Ronald Hagood - Laredo Petroleum, Inc. Randy A. Foutch - Laredo Petroleum, Inc. Daniel C. Schooley - Laredo Petroleum, Inc. Richard C. Buterbaugh - Laredo Petroleum, Inc. Jason R. Greenwald - Laredo Petroleum, Inc. James R. Courtier - Laredo Petroleum, Inc. Blaise Matthew Angelico - IBERIA Capital Partners LLC.

Brian Singer - Goldman Sachs & Co. LLC Asit Sen - Bank of America Merrill Lynch Kashy Harrison - Simmons Piper Jaffray Derrick Whitfield - Stifel Financial Corp. Jeffrey Robertson - Barclays Capital Chris S. Stevens - KeyBanc Capital Markets, Inc..

Good day, ladies and gentlemen, and welcome to the Laredo Petroleum Incorporated Third Quarter 2017 Earnings Conference Call. My name is Kevin and I'll be your operator for today. At this time, all participants are in a 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 Ron Hagood, Director of Investor Relations. You may proceed, sir..

Thank you, and good morning. Joining me today are Randy Foutch, Chairman and Chief Executive Officer; Rick Buterbaugh, Executive Vice President and Chief Financial Officer; and Dan Schooley, Senior Vice President, Operations; 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. 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 yesterday's news release. Yesterday afternoon, the company issued a news release and presentation detailing its financial and operating results for third quarter 2017.

If you do not have a copy of this news release or presentation you may access it on the company's website at www.laredoletro.com. I will 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 third quarter 2017 earnings conference call.

The third quarter proved to be another quarter in a series of quarters in which Laredo demonstrated its operational expertise, posting company record production despite operational challenges from Hurricane Harvey, and oilfield service providers struggling to keep up with demand.

While Harvey presented substantial challenges for much of the industry, our operations and marketing teams did an amazing job minimizing disruptions to our operations.

Honing our own field infrastructure and access to multiple processing plants provided flexibility in the transportation of our production and limited the impact of the storms to the company. In addition to operational flexibility, our field infrastructure investments reduced cost and generated increased revenue for the company.

In the third quarter, our unit lease operating expenses reached a company record low of $3.55 per barrel of oil equivalent, the fifth consecutive quarter our unit LOEs have been under $4 per barrel of oil equivalent, a trend we expect will continue.

Oilfield services presented operational complications, especially on the completions front as providers struggled to supply enough equipment, material and personnel to maintain past efficiencies. This is an area in which Laredo management has considerable experience from past cycles.

We are always working with providers in an effort to stay ahead of Laredo's drilling and completion schedule, making sure best practices are shared across crews and focusing on safety. While we did see a few delays in the third quarter, it did not keep us from hitting our production guidance. Laredo is very focused on capital efficiency and returns.

This is evident in how we make strategic investments that have a multi-year planning cycle and generate long-term value. The Medallion Midland Basin pipeline system is a prime example. We recognize the need to move our oil to multiple cell points and not be captive to the Midland market.

We began investing in Medallion about four years ago and, on this past Monday, announced the closing of the sale of our interest in this system for approximately $830 million after fees and expenses, or more than three times our capital invested.

We committed to using the proceeds to pay down debt and have given notice to call the $500 million of our 7.375% notes due 2022. This will save the company almost $37 million in cash interest annually. The company is currently executing initiatives that are expected to further enhance the efficiency of our development plan.

Successful tests to tighten vertical and horizontal spacing and add premium locations in the Upper and Middle Wolfcamp formations are expected to enhance our field development plan. Tighter spacing enables larger well packages which are more capital efficient and minimize parent-child issues.

Additionally, drilling these large packages on our production corridors to take advantage of previous infrastructure investments further enhances our economics.

We are focused on aligning capital expenditures with operating cash flow and expect to generate double-digit annual oil production growth over the next two years, while moving to cash flow neutrality by the end of 2019. I would now like to turn the call over to Dan for an operational overview..

Thank you, Randy. Before I drive into an operations review, I'd like to acknowledge the entire operations team at Laredo. In the face of one of the most devastating hurricanes in the history to hit the U.S. Gulf Coast, the efforts of our team limited the production impact to the company to approximately 300 BOE per day for the quarter.

Third-quarter operations remained focused on executing our drilling plan, while also testing spacing and completion concepts that are integral to the company's long-term development plan. While this may sound easy, it actually places substantial challenges in front of drilling operations and I would like to stress our people have been up to the task.

Operational efficiency is at its best when you are drilling the same type of well in the same landing zone time after time. The company's extensive testing program has varied spacing, landing points, completion design and multiple other variables.

Our operations group has been able to keep on schedule and we expect to meet our annual completion guidance range of 60 to 65 wells. The company's testing programs continue to post positive results.

As referenced on slide 15 in the November Corporate Presentation, as we test new landing points and tighter spacing our results consistently outperform our type curves. Slide 18 shows the design of the six Southern Sugg-Graham wells in the nine-well package.

The results of this package thus far confirm tighter spacing between landing points and an increase in location in the Upper and Middle Wolfcamp formations. Slide 16 shows results of 2,400 pounds per foot testing separate from other tests.

These wells, including nine wells completed in the third quarter, continue to significantly outperform our type curve. The compelling results of our testing program were the impetus for us to accelerate the program in 2017.

Moving into 2018, as testing slows down, we have the ability to adjust our drilling cadence as two of our rigs are on well-to-well contracts, one about to go well-to-well at the first of the year and the last with a six-month term.

As mentioned in our earnings press release, we are currently budgeting $7.7 million for Upper/Middle Wolfcamp 10,000-foot horizontal with 1,800 pounds of sand per lateral foot.

The increase from $6.4 million is due to service cost inflation responsible for approximately $1 million and driven by the success of perf cluster spacing tests, $300,000 for 30-foot cluster intervals versus 54-foot intervals. Our drilling day rates have stabilized and we have seen stable pressure pumping cost since early this summer.

We anticipate a resumption of our trend for both drilling and completion efficiencies to largely offset any additional cost pressure in the near-term.

A primary initiative is evaluating the self sourcing of in-basin sand, which we estimate could save approximately $400,000 to $500,000 per well, and a corollary initiative of increasing the clusters per stage in our 30-foot cluster spacing design that we estimate could reduce completion cost by as much as $350,000 per well.

I would now like to turn the call over to Rick for a financial update..

Thank you, Dan. As you have seen, quarterly production of roughly 60,000 BOE per day was a 17% increase from the prior year period and up 2% sequentially from the second quarter of this year.

These third quarter volumes were at the midpoint of our initial guidance for the quarter, though at the bottom end of our increased expectation that we issued in early September.

Although our teams did a fantastic job working through the various challenges following Hurricane Harvey, we did experience some negative production impacts in gas processing and the timing of bringing new wells online following the release of that guidance.

Increased realizations for oil and NGLs were offset in part by lower natural gas prices for the third quarter when compared to both the prior year and prior quarter. For the third quarter of 2017, oil price realizations increased to 94% of WTI.

This was due to a pricing election we were eligible to make based on our crude oil purchase agreement with a third party. Expecting Gulf Coast pricing to remain at a significant premium to Midland and Cushing, we expect to continue electing the Gulf Coast delivery point until the expiration of this contract in June of 2020.

Our expectation is that our blended oil price realization through the end of the contract will remain in the low to mid 90% range. We have guided oil price realizations to 94% of WTI for the fourth quarter of 2017 due to the strength of Gulf Coast pricing as Brent pricing has widened from domestic pricing.

Please note that, as disclosed previously and further described in our Form 10-Q that is being filed today, this contract is in litigation. Cash operating costs of $8.39 per BOE for the quarter are down about 7% from the prior year quarter and up slightly from the second quarter of this year.

The quarter-over-quarter increase was driven by higher production and ad valorem taxes, which were primarily due to higher oil prices, as well as higher cash G&A from increased legal and employee costs.

As a result, net income was $11 million and adjusted EBITDA, which is a non-GAAP financial measure, increased to just over $130 million for the quarter. Capital expenditures for the quarter were about $175 million and we now anticipate total capital to be about $630 million for the year.

You will recall that during our second quarter earnings call, we advised that we were experiencing some upward pressure on service costs which, if sustained, could increase our total capital by 5% to 10%.

We have continued to see pressure primarily on completion costs that, when applied to our second half of the year activity, equates to an increase of about $35 million.

We also anticipate that due to our program of drilling larger packages of wells, which is to take advantage of operating efficiencies and better total resource recovery, we expect to have a larger number, than previously anticipated, of wells that are in progress at year-end. This increase in work in progress is about $25 million of activity.

Additionally, following the positive initial results that we have seen on our testing program, we have expanded that testing program in the third quarter to accelerate the data capture. These activities as Dan described are increasing our 2017 capital by about $35 million.

As a result of these factors, we have increased our original capital budget by $100 million for 2017.

Our decision to accelerate the testing activities was also driven by our desire to complete the 9 to 12 months of data capture as soon as possible in order to expedite the application of these learnings and our confidence surrounding the sale of our Medallion interest.

We announced this past Monday the closing of the sale of our interest in the Medallion Midland Basin pipeline system. In rounded numbers, we received net proceeds after fees, adjustment and expenses of about $830 million. Relative to our $276 million investment in Medallion, we have a gain of $533 million.

About 75% of this gain will be recognized in the fourth quarter of this year. The remaining gain will be deferred and recognized over the remaining contract life of our firm transportation commitment with Medallion. Tax leakage from this transaction is expected to be minimal with AMT of approximately $5 million to $7 million.

Pro forma for the sale of our Medallion interest, our net debt defined as total debt less cash, as a multiple of the annualized third quarter adjusted EBITDA, a non-GAAP financial measure, has been reduced to about 1 time.

We have the flexibility to use 100% of the proceeds from this sale to retire long-term senior notes of which there's $1.3 billion outstanding today. We have already given notice to call the entire $500 million of our 7.375% notes. This provides annual interest reductions of about $37 million.

Keep in mind that we also have $450 million of the 5.625% notes that are callable today and the remaining $350 million of 6.25% notes become callable in March of next year. In the interim, we have used proceeds from this sale to totally repay our credit facility.

The sale of the Medallion interest, the testing activities that are being completed, the short-term nature of our rig contracts, the carryover drilling and completion activities and our low operating cost structure provide significant optionality to the company as we work our 2018 capital program.

With the continued volatility in commodity prices and service costs, we have a strong desire to balance cash flows with capital expenditures. We believe that this is obtainable within the next two years while still providing consistent production growth.

In fact, in the current environment, we believe that we can achieve repeatable low-double-digit production growth with a capital program of about $550 million and be cash neutral in 2018. With a mid-teens growth rate, we believe cash neutrality could occur by year-end 2019.

Laredo's overriding focus has always been to maximize the value of its large contiguous acreage position. We know that this acreage contains up to 4,500 feet of prospective hydrocarbon-bearing rock in multiple stack formations. Obviously, balancing the recovery of these resources in the most capital efficient and timely manner maximizes its value.

We believe that to do so also requires a thorough understanding of the complex interdependencies of the multiple landing points within the multiple stack formations. The spacing and completion optimization tests being performed today will ensure true value enhancing investments to maximize this value.

Operator, at this time would you please open the lines for any questions?.

And we'd also like that you limit yourself to one question and one follow-up. Our first question comes from Brian Singer from Goldman Sachs..

Thank you. Good morning..

Good morning, Brian..

I wondered just, if you could talk a little bit more on the production mix side. I know there were some issues with the storm on bringing new wells online that you highlighted. So I wondered if you could talk about maybe the one-off impacts that that had on the production mix falling a little bit below your guidance.

But then how that translates into fourth quarter where you expect to ramp up in both oil and gas volumes, the mix staying a little bit more at that 44% type range? Thank you..

I'll get others to jump in on this. But as we drill the longer laterals, which we think are pretty economic, the clean-up time, the flow back time and everything else is just longer, which you would expect. And that's caused us to not have some of that flush production. Jason, do you want to....

Sure. Hi, everybody. This is Jason Greenwald, Vice President of Reservoir Engineering. So, on the production mix, this is an issue that I think we've talked about several times in the past. And I think in one flavor or another it's how production comes online in a particular quarter.

And so, for these 15,000-foot horizontals that we drill, I think it's important to, kind of, recognize a few things. One, we're doing this for the first time and I think very few are drilling wells of this length. And so there's going to be things to learn about how to flow back the wells.

And I think the other part is that 15,000-foot wells, that's equivalent to 4.5 10,000-foot wells and if you went back all the way to 7,500-foot wells that would be equivalent to 6. So, they are, kind of, an outsized size of the program in that quarter. But again, it comes back to how production comes on in a particular quarter..

Got it, thank you. And then my follow-up question is the commentary you made on achieving free cash neutrality potentially by the end of 2019.

And I wonder behind that, if there are some key areas of efficiency gains or productivity gains you could talk to versus where you are today, specifically if there are any targets for, where operating costs could go to improve margins to help the case for free cash neutrality or anything you can comment on the capital efficiency with regards to capital costs..

That's something that we always think about. And as you know, we're enjoying some of the lowest LOEs in the basin. And we keep that regardless of Medallion and that's a result of investments that we made starting several years ago. If you look at the cover of our presentation, you can see four rigs set up in a production corridor all side-by-side.

And that's been very, very helpful for us to look at best practices when you are drilling, I've said before, when you're drilling that close you can look at every 30 minutes and figure out what's really working and not working on the drilling side.

We have a similar, kind of, program on the completion side and which we really look at every minute of non-productive time. So, a year or two or three ago, we've been saying that we were dramatically improving our cost structure, decreasing costs, drilling more footage per rig.

And I think we've said consistently that that rate of improvement has to slow. So, I still think that we've got incrementally improvements coming, but I don't think it's going to be near like what we've seen in the past years..

The other things to keep in mind, Brian, through the sale of our Medallion interest, we expect to significantly reduce our interest costs, which will add cash flow on that side of the equation, as well as the contract that we have renegotiated on some of our transportation, which is getting higher realized prices than we had seen in the past, also adds a meaningful positive to the cash flow that we're generating.

On the expense side, as Randy mentioned and we've talked about we think the pace of our testing budget will slow meaningfully in 2018 relative to the accelerated activity that we did and are still doing in the third and fourth quarter of this year.

And as Dan identified earlier there's significant opportunities in our well cost structure that we believe, some of these tests will prove out to be economic and we are pursuing those opportunities to reduce the per well cost of our program.

Keeping all of that in mind, we are very focused on bringing our cash flow and capital expenditures into balance as quickly as possible.

There are things that we need to consider as we do that to make sure that we're maintaining the operating efficiencies that we have worked really, since the inception to be able to create and even improve upon those..

Brian, I think just to – what we're really trying to do is, we know that there are a lot of things we've done to increase production short-term and maybe long-term.

And what we're really trying to do is figure out what the sweet spot is in terms of how much sand, in terms of what kinds of sand, in terms of actually cluster spacing or stage spacing or even what window we need to drill that lateral in. We've drilled some of those laterals in literally 10-feet windows and that costs money.

So, where we are is that, we've done a lot of testing to try and figure out really where the sweet spot is such that as we go forward we maximize our capital efficiency everywhere we drill and not have to do so much testing on a number of different factors..

Thank you very much..

Our next question comes from Asit Sen with Bank of America Merrill Lynch..

Thanks, good morning. So, I have a question on the press release where – you mentioned, Randy, about LPI's focus on return on capital employed. And historically LPI has always had a multi-year planning horizon.

So, wondering if you could frame for us a ROCE target or anticipated roadmap for return on capital employed?.

We have always looked at things in the context of what's best for shareholders, not necessarily this quarter, but long-term in terms of making sure that we maximize the value that this wonderful acreage base can generate for shareholders long-term. Return on capital, NAV, rate of return, all of those factors are things that we look at.

And I think if you even go back, look at our corporate compensation, about 75% of it I think is tied to, one way or another, being very, very efficient on capital and rate of return, return on capital. So, that's, kind of, how we think and believe this business should be run long-term.

That means that we're not always drilling the best rate of return wells in our portfolio. Earlier at Laredo, we drilled deeper wells trying to make sure that we understood the total section, but also to hold our acreage by production. We've drilled wells and packages making sure that we didn't create parent-child issues.

We started talking about that three or four years ago. So, while we're very, very focused on return on capital and other parameters, all the way through including the compensation, we're trying to do it in a long-term basis.

And part of the issue for us is that, we believe that it takes 6 months, 9 months, 12 months to really understand the economic results of some of this activity. So, this quarter we triggered a lot of testing and now we're in the process of really trying to figure out where the sweet spot lies on a number of those factors..

Great, thanks. I appreciate the details on quantifying for the pressure on completion costs. Could you speak to the current operating environment heading into, say early next year? Because I think I heard you mention stable pressure pumping costs currently..

We've, kind of, had the view, and we've seen this before, as you know, that we try not to sign long-term contracts for service providers. We've seen time after time after time that we want the latest and best equipment, the best personnel, the best crew. When you do that, when things get tight you've got to scramble some.

But the service providers do a pretty good job, we think, of fixing any kind of a demand arbitrage and that's exactly what we're seeing. Certainly on sand, sourcing local sand is probably a very good example of a big demand that wasn't easily satisfied.

And then there's literally numerous mines being permitted and some of them will fall by the wayside, but some of them will work in the local area. So, I think our view is that we didn't think the low, low, low service costs that we saw were sustainable. We didn't pay a fee to reflect the low. We saw the increase really start a few months ago.

But what we've seen since then is that there's been supply come to the party, come to bear, and I think it's, at least, somewhat muted if not held flat some of the service costs. So, it'll be interesting to see what that balance is and clearly it's become more of a completion crew cadence than a drilling rig cadence.

And there's probably still a little bit of a shortage on completion crews that Laredo wants to use that we think have the kind of equipment we want, have the kind of safety and personnel training and attitude that we want, but they're coming..

Thanks. I'll just sneak in a quick one.

So, on completion cadence, how should we think about first half 2018 relative to the 60 to 65 in 2017? Any early thoughts?.

Yeah. We have not announced our 2018 program yet. Some of it will be – first quarter obviously will be somewhat dependent upon activities in the fourth quarter.

But those are the things we are working through right now as far as how the completions in 2018, whether we're running our current level of activity or a lower amount will impact all of those items..

Thanks a lot..

Thank you..

Our next question comes from Kashy Harrison with Simmons Piper Jaffray..

Good morning, all, and thanks for taking my questions this morning..

Good morning..

So, in the prepared remarks, Dan, you provided some estimates for well cost savings moving forward.

I was just wondering, do you have an idea of when you expect to consummate the agreements to self-source sand and when you may get to the point of increasing the clusters per stage?.

Thanks, Kashy. What we're seeing on the sand front is that, there's been a lot of local sand mines that have been announced, a very small – a much smaller number that's been permitted and then an even smaller number that's actually come online.

So I think the sand, being able to self-source the sand in the quality and the quantities that we're going to utilize is probably going to take some time to get up and running at any kind of strength in 2018. We do feel like the completion design savings that we highlighted in the discussion this morning, those can come quicker.

That's something that we obviously can control. But moving to the more perfs per cluster is going to help us in terms of cycle time, so it's going to reduce the cost of our completion design. That change can come fairly quickly in 2018..

Got it.

And then segueing into Rick, your sensitivities for the path to cash flow neutrality, I was just wondering, did those estimates incorporate the potential cost savings that Dan was talking about or was that predicated on the $7.7 million well? And additionally, when you provided – when you guys ran through the numbers, were you using the base type curve or were you incorporating the outperformance you're currently seeing on your wells?.

As far as the program that we run, it's going to take into account the specific wells that we anticipate drilling in 2018 and 2019, but those wells are going to be adjusted based upon lateral length, where they are in the acreage block, what other wells are around that.

So it takes into account our best estimate of what the program would be at this time.

As far as the cost structure, it does assume some benefit in the cost reductions that Dan has talked about that we feel more comfortable with and really the timing of how those would be incorporated into our 2018 program, as well as the interest savings and the price realizations that I talked about earlier..

Got it. And if I could just sneak one more in and break the rule for the two questions.

Once these longer laterals start to clean up over time, should we expect the oil mix to start to tick back up to about 45% or should we just, kind of, stick with what we're seeing in 4Q?.

As we've talked about previously and in the past, we're going to continue to see volatility in that oil mix, would expect it to be in the range of 43% to 46%. If there is a significant package of wells that comes on early in one quarter that could move even higher. But, kind of, the midpoint of that range is the best expectation on a long-term basis.

If you look at Laredo and you look at our proved developed reserves and the product mix on that from our base production, obviously it's a bit lower than what we would expect new wells to be coming on. But as that base continues to grow, it's going to be more and more difficult to have a meaningful impact on that.

But that's not out of the ordinary for any of the producers in the Basin..

Got it. Thanks for the time and have a good rest of the day..

Thank you..

Our next question comes from Derrick Whitfield with Stifel Financial..

Thank you and good morning..

Good morning, Derrick..

Randy as a follow-up to Brian's first question, could you comment on how your spud to peak production times are expected to evolve in light of the transition from 8,000 to 10,000-foot laterals with less intensive completion designs to 10,000 to 15,000 laterals with more intensive completion designs?.

I'll get Dan to give a better answer as far as specifically. But obviously, as we've gone further out on laterals that takes more time, and not so much on the drilling side, but more on the completion side, there's just more stages to drill out. What we've seen is that there is a penalty for staying in a very tight zone on the laterals.

If you're trying to drill within 10-feet that adds to the drilling time, just in terms of directional controlling the well and also in some cases the rate of penetration per foot of lateral. And so, I think the testing that we've done certainly in this quarter has cost us some efficiencies on drilling and completion days.

But that was one of the reasons why we wanted to get that testing done is where we could start building the 6, 9, 12-month production history, and make sure that that efficiency we lose on cycle time is more than made up on the base economics and that's, kind of, where we are.

Dan, do you want to comment on cycle time?.

Well, obviously 15,000-foot laterals are a steep learning curve for us because there aren't any others to even look at, and in terms of third-parties to even share data with and understand what's going on.

So, it's going to take us some time to understand how those wells are going to perform and what the type curves that build up to peak production is going to look like on a well 15,000-foot in length. So, it's just going to take a little bit of time and we've just put those wells on production. So, good things are coming we hope..

The other thing to keep in mind is that all of our wells, whether they're the 15,000-foot or even 10,000-foot laterals, are being part of much bigger packages.

So, the overall cycle time of a well package is going to lengthen, which is going to cause – at the current rig cadence is going to cause lumpier production growth on a quarter-to-quarter basis.

But we believe it's much more efficient from an overall operation standpoint and value creation to ensure that we're drilling these wells in packages, minimizing parent-child issues and maximizing the recovery of the resource..

Right. All of that that Rick is talking about extend cycle time. From spud to first production it's going to continue to move out..

Understand, that makes sense. And then my follow-up would be regarding slide 14, the work that you guys have done on the completion evolution front is quite remarkable.

What's your sense on how the effective frac length has evolved from the base design to second half 2017 testing?.

I will let – others maybe help out a little bit, James, but what we're really trying to do is to make sure that we impact consistently and we know what we've impacted consistently in a 3D sense around each wellbore such that we can then consistently come back and know what spacing we should be using in drilling the wells.

If you look at the base design you can see that we had, kind of, the linear design. If you look far to the right it was much more of a circular kind of a target.

And if we can consistently define the amount of that zone in a 3D sense that we are impacting effectively, that allows us to continue to talk about how much greater inventory we have when we do the chevroned drilling and so on and so forth and that's been very helpful.

Now the key to all this, and we haven't really talked about it some, is that we all know the recovery factor in a block of this acreage has been pretty low. And what we're trying to do is maximize that recovery factor by efficiently impacting more of the rock for each well and not have the frac run away from the well in some areas, or not.

James, do you want to add something to that?.

I think what I would add is we continue to use all of our data to try and build predictive models. The field is a very expensive laboratory, so we try and understand what's going on with our entire data set.

So, once we have an idea/concept we then go and test those concepts sequentially and that's what we've been doing throughout the year as Dan and Randy have talked about. And that concerns both multiple landing points, it concerns the nature of the completion and how those two components interact with the relative spacing between wells.

And so all of that work is geared towards getting the best return out of a unit area of rock..

Okay, got it. Thanks for taking my questions..

Thank you..

Your next question comes from Blaise Angelico with Iberia Capital Partners..

Hey good morning, everyone. You guys are drilling some of the longest laterals in the Basin. This is, kind of, a technical question I guess, but I was hoping you could maybe help me better understand it.

So, as you drill these longer laterals, can you maybe talk about the effectiveness of artificial lift relative to that of a shorter lateral? Do you guys see any challenges with having these longer wells flow as expected relative to a shorter one? Thanks for any comments you guys have on that and I'll hop back in the queue..

It's interesting to see there was – a major company announced they were going to start drilling 15,000-foot laterals yesterday or the day before. And their acreage is blocked up, which is, kind of, what we've been saying for several years.

The concerns that we had going into this was, can we actually mechanically drill it? We satisfied that and we think actually the way we're set up with our team, Dan and Karen's teams, that we could drill longer if we wanted to. We were concerned somewhat about our ability to complete and we've satisfied that – that we do have completion.

So, where we, kind of, got to was we wanted to make sure that, to the extent we could, we drill that lateral without a lot of – variance vertically dips and sways and increases such that the fluids entering the wellbore have a better opportunity to flow to the vertical part of the well.

All of our artificial lift, and it's mostly gas lift on the early days, one version or another of gas lift, that is where we get fluids that enter the vertical part of the well. So, to some degree the length of the horizontal part doesn't really impact the effectiveness of any, kind of, artificial lift.

You just expose more fluid to the vertical part of the well, so your design criteria has to be different for the gas lift. But the artificial lift, once we get the fluid to the vertical, doesn't seem to be a big issue at all..

Got you. Appreciate it. Thank you..

Thank you..

Our next question comes from Jeff Robertson with Barclays..

Thanks. Good morning..

Morning, Jeff..

Randy, you all talk a lot about trying to improve capital efficiency, and I'm just curious if you can talk a little bit about the concept of drilling more 15,000-foot laterals. I think you say you have 500 land-ready locations in the Upper and Middle Wolfcamp.

But how would the capital efficiency, on a development of 15,000-foot laterals for that acreage compare to, say, if you could only drill 10,000-foot laterals?.

The advantage of the 15,000-foot laterals are, we set up on a location and you can drill literally double the amount of – or increase by 50% from a 10,000 to a 15,000, the amount of rock that you're exposing with that drill. And it doesn't take that much longer to drill that extra 5,000 feet. We were surprised at how effective that was.

So, you then look at capital efficiency in terms of, you're bringing water to that location for the frac. You're taking water away and all the other liquids. And we're doing that within corridors, so we're reducing the number of locations we actually have to build on the surface; we're reducing the number of times that rig has to move.

We're reducing the set up on the frac crews. We're reducing the surface needs in terms of making sure that you've got water everywhere. And also utilizing better and better of our water takeaway – and we haven't talked about the water recycling, but that plays well to 15,000-foot laterals.

So, what you're really looking at on a development basis is you just need less infrastructure. You drill less vertical wells and all of the surface facilities that go with more vertical wells and you're more effectively handling fluid..

So, the improved return, is a lot of it cost? I guess, not only – obviously, drilling fewer wells to develop the same amount of reservoir, but you've also got a lot of facilities costs that will be spread and therefore also help your capital efficiency pretty substantially, correct?.

Yes, you got it. And just to further that, if you're drilling one-off wells four or five miles apart as an example, to frac that 10,000-foot or 15,000-foot well, you've got to have some pretty significant water handling, both into it and out of it after you've completed it.

And that limits, I think, in some ways, some people's ability to drill longer laterals. In our case, with the way we've set up in our corridors, we've got the water handling facility to a significant degree, certainly in the immediate area. And we also have to a significant degree the ability to hand the flush frac water production.

It just uses a lot less surface area and just everything about it is beneficial. We can also – the way we do that 15,000-foot is that, it allows us to not lose sight of multiple future zone development as we – I mean, we've got a lot of zones that produce on this acreage and at some point I think most of those zones will be drilled.

So the way we're set up with the corridors and the infrastructure and the 15,000-foot, that gives us effectively more surface area to drill other zones within those corridors..

Okay. My second question is you all talk about the $7.7 million for a 10,000-foot Upper/Middle Wolfcamp with 1,800 pounds of sand. But it seems like the outperformance that you highlight are wells that use 2,400 pounds per foot.

Can you talk about the difference in cost just on the proppant side and the completion side for the increased fracture intensity?.

Yeah.

I'll let Dan address it, but the point I want to make on that is that we've seen, Jeff, time after time after time things that early on, the first week, the first day, the first two months, three or four months, that yielded a better production rate, but failed to, over time, keep that production far enough above the type curve that it paid out the extra cost.

And so that was one of – we've tested actually more than 2,400 pounds of sand.

So, that's one of the things that I think our testing this quarter and stuff we've done before was geared to do, was really let us optimize what production gains you get over time with 6 months, 9 months, 12 months production and really try and figure out exactly what's the amount of sand that we want to do.

And keep in mind that sand is just one part of the spacing issue. And if we could, for example, do less sand and contain the fracs that we show on page 14 – I think it's 14, better and add significantly to the inventory of wells that we have and get a better oil in place recovery, we may not need to go to more sand.

So Dan, after that long-winded, what's the answer?.

Great introduction..

Yeah..

Yeah, I think obviously it depends on the spacing design and the completion design that you choose. We tested 2,400 pounds in nine wells in the third quarter, but all of those were at fairly significant spacing, they were at 5x54.

So, when you look at page 14, you can understand to the left is what you see – what you get in the models when you use 2,400 pound sand and the bigger cluster spacing.

And what we've been driving to is a smaller connectivity around the wellbore and trying to contain that frac, so that it doesn't have these long planar shoots on it like you see on page 14. And we're doing that, we think, better actually with 1,800 pounds of sand, at least, in the Upper and Middle.

In containing that frac closer to the wellbore that allows us then to tighten up the spacing and maximize the NAV across this asset..

Thank you..

Our next question comes from Chris Stevens with KeyBanc..

Hey good morning guys. I was just, kind of, curious about 2018.

At this point, if oil prices continue to firm up here, are you going to use that extra cash flow to just minimize the cash flow deficit, or is there a point where you would add that extra rig?.

I think, we're not talking about 2018 specifically and I wish I had better ability to predict oil prices. But what I will tell you is that, we've tended to look at the efficiency gains that we've made both in terms of the ability to drill and the ability to complete.

I think it's difficult to say that we would accelerate with more rigs without something pretty dramatic happening. I think we're getting very efficient. In fact, the way we're set up with no long-term contracts we could drop rigs. The real question I think comes to your cadence on completions.

And I think where we are drilling multiple well pads, you really need to drill four, five, six – whatever the number of wells on the pad are, before you talk about completion. So, I think we have a lot of flexibility on what we would use any extra cash for, and still have good production growth.

Rick?.

Yes, as we mentioned earlier, our focus is to get cash flow neutral as quickly as possible that makes sense. But as we've always done, we've let the data really indicate the correct cadence. We've done a lot of testing and we're going to complete a significant additional test through the remainder of this year.

We talked about that, the initial results are obviously very encouraging. We're trying to fine-tune those tests. But you're going to need 6, 9, 12 months of production history to truly understand the economics of those tests. So, we will really focus on the data, the results that we're getting there to help dictate the proper cadence..

Okay, understood. And I guess just following up on a previous question, it sounds like you're, kind of, trending more towards sticking with maybe lower proppant loading of about 1,800 pounds per foot. And I guess drilling a little bit tighter well bore spacing with some of these stagger-stack pilots.

Is that tighter spacing – with the wellbore spacing and the stagger stack, is that something you're going to do on most of the upcoming pads at this point with more of the 1,800 pound per foot going forward?.

I think you ought to view us as having tested more sand and we're seeing initial results that are positive. But I think also if you look at in our presentation, page 18 or any of them, we can add significantly to our inventory if we can control the zone around the wellbore that we impact.

And that probably makes you lead towards maybe less sand, 1,800 – not less than 1,800 but around the 1,800, not the higher sand packages.

And that again goes back to our view about what's best for this acreage long-term because increasing – adding zones in the Upper and the Middle and increasing the inventory of things that we have to drill has a huge impact on the NAV for the company.

So, to your question, I think we're probably more in the 1,800 mode than we are higher, but we still want to see more production information before we really call that in terms of (57:15) I think, the thing you need to keep in mind is that, we've tested 11 configurations of the chevroned landing points.

And it's been between two to four separate landing points. And we want to make sure that we get significant history on those. But if we can add that many landing points to the Upper and Middle, we've just significantly increased the value on an NAV basis of what's very high value acreage already in those zones.

And so, that's, kind of, what our goal is..

Okay, got it. Understood, thank you..

The other thing to keep in mind on that is, once this acreage is drilled it's very difficult to come back and get some of those other landing points. So, you want to understand as best possible, as much as you can, about interdependencies within those zones and drill it right from the onset.

Otherwise you are going to lose substantial potential value that could be created from your existing acreage..

And I'm not showing any further questions at this time. I would like to turn the call back over to our host..

We appreciate your interest in Laredo. Thanks for joining us for our third quarter financial and operations update. Have a good morning..

Ladies and gentlemen, this does conclude today's presentation. You may now disconnect and have a wonderful day..