. LMS' share the economics is recognized as income or loss from equity method investee when netted against expenses on consolidated income statement.

As Jay discussed, LMS is providing numerous services to Laredo in the production corridors, including crude oil gathering, low-pressure gas gathering, centralized gas lift and natural gas rig fuel. These services are all delivering benefits to Laredo as either increased revenues, reduced operating expenses or reduced capital expenditures.

The benefits of these services to Laredo are estimated to have exceeded $1.2 million during the third quarter of 2014. We expect these benefits to accelerate as our crude oil and gas gathering volumes increase and as our water recycling plant and water distribution systems become fully operational.

I will now turn it over to Rick for a financial update..

Thank you, Dan, and good morning. As detailed in this morning's news release, Laredo reported adjusted net income of $27.5 million or $0.19 per diluted share. Adjusted EBITDA for the quarter of $142 million represents an increase of approximately 20% from the second quarter of 2014.

Record quarterly oil and gas sales of approximately $200 million or up more than 9% in the prior quarter of 2014, which is driven by an approximate 15% increase in production volumes, which more than offset the 6% decrease in our average realized price.

Combined LOE and midstream service expenses increased slightly on a unit basis, primarily due to the increased well work that Jay discussed. However, total cash expenses on a unit basis for LOE and midstream, production taxes and G&A decreased more than $2.50 per barrel of oil equivalent, an 11% reduction from the second quarter.

Capital expenditures for drilling and completion activities increased nearly 50% during the quarter as a result of the significant amount of horizontal and vertical well completions performed during the third quarter as compared to the second quarter.

We believe we remain on track in 2014 for total capital expenditures of approximately $1.1 billion, excluding acquisitions. Laredo's net debt at the end of the quarter was approximately $1.5 billion resulting in net debt as a multiple of current quarter annualized EBITDA of 2.67x.

As we have discussed previously, this is slightly above our target multiple on an ongoing basis of about 2.5x, but it remains at a manageable level.

We have demonstrated in the past our ability and our willingness to positively impact this metric in a matter that enhances value for our shareholders, and we are actively evaluating options to do just that.

We believe our philosophy of not carrying long-term service contracts and underpinning our cash flow with a strong hedge position provides the company with optionality to manage our capital expenditures, potential outspend and capital structure during the current period of somewhat erratic commodity prices and uncertain service cost.

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

[Operator Instructions] The first question is from the line of Brian Gamble from Simmons..

Your comment there, Rick, let's just start with that. I think that was rather generous to call the market somewhat erratic right now. I know that we don't have a very clear view of anything a month out, let alone for full year '15, but how are you guys thinking about it from a spending standpoint? Obviously, you have great hedges in place.

Fluctuations in oil prices don't do much to your outspend, but given that we've gotten a few comments on the potential asset sale and given that we kind of know what your outspend next year looks like without any additional capital, what -- kind of walk me through how you're thinking about next year at this point?.

As you mentioned, I mean, we do have significant hedges in place for the remainder of this year, as well as for 2015 and even going down as far as 2016 and 2017. So that does give us some confidence in the predictability of a minimal amount of cash flow.

But given substantial reduction in commodity prices and the uncertainty on rather -- on -- at what level and how quickly service cost comes down, we're obviously in the process of putting together our 2015 capital program and taking all those issues into account -- in our consideration of what level -- do we want to spend that.

We certainly have the ability to live within our cash flow. Doing so does impact our production growth rate. It can grow at substantial rate.

But certainly, I think that in this environment, one of our primary goals is to preserve our liquidity and feel confident that we will continue with our goal of being able to self-fund a greater and greater percent of our capital expenditures..

Great. And then maybe as my follow-up, you mentioned all the benefits that you're seeing from your efforts on the infrastructure side, the pipelines, the corridors.

From an efficiency standpoint, let's maybe focus on the well cost angle of it, as we walk into '15, let's just assume service costs are flat and that -- maybe that's too conservative at this point.

Let's assume they're flat, what can well cost be by the end of next year given how much stacked lateral and multi-well pad drilling you guys are planning on doing?.

This is Jay. I'll take that question. We continue to make significant improvements in our drilling efficiency, completion efficiencies. I think in 2014, we've held D&C costs about flat, improving our drilling cost, about outweigh the inflation that we've seen on the completion side.

And we see that things kind of settled down a bit in the Permian Basin, I think we can get another 5% or 10% production on drilling cost in 2015 given the assumption, that things at the completion side at least levels off and stays flat..

The next question is from the line of Matt Portillo from TPH..

Just in relation to your corridor area where you've obviously invested a lot of capital in order to benefit from drilling efficiencies and cost savings.

Just curious how you think about your drilling inventory and how many years you can continue to accelerate development in that area before needing to move outside of the corridor?.

We've talked about that some, and there's going to be multiple corridors. We're actually working on 4 or 5, and the issue, I think, that everybody needs to understand is the corridors, the first one we started has the potential to support something like for 445, 450 horizontal wells.

And you wouldn't want to move in 10 rigs or 15 rigs in that one corridor, but that corridor will be supporting decades of drilling.

And we've proven with the corridors and that's one of our advantages of the locked-up, contiguous acreage is that we can -- we've proven that we can move the product around in-pipe, reduce trucking, we've proven that we can actually frac 4 multiple stacked laterals back to back and -- within those corridors.

So we think the corridors will be contributing to the efficiency for years and decades to come. There'll be more than one corridor, but it is becoming very clear that's the very -- the most efficient way to go. Jay, do you want to add....

We actually will have 4 corridors to be completed by the end of the year, and currently, we're drilling along each one of those..

Our first water reclamation plant will be up sometime into the year, 1st of next year, the end of this year. That has tremendous capability and benefit to us in terms of capturing flowback water, produce water and turning it back around, and that's all being done within a corridor, and the corridors can self-support each other also.

They're not completely independent in that we could move product, move water, should we choose to from one corridor to another one..

Great.

And then, I guess, as a follow-up question, as you guys think about accelerating some of the undeveloped acreage you mentioned potentially monetizing some of your northern position, could you give us a little bit of context around the size and scale of that potential package?.

At this time, we're not going to discuss anything regarding any possible transactions as we talked about in the opening comments. I'm going to have to leave it at that..

Our next question is from the line of Bob Brackett from Bernstein..

Quick question on this Permian-Garden City asset, and maybe I'll strike out.

But can you talk about the timing of the decision to monetize that asset? And could you talk about the philosophy of selling assets at the bottom of the price cycle versus monetizing it now?.

As far as the timing of our decision on this, we have always looked at this as the operations dictates when is the appropriate time to do this. We wanted to make sure that any dollars that we're putting into it -- into that portion of our acreage or not is really done as an investment, not just accelerating activities to accelerate the activities.

With the amount of work that we have done over the last several years in delineating our acreage, understanding how we want to go about the development, building the production corridors, and what is the most efficient way to do this, we think from an operational standpoint, we are ready to move ahead.

We'd accelerate the development of our overall acreage. Beyond that, we're not going to discuss the transaction or possible transaction any further..

Quick follow-up, do you think oil price will rise from here or are we in an $80 world forever?.

Well I think -- this is Randy. I think, first off, I wish we knew. The second point, I think, is from our viewpoint, we need to plan for the worst and hope for the better, and that's one reason why we've always been pretty thoroughly hedged throughout good times and bad times.

We view the hedging program as a mechanism to make sure that we can always pay debt, always pay salaries and maintain a capital program, so we've got plenty of time to -- with our hedges in place, to decide what we think our long-term view of oil prices are. We don't have to do anything right now.

We also have a great operational flexibility with no long-term contracts, and we don't own rigs. And so we've got a lot of flexibility to decide on what our view is of long-term oil prices..

Your next question is from the line of Ipsit Mohanty from GMP Securities..

If I could just ask you to provide a split between your horizontal and vertical productions from the Wolfcamp and how many vertical wells you drilled for the quarter?.

Our split of horizontal and vertical production is somewhere around 55% horizontal, 45% vertical. And in the third quarter, we had 33 vertical wells that we drilled..

And then just looking forward to your Analyst Day, is that where we expect your '15 overall capital introduction outlook?.

Yes. As you're aware, we're hosting an Analyst Day in early December. At that time, we will give you much more detail and color regarding our expectations for 2015..

The next question is from the line of David Heikkinen from Heikkinen Energy Advisors..

I'm not going to try anything around potential transactions no matter how much I want to. Just a simple question then on the reduction in drilling cost.

Can you just give us your third quarter drilling cost and the completion costs, and -- so we can put in scale of 5% to 10% reduction in '15, just on the drilling component?.

I think this year, we averaged about $7.5 million to $8.5 million on drilling complete costs from the Upper Wolfcamp to the Cline wells we drilled. That excludes some of the longer laterals we would drill..

That big issue that you've got to talk about there is -- we've mentioned it in the past, is that we spent a fair amount of time and money on trying to really figure out how to optimize completions.

And I think, what we've saved -- the significant savings we've seen on just the actual drilling, in many cases, we've actually spent that much money or more back on the optimizations of the completions, and we've done -- as you know, and we've talked about it, we've done resin coated sand, we've done ceramics, we've done a number of things, changed amount of sand, changed the spacing on the curves.

And our view is that we think long-term, some of those things we need 6 months, 9 months, 12 months production to see if they're, in fact, economic. So we have spent a fair amount on completions.

The goal there, of course, is, and we know this and we have data to support it, we see in this basin along with the other resource play basins that a lot of your perforations on your stimulations just aren't effective.

And we think that with our database being able to tie back into our 3D, that our goal is to ultimately figure out how to complete those zones that aren't contributing significant production today or not spend that money. So we're pretty excited about the data collection and the effort we'd put in to the completion optimization.

We think that has potential to be very meaningful going forward..

And then on total capital budget, kind of thinking about all-in, 1.35 included and then you think about the acquisitions and your balance sheet. The increase of the budget is one of the things that we got some feedback on. That was kind of negative as you think about '14.

I know you don't want to get into '15 completely, but how do you -- additional bolt-on acreage acquisitions look going forward and how does that fit in to your allocation versus kind of an efficient drilling and completion budget? So I'm trying to get into the balance of continuing to add leases versus that efficient 4 or 5 corridors in development mode?.

We've not budgeted lease acquisitions or any acquisitions for that matter. And the one acquisition we did, we've been actually working on it, 3-plus years, we kind of thought it was dead a number of times. Our view is, clearly, that we have significant data that suggests we have very, very, very good acreage. The well results speak for themselves.

It's difficult for us to add unless we think it's as good as what we have. And in the case of the 1 acquisition we did, we already had working interest in some of those sections. And when you look at the map, it was -- it did block in some of the acreage to put us in a position of doing production corridors much, much more efficiently.

So we're not beating the woods for additional acreage in any mean. It's just not there. But if something came up that was right in -- right in the guts of where our production corridor was going to go or something like that, we might look at it because I think it operationally efficiently gets justified pretty easy.

Rick?.

In addition, that specific transaction where we acquired the acreage, not only does it provide additional efficiencies in the corridor development, it also helps to reduce our CDC requirements on drilling, not only there, but in additional acreage surrounding that area since it was all from the same original leaseholder..

Your next question is from the line of Gil Yang from DISCERN..

The type curve performance is pretty impressive.

Can you talk a little bit about maybe the consistency of that performance across, maybe those 4 different corridors you're drilling in?.

Let me take first crack with that and then Jay. We now have got a pretty big inventory of horizontal wells in all 4 zones. And I think what we're seeing is that the type curves we pushed out 2, 3 years ago are more or less on track, and I think that speaks a little bit to the quality of the data that we collected out there.

We're not having to adjust those. But there is going to be some up and some down. I think that's just the nature when you're drilling 150 wells or so.

So we're pleased that the type curves we pushed out with a lot of help, a lot of stimulation -- simulation effort from some internal people and some external holding up pretty well, but there is some variation.

Jay, do you want to add anything to that?.

These unconventional resource plays are not homogeneous in doing a lot of work to improve our understanding where the best rock is and how to geosteer to keep in the best rock that can change pretty significantly over a short period. The data that we've collected, I think we continue to see improvements in our production.

And -- but through all of our areas, from the north to south, that we're developing, we've seen very good performance from all 4 zones that we are developing..

Do you think that with the data you have, is it pretty predictable, what the variations are going to be or is it not as predictable yet as you would like or hope?.

We pushed out in the past the work we've done on our 3D earth model tying the geophysical, geomechanical properties of the rock to our seismic and tune that seismic to see what's the best rock for performance, as far as hydrocarbon in place, brittleness, TOC, all the factors that make good wells good. We've made a lot of progress.

We'll cover this in a lot more detail in our Analyst Day, show you some of the results that we've had to date in predicting well performance and how we will use that going forward to improve our well performance in each zone..

All right. Second question is just, Randy, you once told me that you thought that joint ventures were one of the most expensive sources of capital because you're giving away the upside.

Does that sort of imply that you have a good enough understanding of the rock that if you sell something that you can really value it correctly?.

I think what we've consistently said is along the lines of what you said, but we view any kind of capital markets or joint venture of selling acreage as, we're looking at barrels. If we do debt, we've got to have barrels to pay it back. If we do equity, we're diluting the barrels at a share we're currently on.

So if we sell acreage, in our case, where we're talking about really hot-quality acreage backed up with a lot of data, there's barrels there that have some quality. Same thing with the joint venture.

What I will comment on is that, we concentrated in the southern part of our acreage because when we -- that's where we started with our first 2 horizontal wells in '09. The acquisition we made, there was a significant amount of data and that's where we concentrated.

We said all along that we thought our northern acreage had a potential, but we hadn't gotten there yet because we wanted to go to the production corridor and the pad drilling.

We'd still say that was the right information, but as we work our data and really reinterpret it and continue to work it, get new data and as the industries drilled some pretty big wells in and around us, we think we now know, Gil, what the cost of how many barrels it would take to do any transaction up there..

The next question is from the line of Jeffrey Connolly from Mizuho Securities..

You have 4 production corridors that are going to be mostly complete by year end and a lot of the infrastructure spend for that with this year, can you talk about how much infrastructure capital is required in '15, kind of a bare minimum?.

Jeffrey, this is Dan Schooley. We will have most of those expenditures done in the fourth quarter, so the spend in 2015 is fairly insignificant relative to what we've spent in '13..

And keep in mind, a lot of that infrastructure spend was not just within the corridors. The pipeline, the marketing capability to get our crude out of the Midland congested area up into Colorado City was included in there. So it was a heavy expenditure year on things that we'll be using for years and decades..

All right. And then, Jay, kind of one for you.

Can you give us any color on the completion optimization program or is it still a little early for that?.

As Randy mentioned, due to these things, it takes 6 to 9 months to 1 year to really understand. And also, it needs to be repeatable. Not just one well at good performance [indiscernible]. And some of our tests, like the resin coated sands, we've had initial great response, as well as produced in longer period.

We've seen those declines come back down in line. We're still wondering if that's really worth the investment. As an example, where you can see great early response in call victory and really, you need time to play this out. So as Randy mentioned, the ceramics and resin coated sand and upstage -- sand per stage, engineered curve designs.

We're still monitoring those and are not anywhere close to declaring victory. Although, a number of those are showing very positive early response. We'll just be watching it and continuing to try to improve our completion program..

Next question is from the line of John Herrlin from Societe Generale..

Close enough. Getting back to your Table 3. It looks like you're getting improved at the margin versus your type curves with the older wells.

You have changed the way in which you're completing wells going forward, so you had a lot of questions already addressing the efficacy of the new well completion designs, but I'm just curious assuming that these are all older completion designs or lateral lengths or whatever, I'm curious as to why you're getting uplift on your curve further out than on a shorter-term basis.

Any reason?.

Production varies. Using a 30-day rate, as we've always said, is pretty dangerous. 24-hour rate is really dangerous, 30-day rate is also dangerous. You just need to see how the wells will perform in a much longer period of time than an average 30-day rate.

Keep in mind, early on in these wells, the produced -- most of zones produced naturally up pacing, and so the well will eventually load up and we run tubing and put them on an artificial lift, and they come back even stronger than when they started. So there is a lot of variability in the first 3, 4 months of these wells.

You've got to be cautious, and it's saying, this is how -- it's a good well or bad well in a very short period of time. That's why we included the data of 6 months to a year. That's really where we'd looked at how are these wells performing and holding up..

John, we've talked about this before, I think, but we really feel like that when you start getting out there close to a year, you can start getting some confidence that you're getting data that's meaningful -- and we show the 180-day, but the completion techniques and how you flow back a well, and you can have a lot of impact on the first month or 2 of that 180 days.

So we tend to look a lot on how the well performs well out there. And that's one of the reasons why we think the optimization process takes some time..

Yes, that's fair, Randy. It just -- it looked differential with the 365 days, that's why I was asking. Next question for me is on your [indiscernible] infrastructure.

Have you considered doing more third party, just given the amount of capacity you have with what you are building out whether it's the pipeline, the Medallion Pipeline or your own gathering facilities?.

John, this is Dan Schooley. We look at that from time to time, but the primary focus of LMS is to provide services to LPI and then make sure that we have optionality and takeaway capacity, and we're focusing on capital efficiencies in making sure that our systems provide benefits to Laredo as a whole.

As we continue to grow and mature and understand the full capacity that's required for Laredo, then, yes, we'll certainly be out looking for an opportunity to offer those services to others in the area that may need it..

The initial goal of the crude oil marketing was with Medallion, we can market our crude within Midland. we can take it to Cushing, we can take it to Gulf Coast pricing, and that was part of our historical core business strategies to make sure that we're -- we don't know which price is going to be best, but we want to make sure we have access to them.

And we've done the same thing on our natural gas or natural gas liquids. We do recognize that, long term, there may be some substantial benefits to LMS. But our primary goal, as Dan said, was to take care of Laredo..

And John, as a follow-on to what Randy said, too, remember that our investment in Medallion Pipeline, Medallion is a shipper, open-access shipper, and they do move third-party volumes other than ours..

Right. Last one for me is another roundabout on your proposed transaction.

Prior to making today's announcement, had you been receiving a lot of calls on that acreage?.

I think our -- I think we've received calls. I think it's pretty clear that we've captured world-class acreage. The well results just speak to that. Can't deny it. Can't ignore the well results.

So the calls have ebbed and flowed and up or down, but I don't think we've ever not had a very long period going by with someone asking questions about what's -- Laredo's got great acreage, 50-plus year inventory, we started off talking about a 25-year inventory, then it went to 30, then it went to 40, then it went to 50, and we haven't attempted yet to de-risk a lot of zones that we know produce well in the vertical.

We've tested them vertically. We know they produce. We haven't yet tested them horizontally, so I think a lot of people recognize the quality.

And yes, there has been inbound calls, and our response has always been the same that, back to the barrel issue, we're going to do what's right for shareholders, but we do think we've captured some pretty high-quality barrels..

Next question is from the line of Brian Gamble from Simmons..

This is a quick follow-up. I was thinking about the wells you completed in the quarter. I know you brought the Halliburton on.

Did you have to resort to anyone other than Halliburton to get those wells done? Any spot frac crews that were brought online? And if so, how easy was it to get those and even further if you want to throw out a price that you had to pay for that, that would be amazing..

I'm sure there are frac companies that we're using would love us to talk about their pricing. We did access the spot market and brought in several other fleets. We do have -- we did the deal with Halliburton. That's working very well. It's our baseline of service. But as you know, the majority of these wells we drilled has been multi-well pads.

As you finish pads, we can't always predict exactly when they're going to finish. It'd be nice if they're all lined up, finishing just as we're completing the last pad. But we have had multiple pads come on, ready to complete at the same time and so we've been able to access spot market to bring in additional frac fleets..

Was that just luck of timing or do you think you just did a good job of managing expectations on getting people on-site at the appropriate times?.

I think we've gotten a lot better at scheduling. Our operation's getting in front of the work we need and some of it has just been opportunity as the frac fleets have become available, and we've been able to secure dates that fit into the program..

Thank you. That's the end of the question-and-answer session. I would now like to turn the call over to Mr. Ron Hagood for closing remarks..

Thank you, Darren. On December 8, we'll be hosting an Investor Meeting in New York City to provide additional detail on our operations and details for the company's plans for 2015. Our registration information is available on our website under the quicklink section.

And thank you very much for joining us for our third quarter earnings call, and good morning..

Thank you. Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Have a very good day..