Good day ladies and gentlemen, and welcome to Laredo Petroleum Inc's Fourth Quarter 2019 Earnings Conference Call. My name is Jimmy. And I will 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 call is being recorded for replay purposes. It is now my pleasure to introduce Mr. Ron Hagood, Vice President Investor Relations. You may precede, sir..

Thank you and good morning. Joining me today are Jason Pigott, President and Chief Executive Officer; Karen Chandler, Senior Vice President and Chief Operations Officer; and Michael Beyer, Senior Vice President and Chief Financial Officer 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 non-GAAP financial measures. Reconciliations to 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 fourth quarter and full-year 2019. 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 Web site at www.laredopetro.com.

I will now turn the call over to Jason Pigott, President and Chief Executive Officer..

Good morning and thank you for joining us on the call today. I would like to start off today by reviewing some of highlights from the fourth quarter listed on slide three.

We again surpassed guidance for the fourth quarter in a row for both oil and total production, and maintained our peer-leading cost structure Turning to slide four, not only did we have a good quarter, but 2019 was a transformational year for Laredo defined by a deep list of highlights too numerous to mention on this call.

However, there are several significant ones that I would like to mention this morning. While many companies were talking about hitting their positive free cash flow, we achieved in our second quarter ultimately generating $60 million in free cash flow in 2019 as the company reduced capital expenditures by 25% from the full-year 2018.

Additionally, we were able to grow oil 2% and total production from 19%, while delivering free cash flow [technical difficulty] capital program.

This would not have been possible without the dedication and focus of our operation teams who cut well cost by $1 million, reduced our well cycle times, and kept our operating cost at basin-leading lows as we reduced our lease operating expense from $3.08 per BOE for the full-year 2019 from our 2018 cost of $3.76 per BOE.

A shift to wider spacing was also a key contributor to our success. Today, wider spaced wells outperformed our oil type curve by 12%. Our hedging strategy also helped mitigate the impacts of commodity price improving our revenue by $48.7 million. We also have significant hedges in place for 2020, which Michael will describe in more detail shortly.

Described on slide five, and as we have highlighted on previous calls, the most important part of our strategy is to optimize our operations on our existing footprint. Every day we look to improve well selection, completion designs, facilities, and every aspect of our business to maximize our stakeholder return.

Another aspect of this strategy is to look at our inventory with fresh eyes and determine if new completions [technical difficulty] can bring fresh life to additional zones for development. As we mentioned in product updates, we believe there is additional upside on core footprint in the Cline. We are just starting flow back our first two Cline wells.

Our preliminary field estimates indicate both wells are significantly under the $8.2 million well cost we identified when we highlighted the Cline as a higher [technical difficulty] rate target last year. Both wells are continuing to [clean it up] [ph] from our high intensity frac designs and the initial results are very encouraging.

I hope everyone on the call can appreciate the strength we have as a foundation and a competitive advantage it provides us as we look to the future. One of the things I found in my life is that hard work can open a lot of doors for you.

Our cost leadership and balance sheet strength opened a couple new doors for us as we completed two accretive acquisitions last year; one in Howard County and one is Western Glasscock.

These acquisitions align well with the second pillar of our strategy to increase and improve the quality of our inventory by shifting to higher margin and higher return areas of Midland Basin, while maintaining our commitment to a strong balance sheet.

As we show on slide seven, both acquisitions were completed at evaluations significantly below historic averages allowing us to maintain a competitive leverage ratio.

The close proximity to our existing acreage position allows us to use our strengths as we have drilled our first well on Howard County as expected, and continue to transition our rigs to the area.

As an early bonus to the year, we are able to acquire additional 1,100 acres in the heart of our position in Howard County for $22.5 million, increasing our total position to 8,380 acres. This acreage will increase our working interest on our operated acreage from an area from 83% to 96%, and increase our net well cap from 100 to 124 net wells.

While our cost per acre was higher in our previous purchase, the efficiency of the investment was much higher as the cost for net well was 28% lower than our previous acquisition. We are in the process of incorporating the impacts of this addition in our planning as well as the impacts of lower commodity pricing for the next three years.

Our development plan will pivot to production maintenance mode focused on remaining cash flow positive at $50 a barrel and delivering over $100 million in free cash flow at $55 price. The high oil yield for our new acquisitions will allow us to improve our oil collection over 40% during this time period and improve our margins.

I will now turn the call to Michael for financial update..

Thank you, Jason. Continuing on slide eight, we are very happy with results of our recent senior notes issuance. We are able to address our pending maturities in 2022 and 2023 rolling them out to 2025 and 2028, accomplishing this in a very challenging high-yield market for E&P companies.

Despite the downturn in commodity prices, we remain committed to operating within cash flow, excluding non-budgeted acquisitions. As Jason mentioned, we believe we can generate a modest level of free cash flow over the next three years, and a $50 per barrel $2.25 per MMBTu environment.

This projection grows to at least $100 million and $55 per barrel with the same natural gas price. Our plan is to apply to free cash flow that is generated to paying down debt with the goal of reducing debt to adjusted EBITDA to our pre-acquisition level.

Similar to the first quarter of 2019, we expect to outspend cash flow in the first quarter of 2020. Like 2019, we plan to utilize free cash flow generated during the remaining three quarters to reduce debt incurred in the first quarter. Turning to slide nine, we get details of our strong 2020 hedge position.

Our 2020 hedges are expected to generate more than $150 million of realized hedge income at $50 per barrel and $2.25 per MMBtu, supporting our cash flow for the year as we transition to our more capital efficient Howard County acreage.

We will continue to evaluate opportunities to hedge in 2021, where we have already hedged 1.5 million barrels of oil at Brent price of $60. I will now turn the call over to Karen for the operations update..

Thank you, Michael. As Jason mentioned, the shift in our development plan to wider well spacing driven by our returns and free cash flow focused strategy was a key driver of our success in 2019. Throughout 2019, we completed six widely space packages consisting of 38 wells.

As shown on slide 10, combined oil production of these widely space packages has outperformed our type curve by 12%, which contributed to the company exceeding oil production guidance every quarter in 2019.

Another key driver of our wider success last year was the continued progress made by our operations teams to improve operational efficiencies, reduce cycle times, and wring costs out of our already low well cost. On slide 11, the top graph shows our continued upward trends in both drilled feet per day per rig and completed feet per day per frac.

In fact, we set company records for both drilling and completions performance in the fourth quarter of 2019. These improved operation efficiencies and reduced cycle times also contributed to the company exceeding production expectations as wells were consistently put on production earlier than anticipated.

As shown on the bottom chart on slide 11, these performance improvements and continuous focus on cost reduction had allowed us to reduce our average well costs to peer-leading levels. We were also able to deliver the 2019 drilling and completions program below budget, even with additional activity.

On slides 12 and 13, we expand on the second pillar of our strategy that Jason discussed. We have now closed on three transactions in areas of the basin with higher oil productivity that are established acreage position. On slide 12, we show the specific locations of these acquisitions in Howard and Glasscock Counties.

Through these transactions, we've added 175 gross locations, or approximately three years of inventory at our current activity levels. Moving to slide 13, I'll expand on how we look at our current development opportunities.

In short, we plan to develop our highest rate of return wells first, fully leveraging our peer-leading drilling, completions, and operating costs.

The graph at the top of the slide demonstrates the positive impact of cash flow generation that results from putting our cash flow to work in the new Howard County and Glasscock County areas, versus our existing acreage.

The table at the bottom of the slide further demonstrates the well economics of the recently acquired locations that are expected to lead to substantial improvement in capital efficiency.

Turning to slide 14, since our initial Howard County acquisition, our development plan has revolved around quickly and efficiently transitioning our drilling and completions activity to Howard County.

To accomplish this, we've accelerated our first quarter drilling and completion activity levels, bringing in fourth drilling rig and second completion crew. This will enable us to complete all of our activity on our established rig in Glasscock acreage in the first quarter of 2020, and allow us to fully transition to Howard County more quickly.

We already have two rigs operating in Howard County, and the third rig is expected by the end of this quarter. We expect to begin completion activities our first 15 well package in Howard County during the second quarter.

This month, we executed an additional bolt-on transaction on our Howard County acreage, primarily increasing working interest on existing or regular operated acreage. The acquisition increased our location count by 24 net wells and similar values to our original Howard County acquisition, which was well below historic averages.

Additionally, we're in negotiations with multiple third-party infrastructure providers that operate in Howard County. At this point, in the development lifecycle of this area, sufficient infrastructure hasn't built the combinator development plan, minimizing the need for capital investment.

Initial indications are confirming our expectations that transportation costs will not be significantly different. From what we pay on our establish acreage position in Reagan and Glasscock County. From an operation standpoint, our transition to Howard County is on track and going well.

I just want to emphasize again that our D&C activity in 2020 will be higher in the first quarter. And we complete the remaining well packages on our established acreage to accelerate activity on our Howard County position.

As we work to finalize our 2020 budget, we expect the activity to moderate in the second-half of 2020 as we move to normalize development pace in Howard County and balance capital expenditures and cash flow for full-year 2020.

Moving to slide 15 and 16, I also want to highlight some of the company's key focus areas related to minimizing environmental impact of our operations. ESG is moving to the forefront of the E&P industry and rightly so. Water management and air quality are important to all of us. Laredo has been focused on delivering on these principles for years.

On slide 16, you can see in the top [chart that] [ph] that we have continually focused on increasing the percentage of recycle water used in our completions to significantly reduce the amount of freshwater needed for our completion operations. We've accomplished this by building out 54,000 barrels per day of water recycle capacity.

We're currently using 40% recycled water in our completion operations. For full-year 2019, this reduces our demand for freshwater of more than 11.5 million barrels. The bottom chart on 15 shows the amount of flared and vented gas related to gross gas production for 32 companies in the Permian Basin, beginning in 2018.

We are very proud to be on the chart where we are relative to our peers. Our current 1.7% of flared gas is less than half of the peer average over the past two years. We're proud of our results focused on minimizing the environmental impact of our operations and protecting the environment.

In addition to the water recycle infrastructure I just mentioned. Slide 16 also highlights additional infrastructure we have in place to help reduce the environmental impacts of flaring and trucking.

Importantly, this slide also shows that these investments are not only the right thing to do to protect the environment, but also to enhance our overall economics. With that, I'll turn the call back to Jason for some closing comments..

2019 was a transformational year for Laredo as we started to pivot our strategy using our strengths to our advantage. In 2020, we will begin to reap the rewards from our recent acquisitions as we benefited from more capital efficient development plan or being protected by our 2020 hedges and debt maturities, which have been pushed into the future.

There aren't very many companies undergoing transformation like we are executing as planned. I'm very excited about our future. Operator, we can now open the line for questions..

Thank you. [Operator Instructions] The first question comes from Brian Singer with Goldman Sachs. Your line is now open..

Thank you. Good morning..

Good Morning..

Can you quantify a bit more the CapEx trajectory through the year? You talked about the initial ramp up of activity happening now here in the first quarter.

What are the implications of that for CapEx, and then how do you see that falling off extensively as we go through the remaining quarters of the year?.

Yes, this is Jason. If you look at kind of what we've done in the past, I think we're going to model that very similarly to what we've done before. So, we're front-loaded with the activity.

I'd like Karen to kind of go into some of those details, but we're very front-loaded, and then again activity will kind of drop as the year progresses, but I'll let Karen give you some of the highlights of that activity..

Yes, just to add to that, so -- Jason, again, 2019 was very similar for us. So, you know, our expected as we kind of finalize in 2020 budget, is that we'll be running one frac crew, plus about two-and-a-half months of an additional frac crew. So, for us in 2019, similar cadence we front-end loaded all those additional completions.

We're doing the same thing for 2020 with the two frac crew starting in January. So, expectation is that we'll be down to one frac crew by the end of first quarter. We've also picked up the fourth rig.

The primary reason for that was to really get ahead and accelerate our transition to Howard County to get the drilling down to the frac crew, the single frac crew could move in there.

So, expectation there, running the four rigs to kind of make that transition as quickly as possible will most likely be down to two rigs by the time we move into the second-half of the year..

Great.

But no specific numbers that you're putting out on either the first quarter or the full-year?.

No, not yet. Again, we will come out with a full budget here shortly. One of the things that we highlighted [technical difficulty] that we added 1,100 acres in Howard County, it's right on top of the drilling footprint, and so, we as a company are 100% dedicated to being a free cash flow positive and staying that way.

So when you've added working interest in NRI in the area that you're drilling, we just wanted to get tight on our budgets. So, we'll come out with new numbers shortly, but it's a good thing for us to push it out, because again, we closed on this acreage just over a week ago.

So, just trying to factor that into our planning as we go forward, but we're excited and look forward to kind of rolling that out shortly to you..

Great. And then my follow-up is with regards to the balance sheets.

Slide 16 highlights how you compare relative to peers, and you've talked multiple times here on the free cash flow, can you just talk about where you ultimately see or desire your net debt-to-EBITDA to go, or what is the steady state net debt-to-EBITDA that you're targeting, and then what is your tolerance level as you think about further bolt-on acquisitions to [indiscernible] that at least temporarily?.

We've highlighted before that our goal is to get it down to pre-acquisition levels before we started this, and ultimately, to help the company, you want to be driving it down to 1.0 or something like that. So, we're 100% dedicated to driving that number down. We're just working through the levers that create that opportunity for us.

We've got water infrastructure that we look at all the time, we've got royalty minerals that we could monetize. So there's lots of options to help us push that number down. We're thinking through all those.

When we think about the kind of M&A activity we're looking for things that would be more like the Glasscock, where you're bringing in production as you do those in this environment. There is stress on some companies that have less healthy balance sheet.

So, we're looking for things where we can pick up production and get the inventory at lower rates, and then be able to use our drilling machine to optimize and develop those.

So that's kind of what we're thinking about for the future, but ultimately we're looking to push that debt-to-EBITDA down and not flex up, and so, we're just -- we will navigate that as we start to look at these opportunities..

Thank you..

Thank you. Our next question comes from Asit Sen with Bank of America. Your line is now open..

Thanks. Good morning.

So, Jason, on the strategy to further expand inventory depth in the Howard County, how do you see the runway, and what's kind of the funding strategy here, if you go by doing that?.

Yes. Again, we're working through that, there's lots of things that are kind of turning through the market right now. We're trying to find those things that would be a good fit for us.

Again, we've got a balance sheet that we can use to our advantage, and it's just a matter of again, looking at what's the appropriate discount rates on PDP, those are getting probably a little bit higher these days than they've been in the past.

So again, I think that allows you to pick up some production and not stretch your debt-to-EBITDA, but those may be things again, where we pick up something and then look at monetizing the water system. So, we are again just working through that right now, but the goal is not to really increase our debt-to-EBITDA to drive it down over time..

Got it.

And my follow-up is for Karen, Karen, you noted that the up-spaced wells are producing more oil than originally anticipated, what's driving the delta in your opinion?.

Yes, as we've got in here in the slide, I think slide 10 in our in our deck, where we're kind of showing overall the well performance of all the wider-spaced packages. So, we are seeing kind of variability around the type curve that we have released. On average, we're 12% above. So we're very happy with that performance.

We do think that continues to support the type curve that we have out there with well performance both above and below the curve. Performance, we went to the 1320.

These packages are both single and co-developed, and I think that we're just getting good performance from the completion design work that we're doing, made the right decisions I think on the spacing..

Great, thank you..

Thank you. Our next question comes from Richard Tullis with Capital One Securities. Your line is now open..

Thanks. Good morning. Jason, looking at the one key production guidance, it looks like it's roughly flat quarter-over-quarter.

How does the well growth cadence look quarter-over-quarter for the rest of the year, particularly since you're planning to bring on it looks like around 28 net wells in 1Q? So that's about 10 more than the fourth quarter, so is that production kind of rolling into the second quarter? How do you see that playing out?.

Yes, I will let Karen answer that, but yes, we were definitely front-end loaded, so you'll see the impacts in the following quarters..

Yes. So I'm going to refer to slide 10 again, same slide in the deck. So, our cadence looks very similar to what we did in 2019. We're front-end loading any additional activity. So, overall, that helps with the annual well growth and also cash flow for the year.

So, if you look at the 2019 oil production, actual production numbers on a quarterly basis, we expect to see the trend very similar to that.

So we're doing kind of the heavy front-end loading on the completions right now and the existing acreage, we will really see that impact in second quarter, and then the trend, therefore, going forward from there is we should again see kind of an uptick in Q4 that we didn't see this year as the Howard County will start to come on..

Okay. Thanks, Karen. That's helpful, and then just lastly, Karen, Laredo has done a great job with reducing cash controllable cost over the past couple of years. You see a small uptick in the Q1 guidance compared to the fourth quarter.

How do you see the cost trending as we move through the year as you move more activity away from your kind of traditional production core door centric areas?.

Yes. So, as we're transitioning to Howard County, I will talk about kind of our infrastructure in place and what the plans are for going in developing there. We do expect to see a little bit of an uptick as we're transitioning in, but something on the order of that $0.20, so doesn't really significantly impacting the overall LOE numbers..

Okay, that's all for me. Thank you..

Thank you. Our next question comes from Derrick Whitfield with Stifel. Your line is now open.

Yes, thanks. Good morning all, and congrats on a fourth consecutive strong quarter..

Thanks, Derrick..

Perhaps for Jason or Karen, Permian flaring is becoming a topic of increasing investor concern as outlined in your prepared comments.

While flaring is less of an issue for Laredo, what are your expectations for the upcoming Texas Railroad Commission report, and what changes, if any on flaring regulation do you expect?.

Well, I hate to speculate, again what we see there, but I think what we're trying to emphasize that whatever comes out we're well ahead of it. We've had a focus on reducing emissions for a long time and build our facilities, so that we don't have to flare the times we flare when there's just some disruptions downstream from us.

We don't have to flare to sell our oil. So, I think that's -- for us we think we're in pretty good shape, no matter what comes out, we will be waiting for it..

Thanks, Jason.

And then there's my follow-up for Karen, could you speak to early time expectations for D&C design and costs for your Howard County wells, and more specifically, do you anticipate being able to maintain your peer-leading D&C costs as you pivot into Howard County?.

Yes, so we've already moved two of the rigs in onto Howard County, so all the operations are going really well there. We wanted to accelerate that to take advantage of the increased oil productivity of those wells, but everything on track from just to surface planning and then getting the rigs in.

So, the answer is yes, our expectations are that we're going to be able to operate at very similar to levels to what we've been doing on the existing acreage position from the D&C and already managed, mentioned from LOE standpoint as well.

We've done a lot of work looking at the offsets in the area, there's quite a bit of spacing test and other things in the area that we've been able to take advantage of, so looking at completion designs and right now we're doing a little bit of work looking at a little bit bigger completion designs on the existing acreage, we plan to do that there as well just based on what we're seeing from the offsets and our spacing plans, but overall, we expect to operate very similar levels with a very similar cost structure..

Great, very helpful, Karen. Thanks for your time..

I'll just add again, we have been we highlighted here some of the designs with more sand per foot. So we have been testing those on our existing acreage position with the idea there is that cost for sand has decreased. We're also -- again, we've pushed wells out and have a little bit wider spacing.

So the completion designs that worked in the past, and we may have an opportunity to improve those. We're just starting when we did that analysis. It was going to take about six months or so to see the results.

So we're first starting our first wells with these higher sand concentrations and new frac techniques coming in, but some early positive indications are well, as I briefly mentioned it in my prepared comments, they look really good.

I think Karen's team has knocked it out of the park on the cost structure we cut, I mean from the time we originally drilled wells till now you've cut over $1 million of cost out there. So beat expectations there and then initial, we're only 10 days into the flow backs. But initial production is very encouraging.

So when we think about inventory and runway, we've highlighted in the past the client is something that we were excited about, more to come on that but we've got some really good results, I think, starting to come in..

Very helpful, Jason, thanks..

Thank you. Our next question comes from Noel Parks with Coker & Palmer. Your line is now open..

Good morning..

Good morning..

Continuing on the topic of the client, could you just sort of review for us because even before the acquisition you did in fourth quarter in Howard County, on your legacy acreage, you had been putting a good deal of energy on the technical side into sort of evaluating the task for the client.

Could you just kind of remind me of when that started and how that -- where that process took you to and then how that carries over to operating in Howard Country now?.

This is Karen, yes. So, yes, we've actually drilled quite a few clients as a company in our history. The really the change that took place as we started talking about that again was really the cost coming down on wells.

So the plans are deeper, more expensive, so even with really positive productivity trend of that cost difference just had us prioritizing the Wolfe Camp in front of it, as cost has come down through 2019 that really balance kind of shifts where the rate returns remain very competitive with the Wolfe Camp and Wolfe Camp wells.

So we decided we wanted to look at the newer completion design on the client with that transition because of the cost structure. The last time that we've completed any wells has been 2017, the largest completion we've put on a client 1800 pounds per foot.

So we're really having no design analysis that we've gone through more with the Wolfe County something bigger, so we've just gone 2,400 pound per foot on these two wells that Jason's talking about, overall performance looks good, it's very early but the real encouraging pieces of onside, we generally see a little bit more pressure was more required to get the sand away, but these two completed very well.

So we can continue to drive down the cost even from our assumptions with the cost reduction. The rate returns are just going to get better and better. So, we do see this or ads definitely potentials in our inventory, and our focus is high rate of return. So continue to work on and then kind of see where they fall out in our inventory..

And I think it's a good week, we saw a big jump when we went to 1,800 pounds. So we're, starting to test with these 2,400 pounds and what is that point of diminishing return because we haven't seen it yet.

We got a big jump, when we did 1,800 pounds, and just again, there's a lot of new frac technology techniques that have taken place since we last completed in the 1,800 pound jobs. So it's really early, pretty encouraging, don't want over hype it yet, but the costs are down and production looks like [indiscernible]..

Great, thanks a lot.

And could you also talk about just the status of your rig contracts at this point, I guess what on the service cost environment and of course you're moving, arranging, and planning for the whole economy program for the rest of the year?.

So on our rig contracts, I mean, we're pretty much saying, pretty flat costs for the high-performance rigs, the types of rigs that we are wanting to run, we're getting a lot of performance uplift. So that's helping with the overall cost and program, so I think I highlighted some of that but overall it seemed pretty flat service costs environment.

You know, our contracts, we tend to not sign long-term contracts on the rigs. We've got three that are under contracts right now, but only one that will be under contract passed this quarter, next quarter that we're in.

So I guess the answer to your question not really seen any major impacts on rig cost and day [indiscernible] as we're moving into Howard County..

Great, thanks a lot..

Thank you. Our next question comes from Karl Blunden with Goldman Sachs. Your line is now open..

Thanks for taking the question. Just a quick follow-up here on the M&A trajectory going forward, understand the desire to keep leverage and check.

When you think about just the amount of potential spending, is there any way to frame kind of low-end and high-end of how much cash might go out for acquisitions over the course of this year? And then, if it's something larger, something strategic comes available.

How would you fund that? Would that necessarily be done with the divestitures?.

Yes, just so we haven't -- not giving any guidance really on the side that we're looking forward. We're looking at things that are -- again, we've played these smaller things, and that 4,000, 7,000-acre range, but again, it just -- there's a lot of things coming to market.

Our real focus is again, when we do something it is going to keep the debt to EBITDA flat out. I mean, pushing it down at the end of the day, so that I will manage that.

We're also just focused on playing in our fairway and all of Karen's highlights on her operational success and success of the team is an advantage too as a matter, when I look at some of our peer presentations were $500,000 $10 million cheaper in some cases than their wealth when you take down a per well basis.

That's a $10,000 an acre advantage that we have in the basin right now. So, our plans are to use our competitive advantage on the capital side to create success in this M&A world..

That makes sense, and [indiscernible] something also that's a little premature to discuss, but in terms of using cash from the revolver to fund those acquisitions, is there a limit on how much you would go to before you felt uncomfortable from a liquidity standpoint?.

Yes, I probably wouldn't comment on that yet. I mean, it just depends on again opportunities and like that, but we've, again, we've, with all the work we've done, we've set ourselves up to be again perhaps plenty of liquidity to execute on our business.

So, we'll navigate that as these opportunities come available to you, but it's a little bit too early to be talking about that right now..

Got you. Yes, understood, thanks very much..

Thank you. Our next question comes from [indiscernible] with IV Investments. Your line is now open..

Hey, guys. Congratulations on the solid quarter.

Just a question around sort of asset sales, you guys mentioned sort of the water infrastructure, can we get -- can we put some parameters around that what sort of EBITDA or volumes and sort of what sort of profitability is generated there?.

Not, not yet. Okay. We're working through that process and one of the -- it is an asset to us; they have been selling for good rates.

We are the only customer right now on that system, and so, we got to think through, if we monetize it, it would naturally cause your lease operating expenses to go up, which is something that we're proud of, but the team is also looking to make a few modifications to the system that could increase the revenue-generating capacity from where it is today.

So, we're looking at it, evaluating it, and we check it all the time, but it is something again in our portfolio that should we find one of these acquisitions that we'd like to make that may make more sense than it does at any other incident, but it is something that's in our portfolio that we think has real value..

Thanks, appreciate that.

And then just one other question around the same line of thought process, the royalty acreage, can you just update on -- how many rough approximately royalty acreage we have in the portfolio?.

750 net royalty acres..

All right, great, thank you guys, appreciate it..

Thank you. Our next question comes from Kashy Harrison with Simmons Energy. Your line is now open..

Good morning, and thanks for taking my questions..

Good morning, Kashy..

So I think earlier in the call, you mentioned that perhaps the cost for the Cline -- the well costs for the Cline were tracking a bit lower than anticipated.

Would you have an early estimate for the Cline costs on a lateral adjusted basis available?.

We won't give it out just yet. Again, we've just really mentioned this kind of in the comments, but getting that the well has just been drilled, we got 10 days of flow back.

So we want to get tight on all our costs, but [technical difficulty] next kind of temporary release results, I think that's something that we'll be able to give you a lot more detail on but it's again very encouraging early on for us..

Got you. And then just for my follow-up question, just a quick clarification, so for 2019 spend, it looks like it came in around $482 million.

What was the split between the D&C bucket and then the other bucket that's production facilities, land, other capitalized costs, and then I think last year the average lateral length was maybe around 11,000, maybe 11,400, something like that.

Just wondering how we should think about the average lateral length in 2020?.

Hey, good morning. Let me give more color on 2019, so, you are right, $482 million for the year, the D&C part was right around $425 million with the balance kind of split between facilities, land, data, capitalized G&A et cetera..

Yes, this is Karen. I will answer on the lateral length.

So, yes, on average, as we are move into the Howard County and also the new acquisition of Western Glasscock, you know, most of those packages, the way that the DSUs are going to line up, our 10,000 foot laterals, there's some 7,500 foot laterals in there too, we'll be looking at those forward to see if there is some way to extend those, but they really fall kind of in those two categories, 10,075 on our existing acreage position, a lot more variability in each one of the DSUs is with the large blocking nature of that asset base.

So, in general, those are the types of actions we will be completing in [indiscernible] 7,500-10,000 foot laterals, so probably averaging just below the 10,000 foot with averaging those first..

Good. That's helpful. That's all for me. Thanks, guys..

Thank you. And I'm showing no further questions in the queue at this time. I'd like to turn the call back to Ron Hagood for any closing remarks..

Thank you for joining us for our discussion of our 2019 results. We appreciate your interest in Laredo, and have a great morning..

Ladies and gentlemen, thank you for your participation on today's conference. This does conclude your program and you may now disconnect..