Ronald L. Hagood - Laredo Petroleum, Inc.

Randy A. Foutch - Laredo Petroleum, Inc.

Daniel C. Schooley - Laredo Petroleum, Inc.

Richard C. Buterbaugh - Laredo Petroleum, Inc.

T. Karen Chandler - Laredo Petroleum, Inc.

Daniel Eugene McSpirit - BMO Capital Markets (United States) Brian Singer - Goldman Sachs & Co. LLC Sameer Panjwani - Tudor, Pickering, Holt & Co.

Securities, Inc. Kashy Harrison - Simmons & Company International Derrick Whitfield - Stifel, Nicolaus & Co., Inc.

Asit Sen - Bank of America Merrill Lynch Joseph Allman - Robert W. Baird & Co., Inc.

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; 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'll 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 second quarter 2018.

We will refer to the presentation by page during today's call. If you do not have a copy of this news release or presentation, you may access it on the company's website at www.laredopetro.com.

Please note, a conforming change has been made to slide 10, as reflected in the version currently on our website. I will now turn the call over to Randy Foutch, Chairman and Chief Executive Officer.

Thanks, Ron. Good morning, everyone; and thank you for joining Laredo's second quarter 2018 earnings conference call.

As Ron mentioned, last night, we provided an earnings presentation that we'll refer to throughout the call this morning. If you'll turn to slide 3, I'd like to point out that the second quarter was successful for the company on many fronts.

We grew production 15% versus the second quarter of 2017, and 6% versus the first quarter of 2018. Completions and drilling efficiencies continued to shorten cycle time, driving the higher than expected completion cap for the year, and resulting in an increase of anticipated production growth to more than 15% for the year.

We grew adjusted EBITDA by 6% from the first quarter of 2018 despite an almost 2% decline in our average realized price per BOE, holding our net debt-to-adjusted EBITDA ratio to 1.4 times, while also buying back a little over 3 million shares during the quarter. On slide 4, you can see that we met or achieved second quarter 2018 guidance for almost every metric, notably, beating guidance on both total and oil production growth.

On slide 5, you can see that our operational performance has been outstanding. Through the first half of 2018, we have seen a 50% increase in the annualized gross completed lateral feet per year per rig versus 2017.

These efficiency gains are enabling us to do more with less. We expect to complete almost 25% more lateral foot than 2017, while utilizing a lower average rig count than we used in 2017.

On slide 6, as we will discuss later in the call, the results of our initial co-development packages have been promising. Our current co-development strategy seeks to effectively develop a contiguous stacked Upper/Middle Wolfcamp resource section.

This is accomplished by developing adjacent landing points with the highest economic returns in multi-well packages, thus mitigating future parent-child impacts. The development of these large packages, and we did complete an 11-well package in the second quarter, is facilitated by existing infrastructure the company has built along its production corridors.

I'll now turn the call over to Dan for further highlights and details.

Thank you, Randy; and good morning, everyone. As Randy mentioned, our operations teams are hitting on all cylinders.

We'll review some of these achievements in the following slides, but I did want to take a minute to briefly mention the tank battery fire that was caused by a lightning strike that we discussed in our press release of July 2. I worked at very few places, where I can remember being as proud of a group of people as I was with Laredo employees, who stepped up and worked around the clock to recover from this tank battery fire.

We were very fortunate that no one was injured in this incident. We did have our newest wall package flowing into this battery.

And if you recall, at the time of this fire, the battery was handling approximately 7,000 barrels of oil per day gross. After the fire completely destroyed the tanks of the battery, we were back up and producing under partial flow in four days and back to pre-fire production levels before the end of the month.

That's an amazing job by some really quality people at Laredo. Now, we'll move on to slide 8.

You'll see in that, our drilling and completion teams are also doing a great job and having record or near-record efficiency in the second quarter. If you look at the left-hand graph, you'll see the drilling efficiencies.

In the second quarter, we drilled an average 10,000 foot lateral from rig accept to rig release in nine days, which is a company record and a significant improvement over 2017. On the right-hand graph, we are looking at completion efficiencies.

For the second quarter, on an annualized basis, we completed 420,000 lateral feet per crew per year. At 1,800 pounds per foot sand concentration, this is close to record performance by our completions team and a significant increase over 2017.

In addition to significant completions efficiency gains, we also made good progress towards meeting our budgeted cost savings in our initial 2018 budget. At the end of the second quarter, we signed a one-year contract that is expected to enable us to fully implement in-basin sand in future completions.

We anticipate savings of approximately $400,000 per well in the second half of 2018 from the use of this in-basin sand. Laredo continues to stay focused on controlling costs, as you'll see on slide 9.

For eight consecutive quarters, Laredo has maintained LOE below $4 below BOE. This level of performance requires a great deal of effort from our field personnel and our frontline management.

Laredo's continuous acreage position and our prior investment in infrastructure also continues to deliver LOE savings, which are estimated to be $0.53 per BOE in the second quarter. Randy mentioned in his opening comments our co-development strategy for the Upper and Middle Wolfcamp.

To-date, we have drilled two well packages with at least 180 days of productions that provides us with meaningful results that you'll see on slide 10. These two packages have a combined 12 Upper and Middle Wolfcamp wells drilled in co-development.

A few observations: We're performing above type curve on oil by 8% and outperforming type curve on BOE by 27%. This outperformance gives us confidence in moving forward with our tighter spacing co-development program.

We're obviously recovering more natural gas and NGL in these tighter configurations, and we're working on optimizing our completions and manage drawdown to mitigate this GOR trend that we're seeing in co-development. On slide 11, we see the performance of our 2017 well completions.

Our 2017 wells were at a denser spacing and shorter-stage length in an effort to maximize total resource recovery. In addition to denser spacing, we also drilled several new landing zones in the Upper, Middle, and Lower Wolfcamp.

We were encouraged by these results, and we are seeing both oil and BOE production above type curve on these more densely spaced wells. As noted in our discussion on the two co-development test packages earlier, we will continue to optimize our well completions and drawdown protocols to mitigate any negative GOR trends that we see in these packages.

In fact, we are doing a managed drawdown test on our Kloesel package to help us know how to best mitigate these GOR trends. As shown on slide 12, our 2016 drilling program is performing very well on both oil and BOE, outperforming the Laredo type curve by 23% and 43%, respectively.

2016 drilling was primarily single-zone drilling in known landing zones with little appraisal or delineation drilling. Our 2015 drilling was dominated by drilling necessary to hold acreage in a very challenging commodity price environment.

We drilled wells in stacked configurations instead of chevron. We utilized 1,100 pounds per foot in sand concentration.

And the performance of these wells is now performing under type curve and is providing a headwind to Laredo's oil and BOE growth. Our midstream and marketing teams also continued to perform at a high level in 2Q.

As shown on slide 14, greater than 85% of our crude oil is gathered at the lease by either LMS or Medallion, eliminating trucks and reducing costs. The LMS infrastructure allowed Laredo to fully place 19,000 barrels of oil a day with less than two days' notice after the Shell breach of our crude oil contract.

It's unlikely we could have placed this crude oil on such short notice without the benefit of being able to deliver the crude oil to multiple locations through our infrastructure on LMS and Medallion. As noted on slide 15, Laredo enjoys an enviable position in terms of our in-basin firm capacity to all the major exit points for crude oil from the Permian Basin.

Our intra-basin firm capacity on Medallion allows us to move our crude oil to Colorado City, Midland, or Crane and connects to over 2 million barrels of oil per day of exit capacity currently, and approximately 4.5 million barrels of oil per day of exit capacity by 2020. As you see on slide 16, Laredo is actively managing our crude oil basis risk, with both physical and financial contracts.

As noted, in addition to our intra-basin firm capacity, Laredo will have 35,000 barrels of oil per day under firm transportation with the start-up of Gray Oak Pipeline by the fourth quarter of 2019. As shown in slide 17, Laredo has natural gas infrastructure over a large portion of our acreage that gives us the ability to move gas to various purchasers, should our primary purchaser be unable to take all of our production.

Our primary purchaser is Targa, and Targa maintains firm capacity on both residue gas and natural gas liquids processed through their plants at levels that should provide flow assurance for Laredo for the next several years. As shown in slide 18, Laredo is invested in water infrastructure across our acreage base.

This infrastructure includes produced water pipelines, water recycling plants, water storage, and fresh water wells on our surface acreage. These assets are estimated to deliver approximately $19 million in net savings to Laredo in fiscal year 2018.

With that, I'll turn the call over to Rick.

Thank you, Dan; and good morning. As Randy showed earlier, we met our second quarter guidance on nearly every metric.

Dan showed the efficiencies we are achieving throughout our operations. And slide 19 details some additional milestones for Laredo, such as our increasing EBITDA, our solid financial position, and the results of our share repurchase program through June 30 of this year.

Adjusted EBITDA, a non-GAAP financial measure that is reconciled in our appendix, increased to $152.5 million in the second quarter. This is up more than 6% sequentially from the first quarter of this year.

More importantly, as shown on slide 20, adjusted EBITDA per net debt-adjusted share is showing consistent improvement. In fact, over the past five quarters, this metric has increased about 1.6 times, which has outpaced the rise in oil prices over this same period.

The impact on debt-adjusted per-share metrics is an ongoing focus of the company, as we evaluate capital investment opportunities. One of these opportunities is the company's share repurchase program.

You will recall, as depicted on slide 21, that in February of this year, our board authorized a $200 million share repurchase program to be executed over a two-year period. Through June 30, we have completed greater than 40% of this program, purchasing nearly 10 million shares, representing slightly over 4% of the then outstanding shares at a weighted average cost of $8.83 per share.

We will continue to evaluate repurchase opportunities under this program while maintaining a financial discipline and a strong balance sheet. We believe that confidence around our expected cash flow is critical in retaining our financial flexibility and our evaluation of investment opportunities.

As a result, Laredo has been pretty thoroughly hedged throughout a combination of physical and financial transactions. We have maintained this philosophy with the physical transactions that Dan described and the current financial transactions that are depicted on slide 22.

As you can see, we have taken a multiyear approach, considering both the actual commodity and basis. Now, following the recent breach of the physical contract by Shell, we have been expanding our financial derivative position.

We take a fairly simple approach to our financial derivatives and continue to use a combination of puts, swaps, and collars. Details of these derivative positions are shown in the appendix of today's presentation.

We announced last night that ongoing efficiencies achieved in our drilling and completion activities has reduced the cycle times for completing wells. As a result, we now expect to complete an additional 7.5 net wells in 2018, up from our initial projections.

As shown on slide 23, this is driving a $45 million supplement to our previously anticipated capital expenditures for the year of $585 million. However, we now expect to complete about 728,000 net lateral feet this year, an increase of nearly 10% from prior estimates.

We anticipate the completion of these wells late in the year, with their related production benefiting 2019. However, we are also seeing positive production impacts in 2018 as well.

As shown on slide 24, we have increased our expectation for full-year volume growth to greater than 15%, while reiterating our expectation for oil growth of greater than 10%. Slide 25 reiterates the guidance for the third quarter, as presented in our release issued last night.

You should note, as presented in our second quarter financials, we have added a line item for transportation expense. Beginning in June of this year, we are now utilizing our BridgeTex capacity to sell leased barrels directly to the Gulf Coast.

As a result, we are guiding transportation expense now in the third quarter of this year at approximately $0.80 per BOE. In summary, we believe the second quarter results as projected and the operational efficiencies that we've demonstrated, coupled with the ongoing success of our co-development activities along production corridors, supports our approach for enhancing value from our asset in the Midland Basin.

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

Thank you, folks. Good morning.

Morning, Dan.

Good morning, Dan.

Recognizing that using borrowed money to buy back shares is not ideal, at what point is the company generating sufficient free cash flow, where such repurchases can continue to be made and where they're material in size?

Dan, this is Rick. As you're well aware, we have a number of investment opportunities, both in investing in our development of Midland Basin; repurchase shares, we think, is certainly an investment opportunity that the Board authorized the program on.

Our free cash flow capability is something that we look at as well, as well as growing the asset and the development of that asset. There needs to be a balance in all those things.

This is not just a sell in a spreadsheet that you can pick out and say, okay, we want to get to this point. There are multiple factors and multiple opportunities that need to be taken into account.

One of those things are things like the operational efficiencies in our field. At the size Laredo is, and we're running three to four rigs now.

We have several completion crews. We have spent a lot of time working with not only our rig operators and our completion crews to make sure that they are operating as efficiently as possible.

You're seeing the benefit from that. And we want to be able to maintain that, so there's a balance of – to keep that level of activity and the development of our field, balancing that with our cash generating capacity.

We are slightly outspending cash flow. We can certainly bring that down into a balanced position.

That would mean less efficient operations likely in the field if we start and stop the use of the completion – the two dedicated crews that we have. But all of this needs to be kept in mind with, where's your current leverage?

Where's your current liquidity? We have substantial liquidity available to the company today.

We think that it's more than adequate to keep us in a very strong position. We have actually continued to reduce our leverage on a debt-to-EBITDA metric, which is one of the things that we look at.

So, we're going to continue to balance all those things. So, I think at a slower growth rate, certain (20:57) can be free cash flow.

You've seen from the presentation and from what we've done that we have done a significant amount of the $200 million repurchase program. We've got about 40% of that authorized amount already completed, but we have done it at a slower pace in the second quarter.

Part of that is some of the impact associated with Shell's breach of the contract and making sure that we understand all the implications of that. Dan talked about the number of optionality that we have had and been able to move our barrels in other spots, but not certainly at the beneficial pricing that we had anticipated from that firm contract that we thought we had with Shell.

So, we will continue to look at a balance of each of those opportunities, while still keeping the company in a very strong position.

Thanks for the answer, Rick. Appreciate the thoughts there.

And just as a follow-up to that, just a question on in-basin sand. How many wells will be completed with the in-basin sand over the course of the one-year term of the agreement?

And then, what happens when the one-year contract expires? Just asking in an effort to get a better sense of how lasting this benefit is to the company.

This is Randy. I'll address the one-year contract.

And Dan, as you know, we've tended as a company, culturally, not to sign long-term contracts. And we've found over the years that while it's occasionally painful, in general, that's been beneficial to the company.

And our view is that the one-year gets us well down the road to a number of other sand mines being online, gets us well down on the road in terms of understanding what that market's like. And so, we picked the one year as kind of the balance between making sure we have sand, local sand and local sand pricing, but we didn't want to sign up longer term or be vertically integrated and have equity position in sand mines.

And that's characteristic of how we look at the service providers to our companies.

How many wells do we think – we're going to use the in-basin sand on all the wells that we complete in the second half of 2018. And then, for the balance of 2019 term of that contract, it would be – every well would be used.

About 70% or so of the sand would come from in-basin sand.

Got it. Again, appreciate the answers and the context, Randy.

With that, have a great day, guys. Thanks.

Thanks, Dan.

Thank you.

Thank you. Good morning.

Good morning, Brian.

You've highlighted both the stronger recoveries of wet gas than expected and also the efficiencies driving your ability to complete more wells more quickly with the 5 to 10 additional completions this year. Can you talk to the weighting each of these is having on your revised production guidance, i.e., how much is due to just the greater wet gas recoveries from past wells?

And how much is due to the increased activity?

Just to be clear, we increased overall guidance and maintained the oil production. Just to be perfectly clear, what we're seeing is that our guidance on oil is something we're pretty accurate in.

We're seeing that as we do some things on the completions, we're seeing a higher initial gas and natural gas liquids content. But the oil is still there, so it's just a percentage question game.

As we've mentioned, we're doing some work on some packages of wells to see if there's production procedures that can perhaps change that initial GOR long enough to be meaningful. And we're seeing early data on that.

We're going to continue looking at that. The issue that Rick mentioned, just to repeat myself, is that we've got some rigs that are really setting kind of performance records in the basin.

We've got completion crews that are setting performance records in the basin. With our acreage, it's pretty easy for us to do best practices and really sit down.

And we've had three rigs side by side. They're literally a few thousand feet apart.

We've had the frac crews side by side. So, those efficiencies are partially a function of just the way our acreage is set up.

So, it's a combination of things. The increase in capital that we just announced, the additional $45 million and the additional wells that that's going to enable us to do towards the end of the year, you really will not see any production benefit from that additional capital until 2019.

Keep in mind that when we start a package of wells, these are anywhere from 8 to 11, 12 wells at a time. The drilling and completion times in order to maximize the efficiencies and recoveries from that block of acreage is going to take a four to six-month period between the start of the investment and when you really have completed your flow back and start to get production from that.

So, this enhanced our supplement to the budget that we have. You'll see the associated benefit with that in 2019, in bringing production in a little earlier than we thought in 2019.

We are seeing some benefit of just the reduced cycle times from 2018 in our 2018 production forecast, but that's a relatively minimal amount relative to the increase in capital.

And Brian, just to complete that and make sure to answer the question (27:54). The guidance increase is driven 100% from just being more efficient and getting more wells done, doing a little bit more with less.

That is helpful color. Thank you for that.

And then just one quick follow-up. The decrease in local sands, is that built into the revised CapEx guidance, or would that represent the ability for further savings relative to the revised guidance?

We talked earlier in the year about what would be a little bit second-half-loaded on reducing capital per well by using local sand. And as we signed that contract, those numbers were kind of already baked into the capital, so the numbers do reflect using local sand.

Thank you very much.

To clarify my previous comment on the additional capital, Brian, that $45 million in the additional 7.5 net wells that we expect from that, that is not a one-for-one. There is also some offsets in the benefit of using that in-basin sand that offsets the total cost of those wells in that $45 million.

Okay. Great.

Appreciate it.

Hey, guys. Good morning.

Good morning.

Hey, Sameer.

So, on previous calls, you've mentioned the need to accelerate the pace of rig additions to take advantage of the inventory expansion implicit in the 32 well per section development. How do the cycle time reductions you're seeing now impact your thought process there going forward?

It's interesting, we show data that makes you think about that up to 32 wells per section pretty positively. We've got a big inventory; and reduced cycle time brings that inventory forward.

But with the length of inventory we have, when you start thinking about 32 wells per section in the Upper/Middle and the other zones we have, I'm not sure that the cycle time as yet has had much significant impact on the actual inventory.

Okay. And then, on the well cost side, I understand there's a lot of moving pieces with the implementation of in-basin sand and these efficiency gains.

But I think you had previously put out a target of $7.1 million. Is that still valid, or is there a better number to be thinking about going forward?

Karen, why don't you...

Okay. I'll take this question.

This is Karen Chandler, Vice President of Operations. So, Randy mentioned that when we put the budget number out, and you're mentioning $7.1 million, we built in cost savings associated with expected implementation of the in-basin sand, as well as other optimizations that we've been actively working on around stage length optimization and fully designed proppant design.

So those things are all ongoing. We've seen a little bit of cost inflation through the year; and anticipating that we're very flat going forward, that inflation's been less than 3%.

So, with all the ups and downs, we've achieved a good portion of the expected $600,000 savings. Had a little bit of offset due to service cost increase.

We're probably on an average 10,000-foot lateral in about the $7.2 million to $7.4 million cost range right now and continue to work on cost savings.

Okay. Appreciate the color.

Thank you.

Thank you.

Good morning, everyone; and thanks for taking my questions.

Good morning.

Good morning.

So, I was just wondering if you guys could share some color on what your operations team on the ground and what your midstream partners are telling you regarding oil and gas takeaway in the Midland Basin today. Just trying to get a sense of what they're actually telling you in terms of current tightness, both on oil and gas.

Yeah, Kashy. This is Dan Schooley.

I'll take the first crack at this. On the crude oil side to start with, again, one of the advantages that we have is that in our dedicated area to Medallion, 100% of the crude oil in that area, which includes everything except our far northern area, is under firm transportation.

So, the crude oil is going to move, can move. And it can move to Crane, Midland or Colorado City.

And what we found to-date from our purchasers is that, that kind of optionality is very appealing. And we are not hearing or seeing anything from our purchasers that would indicate that they're not going to be able to continue to purchase our crude oil, as long as we maintain that kind of optionality.

So, we feel fairly good about where we sit with our existing purchasers. And, of course, we have 10,000 barrels a day of our firm transportation that we take out on the BridgeTex line now.

So, between that and the Gray Oak transportation that we take in fourth quarter of next year, we really feel fairly good about our ability to move crude oil out of the Permian Basin. On the gas side, we obviously sell gas a little differently.

It's at the lease. A big chunk of our gas moves through our own gathering system.

So, we have the ability to deliver our gas to Targa, obviously, to DCP, and to a larger extent, EnLink. So, we have optionality to be able to physically move the gas should one of our purchasers be unable to take it.

And then in our meetings with our primary purchaser, which is Targa, they have given us enough information to where we feel pretty high assurance that they have enough firm capacity, both on the residue and the NGLs leaving their plants, to handle all of the – certainly our production and the production growth that they're seeing from their dedicated producers for the next several years. So, on both counts, we feel like we're in really good shape.

That's great color there. Thank you, Dan.

And then Dan, in your prepared remarks, you were walking us through the type curves on pages 10 through 13. Just looking at the 2015 vintages on page 13, you highlighted that after about 1,200 days that the cumulative oil production is slightly below the type curve.

Does that have any implications for the wells that you're drilling today, or are the completions just so different that really the 2015 wells are just so fundamentally different from the 2018 wells? Just any color there would be greatly appreciated.

Yeah. Appreciate the question, and that's a great question.

The 2015 wells were very different in terms of completions. Those were primarily 1,100 pound completions.

They were also stacked vertically rather than chevroned, which has a different completion mechanics and different effects, as you complete wells that are vertically stacked versus chevroned. So, 2015 was really also impacted by just the well selection that was utilized in 2015 was driven not completely, but we had a large component of that program that was driven by wanting to hold acreage.

So, we may have drilled more Clines, the deepest landing zone we could to make sure we held all of the zones above that and knowing that the Cline was not going to be the best performing well. So, I think the really night-and-day difference in terms of the completion design in 2015 versus what we did and started doing in 2016, and certainly, as we've gone into 2017.

And just to be clear on what we presented, in 2015 we were using a lower type curve based upon different – well, what we were completing the wells at in those days. And I think you'll remember that we increased our type curve in 2016 or so, Ron, and that was based primarily on what we had learned about higher 1,800 pound and other proppant load-ins (37:38) and some other things we were doing on our completions.

So, the 2015 graph is showing performance to the type curve we have. The 2016 and 2017 are showing performance to the type curve that we used and increased in those levels.

Just to make sure we've been clear on that, Kashy.

No, got you. That's it for me.

Thanks so much, and have a good rest of the day.

Thank you.

Thank you.

Good morning, all; and congrats on a strong quarter.

Good morning.

Thanks, Derrick.

Randy, in last quarter's press release, you indicated that Laredo would likely add a fifth rig later this year. Recognizing that you're better protected from basis exposure than your peers, how would you manage operations if you were faced with two quarters of Midland differentials in excess of $20 per barrel?

And I guess, where I'm getting at is, other than potentially completion deferrals, are there other operational measures you could employ?

It's interesting. I think we implied that at some point, acceleration at the end of the year for the fifth rig But what we're seeing and what we have said, Derrick, I think is that we're effectively adding rigs by just how much more efficient we're getting on both the drilling and completions side.

So, I don't know that adding a fifth rig is the right verbiage anymore. I think our view is that with the efficiencies we're getting, which are actually kind of – it's pretty impressive to us, we have accelerated.

And obviously, that was the reason for what we thought was a fairly small capital increase. And you look in, I think, it's slide 5, we're just continually getting better.

Now, I've said now for several years that you cannot keep getting better at the rate we're getting more efficient. At some point, it becomes incremental and not these huge changes we're seeing.

And Karen's, and Dan, and their teams keep proving me wrong, that we are getting much better as we go. So, I don't know that we're committed.

We're probably, I think, sometime going to add a fifth rig. It may be much later in 2019.

But I'm pleased with how much more efficient we continue to get.

Got it. I agree.

The operational efficiencies are impressive. As my follow-up, perhaps for yourself or Dan, to what degree can reduced pressure drawdown and further completion optimization mitigate the initial increase in GORs that you referenced in your prepared remarks?

That's a great question. I may have Jason jump in here and help me out.

But what we're seeing in the very early data on the Kloesel package that I mentioned in my remarks, where we have maintained a fairly aggressive, what we call, managed drawdown regime, on those wells is that we have seen positive results. We're seeing oil cuts at the 80-plus percent level six months or so worth of production – nine months, a little bit off.

Nine months' worth of production, we're still seeing 80% oil cuts. So, we feel that the managed drawdown will be effective.

We need a little bit more run time to see if it's going to be economically effective or not.

And to be – complete that story, as you manage the drawdown, you are effectively slowing the overall – even though you're increasing oil content percentage, you're reducing the overall production from the well. So that's just the physics of how that has to work.

So, we can get a higher oil content, but it comes at some cost of early less production. And so, we're liking what we see.

We're trying to figure out if that's something we can implement or not broader. And that all kind of rolls into the view of by the time the basis differential cleans up in mid-2019 or whenever it does and the basin has a lot more takeaway capacity, we'll have a better view on what we want to do with rigs and what we want to do with managed drawdown.

That's where we're headed.

Got it, very helpful. And thanks for taking my questions.

Yeah. And just to be fair (43:16), with doing managed drawdown on packages of wells, while it may have a pretty big impact on that package, with our base production, it takes a long time to move that needle.

Thank you. Good morning, everyone.

Dan, I think, previously, you'd spoken about going from 5 clusters to 8 to 10 clusters per stage. Can you talk a little bit about what you're seeing in terms of cluster efficiency?

And also, I think you were doing some tests using lower concentration of fluids. Wondering if you could provide any update on how these wells are tracking?

Thanks, Asit. I'll start this out and probably have Karen fill in the blanks here.

I'll start with your question on the lower water concentration wells to begin with, hybrids. We ran the hybrid design on 12 wells in the first quarter.

And of those 12 wells, we had the one package in particular, where we believe that we had controlled enough of the variables, where we had a pretty good test of that. And we had a slickwater well that was bounded and we had a hybrid well that was bounded.

The hybrid wells, economically, if you just looked at the hybrid wells, they performed very well. They're 40-plus percent rate of return type wells.

So, they're not poor wells, but we were in an extremely good area, where we have extremely good rock. And the bounded slickwater well was at 70-plus percent rate of return.

So, the hybrid design in that particular case was not economic, but it did result in good wells, but simply not nearly as good as we would have obtained, had we continued to use slickwater on all the wells. And the second part of the question was?

The 5 cluster going to 8 to 10 clusters?

Yeah. I'm going to let Karen talk to you about clusters.

Okay. So, again, this is Karen Chandler.

I'll just comment on kind of operationally, then we can add kind of performance-wise. So, what we're doing is looking at – we looked at a variety of completion designs through 2017, and really want to focus on maintaining those learnings, particularly with our denser spacing in our Upper Wolfcamp, Middle Wolfcamp co-development, but start to gain some of those efficiencies back.

And you're seeing that in the completions performance that we've shown today. Part of that is just optimization of those stage lengths.

So, for example, we've been completing wells at say, 5x30 foot cluster spacing. We're starting to march that up, but we want to make sure that we maintain the performance of the wells as well.

So, stepping slowly to 7x30, 8x30, seeing those performance improvements and then looking at well performance. Overall, those wells are continuing to perform very well as expected.

So we're getting some of those efficiencies without really seeing any degradation to the performance. And we just need to continue that work on the stage length to see where the optimization point's going to be.

Great. Thanks.

And, Randy, appreciate your thought process on addition of the fifth rig or not at year-end or early next year. But just conceptually, how are you thinking about completion schedule in 2019, whether it's completion or footage?

In light of your completion efficiency, how would you frame that?

It's a subject of much conversation. And again, to repeat, the two completion crews that we have are doing a phenomenal job.

They compete against each other. The acreage is such that they can often see each other.

And we have a lot of conversations with them. And the efficiencies of the completion crews, in some ways, as you know, drives the need for rig count.

And we're not going to let those crews become less efficient. But on the other hand, we're not going to let them dictate our total CapEx spend.

So, I think some part of that answer is, depends on what we see going forward in efficiencies. And I think some part of it depends on what the go-forward cost structure is.

And are we going to see lower costs with more in-basin sand and lower cost with more crews? And again, if that efficiency continues, then I think, you probably are having to think about what your capital spend is going to be in 2019.

Great. Appreciate the color, Randy.

Thanks.

Thank you. Good morning, everybody.

Morning, Joe.

Randy, I want to go back to your slide 6. And I just want to make sure I've got the right interpretation.

So, as you move from 16 well development to 32, if we were to hold the drilling and completion costs constant, my assumption is – and please check these assumptions – you're going to be spending twice as much. And the question is, are you going to be getting twice as much of the resource, or do you expect to get actually less than twice as much of the resource, or do you expect to get the same?

And I think my understanding of your plan is that the goal is to increase NPV per drilling unit. That's what you really – that's the main message here.

You might sacrifice the rates of return some, but you're going to greatly increase the NPV. And I just want to just check those assumptions and see if you have any other key messages.

I think there's a couple of messages, Joe. And directionally, that's a good question.

What we're saying is that in the Upper and Middle, that is a – we've now seen that we could do up to 32 wells. And that doesn't talk about what we might do in other zones, so keep that in mind.

And I think the message you should have is that we're seeing some results, and we're watching those results, but the performance early on makes us want to talk about the possibility of up to 32 wells in that Upper and Middle section. So, we're looking carefully, I think, at the results and the performance,.

And we're really trying to figure out optimization still on stimulations. But rate of return is related to net present value.

If you've got a strong positive NPV growth, then you probably got a strong positive ready return. And if those are both related to hydrocarbon recovery and the pace of that recovery – and that goes back to our comment about the managed drawdown, while it may change dramatically, the package GOR and oil percentage, it's slow to change the overall base production of the company.

So, I think, we've got a unique ability that we can balance NPV and rate of return with recovery and how we actually complete and manage the production. Rick, do you want to add anything to that?

Yeah, Joe, the only thing I'd add to that, I mean, those points and rate of return versus NPV are certainly something that is a constant discussion at the company. There is a trade-off, certainly is impacted by what is your timeframe.

I mean, on a 90-day reporting period, you're probably going to maximize your rate of return. But if we're living with this asset for the life of it, and NPV, we believe, is important, but obviously, the discrepancy between the two and the trade-off is something that you have to constantly look at.

And that's going to change with commodity prices and with the cost of development. The other thing that we've tried to keep in mind is that the parent-child relationship of wells and the size of the packages are important.

So, are you destroying locations? Once you have drilled a section, it's very difficult to come back at a later date, from what we know today, and get the same type of results.

So, you want to get that right from the start as much as possible. So, similar to our capital investment opportunities between balancing cash flows and accelerating drilling, to realize that NPV and share repurchase, I mean, this is something that is a very complex issue.

We believe, from our standpoint, something that we have spent a lot of time and effort on upfront to try to make sure that we get it right, recognizing that rate of return is important and what are your expectations as you develop resources today and the value of those down the road.

Joe, you and I have had conversations about this very subject in which I made the comment that there's a substantial amount of data out there, not only in the Midland and Delaware, but other basins, that the parent-child problem exists. And if you don't address it, it really does create a problem down the road.

And so, on the one hand, our acreage base is such that we could probably drill one-off locations and maximize rate of return, but we'd be penalizing ourselves in the future. The flip side of that, of course, is you don't want to be completely not aware of short-term performance.

So, we're really striving to find a balance. And you and I have had that conversation.

We think that we have the capability to drill up to 32 wells. We think that is a big NPV boost.

But we need to make sure that we do that and really pay attention to short-term performance. And obviously, rate of returns are part of that.

That's great. That's really helpful.

Thanks, guys. And just one follow-up question, a different topic; maybe a sore subject.

This litigation, I imagine, Shell Trading might be listening and its lawyers might be listening, but any update on that litigation you can share with us? I know there'll be some language in the 10-Q in it.

Yeah. I think that the message that we can talk about is that we did file a counterclaim.

That's public in the Houston system. And Ron can help you look at that.

But everything else that I think we'll say, we'll say in the Q, which I think will be filed tonight.

Great, very helpful. Thank you, guys.

Thank you.

Thanks for taking my quick follow-up. Rick, once Gray Oak comes online later in 2019, what will your realizations as a percentage of WTI look like?

Kashy, this is Dan Schooley. Rough ball park estimate is probably in the mid-90s.

So, 90%, 95% of WTI.

Okay. All right.

That was it. Thank you.

Oh, I just wanted to thank you, operator, Sabrina. And I just wanted to tell everybody that we're feeling the operational efficiency we've been talking about for some time.

We're showing at the corridors, and the acreage is paying off. We're looking at consistent performance.

And I think we do have the opportunities to look at rate of return and NPV. So, I just wanted to summarize by saying thank you.

And we're going to be on the road a lot telling this story, so I look forward to seeing you in the near future. Thanks very much.