Good day, ladies and gentlemen, and welcome to the Laredo Petroleum, Inc.'s Second Quarter 2020 Earnings Conference Call. My name is Chris, and I'll be your operator for today. [Operator Instructions]. As a reminder, this conference is being recorded for replay purposes. It is now my pleasure to introduce Mr.

Ron Hagood, Vice President, Investor Relations. You may proceed, 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 Bryan Lemmerman, 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'll 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.

Our 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 non-GAAP financial measures. Reconciliations to GAAP financial measures are included in yesterday's news release.

Yesterday afternoon we issued a news release and presentation detailing the financial and operating results for second quarter 2020. We will refer to the presentation by page during today's call.

Additionally, we filed an amended 10-Q for the quarter ended March 31, 2020, to correct an understatement of the noncash, full-cost ceiling impairment expense for the first quarter of 2020. The error was isolated to the first quarter of 2020 and has no impact on our financial statements prior to that period.

Please see our amended 10-Q for further information. If you do not have a copy of this news release or presentation, you may access it on our website, at www.laredopetro.com. I will now turn the call over to Jason Pigott, President and Chief Executive Officer..

Thank you for joining us this morning. It goes without saying that the second quarter was an extremely challenging environment, but Laredo performed very well. I'm pleased to report that we have transitioned well to a mostly remote workforce, and as always, we have taken the health and welfare of our employees very seriously.

While we are committed to the safety of our employees, we are highly focused on creating value for our stakeholders, as well. As you can see on Slide 3, we exceeded expectations on both general and administrative expenses and lease operating expenses.

Our outperformance on production volumes was directly associated with our low-cost structure and transportation arrangements which eliminated the need to shut in production of any material significance. Our hedges supported cash flows and we continue to drive down costs.

In fact, versus the first quarter of 2020, we increased adjusted EBITDA by 14%, despite an average sales price decrease of 36%. Moving to Slide 4, our bedrock principles of how we manage the company have not changed. Managing financial risk.

We have clearly demonstrated that this a priority when we went to the market early this year to refinance our debt, protecting our 2020 cash flows through hedges that we put into place last year and through new hedges that we layered on this year. Optimizing the assets.

The team has made significant strides this year, as we reduced our operating costs by 16% from the same quarter in 2019. Our drilling costs are anticipated to be some of the best amongst our peers as we drive down well costs to the $550 per-foot range this year.

And finally, we made some very difficult decisions to reduce our overhead through staffing and compensation structure adjustments to maintain our peer-leading G&A. Acquiring additional high-margin, high-return locations and increasing the scale of the company are key to delivering results in the future and are a top priority for Laredo.

We believe that there are opportunities for us to expand, but rest assured we will be deliberate about how we evaluate and finance these opportunities. We take a conservative view of spacing and productivity and seek to reduce financial leverage ratios with the transactions we pursue and improve our debt-to-equity ratio.

On Slide 5, our Howard County acquisition demonstrates our strategy and how it drives future results. Expected returns on the acquired locations outpace those of our core existing acreage, and those locations are at the front of our development schedule.

We've added our internal budget curves to the plots we have shown in the past, which were pulled from a wider range of data. These curves represent the economics and production profile used to influence our decision to return to activity in Howard County.

We have recently started the bid process for services ahead of our ramp-up in activity, and they support the $5.5 million well cost used in this analysis. Our peer-leading D&C costs result in a lower breakeven cost and are the primary catalyst for the acceleration of activity in Howard County.

Moving to Slide 6, you can see that we were able to rapidly reduce activity levels in response to lower prices and their impact on returns. While this flexibility is necessary to preserve value when commodity prices drop rapidly, operating in our current cadence is suboptimal in the long term.

Our goal is to maintain a normalized operational cadence that drives efficiency and supports stable cash flows and EBITDA. Driven by the return profile of Howard County development, we are resuming completion activities by adding a crew in Howard County.

Further, current plans are to maintain this crew throughout 2021 and also to run two drilling rigs which are needed to balance the spuds and completions. In addition to the obvious operational benefits of running a steady development program, the value proposition for the company is discernible.

Slide 7 demonstrates the stabilization of oil production under our current plan versus a substantial degradation under the previous plan. Cash flows and EBITDA are stabilized even at lower hedged oil prices, and we expect to accomplish this while operating within cash flow for full year 2020 and 2021.

Additionally, we have underpinned the returns from this activity by adding commensurate oil hedges in 2021 and 2022. Turning to Slide 8, we show the progress we have made in the previous 9 months in adding high-margin inventory.

Combined, this represents approximately 3 years of development at a normalized cadence running 2 rigs and 1 completions crew.

While this is a tremendous progress, we still see more opportunity to acquire inventory that can benefit from our operational expertise and low-cost structure and move us toward our goal of increased scale and long-term free cash flow generation. Before I turn the call over to Karen, I would like to welcome our new CFO, Bryan Lemmerman, to the team.

Bryan brings a wealth of transactional expertise to Laredo, both financing and integration. His background will be invaluable as we look to strengthen our balance sheet and evaluate acquisition opportunities, pursue deleveraging opportunities and improve our debt-to-equity ratio. With that, I will now turn the call over to Karen..

Thank you, Jason. Slide 9 is an update of a slide we've used to consistently demonstrate the success of our optimized spacing and completion strategy on our established acreage position. As Jason just mentioned, we've made acquisitions of oilier, higher-margin inventory in the past year in western Glasscock and Howard counties.

The new data that I want to highlight on this slide are the early production results for the 5-well Cook package we completed during the second quarter on our western Glasscock acreage, which was acquired in December 2019.

Although the oil production results are already exceeding our established acreage type curve, early production on this package was curtailed, as existing infrastructure was unable to accommodate initial volumes. ESPs installed on 3 of the 5 wells were not able to run at optimal capacity until additional flow lines were installed.

The performance of the artificial lift has now been optimized on all 5 wells, and the wells are performing at or above expectations. If the current production trend continues, we expect results for the 5-well Cook package to continue to improve versus our established acreage type curve and our initial expectations for the package.

Turning to Slide 10, this is a slide we are particularly proud of for several reasons. The top chart shows the continued progress we've made in both drilling and completions performance.

Each time we think performance improvements might be plateauing, our operations teams have continued to implement new areas of improved efficiencies, and we've continued to see improvements.

Especially impressive is our drilling team's ability to retain these efficiencies over the last few quarters as our drilling operations have transitioned fully to Howard County. Until the last quarter, we have seen the same progress on the completions front.

The second quarter did see a dip in completions performance, which is not unusual when suspending operations, as we did in the second quarter. As we resume completions operations later this year, we expect to regain these efficiencies when we begin our first completions in Howard County.

On the bottom chart, you see these efficiencies translating to our D&C costs that are among the lowest in the basin. As I just discussed related to our recent well performance, we completed the 5-well Cook package during the second quarter on our newly acquired western Glasscock acreage before we suspended completions operations.

We were able to deliver these wells in early second quarter at an average well cost of $620 per foot. This was before we saw any significant reduction in service cost due to price volatility related to COVID-19. We've continued to work with all of our service providers and are budgeting well cost of approximately $550 per foot.

As we've continued running drilling rigs in Howard County throughout the second quarter, we are delivering drilling costs below the levels implied by a total well cost of $550 per foot. Turning to Slide 11, we highlight another operational area that we are extremely proud of.

Our historical investment in infrastructure make our operations safer and reduce environmental releases. Since beginning production in the Midland Basin, we have focused on limiting flaring [indiscernible] of our produced natural gas. We believe it is the right thing to do from both an environmental and economic standpoint.

Over the last 2.5 years, we've only released 1.6% of our gas production and, with one exception, have held that number under 2% on a quarterly basis. To demonstrate our commitment to even further reducing flaring, our board of directors for the first time has tied a portion of our bonus payout to improvements in this metric.

I'm proud to say we continue to see improvement in this area, and in May, June and July we were able to reduce our percentage of flared and vented gas to well below 1%. The first half of 2020 has been an extremely challenging environment for our operations team.

They have successfully managed through the difficulties of operating with the added risk associated with COVID-19, and they have continued to deliver improved performance and reduced costs even with significant changes to our activity levels.

During this time of change, we worked very hard to maintain our focus on operating safely, improving our environmental metrics and continuing to deliver operational excellence in all areas of our business.

I'm very proud of our team for the way that we've managed through the challenges in the first half of the year, and I'm confident the team will continue to deliver peer-leading results as we resume completions activities in Howard County this quarter. I will now turn the call over to Bryan for a financial update..

Good morning. I want to start by saying I feel fortunate to be given the opportunity to assist the Laredo team in achieving the goals and plans Jason has outlined. I look forward to supporting Laredo's plan of improving our balance sheet and financial strength.

As you saw in our earnings release yesterday as well as in the 10-Q/A we filed for the first quarter, we had a material weakness in our controls. This weakness centered around the costs included in the reserve report for Q1.

This material weakness led to an error in the calculation of the ceiling test impairment, understating the impairment by approximately $160 million.

This charge is noncash and has no impact on our financial ratio covenants or the business operations, as we do not use the calculation of SEC reserves and the related depletion or impairment in running our business. The impairment charge has been corrected in the 10-Q/A, and we expect to file the second quarter 10-Q on a normal timeline.

We have also received a waiver from our bank group for the technical default arising from this restatement. Now I will touch on a few items specific to the second quarter and then dive into some big-picture items around activity levels in '20 and '21 as well as our balance sheet.

As Jason mentioned in his remarks, the company's overall operational and financial performance during the quarter was outstanding. We continue our long-term trend of driving both unit LOE and G&A expenses below that of our peers, as illustrated on Slides 12 and 13.

On the LOE side of the equation, Laredo continues to be a low-cost leader, and we continue to drive cost out of the system, as noted by the 24% decrease year-over-year and 14% decrease quarter-over-quarter. As we begin to complete and turn in lined wells in Howard County, we would expect LOE for those wells to be approximately $4 per BOE.

These wells are substantially oilier than those of our established acreage base, and we will utilize ESPs for the artificial lift versus the gas lifts we currently use on our established acreage.

Our existing production will continue to benefit from our infrastructure assets, and on a blended basis we expect unit LOE in '21 to remain below $3 per BOE average for the year. With respect to G&A, the company continues to monitor and manage our costs for the environment we are in.

As discussed previously, management and the board of directors have taken salary reductions, and we had a reduction in force in June, resulting in a charge of $4.2 million. The annual savings going forward are expected to reduce personnel expenses for the full year 2020 by approximately 10% versus full year 2019.

Capital costs incurred in the second quarter were $78 million, versus our expected $65 million. For the first half of the year and for the full year, we are on target for our CapEx expectations. The additional capital spend in Q2 related to the estimates and timing of activity and invoicing during a period of rapid decreasing activity.

As Jason and Karen discussed, we expect to put completion crews to work in Howard County later this year. With activity stabilized and slowly growing in the back half of the year, we are comfortable with our second half of the year capital guidance.

We will be thoughtful in our timing of when we put the completion crews back to work, balancing the impacts to cash flow. We would like to point out the half-cycle returns on these wells are extremely competitive at strip prices, and even more so, as the wells we are completing our DUCS.

Spending the dollars in Q3 will also help us maintain a reasonable production level going into '21, stabilizing our balance sheet and operations considerably over the plan we were executing in the low-price environment a couple of months ago.

Turning to Slide 14, we give some more data on how we intend to balance capital expenditures and cash flows in the updated '21 plan. During the second quarter, we added an additional 4,800 barrels of oil per day of oil hedges in '21, taking us to approximately 70% of the anticipated oil production hedged at a Brent floor of $51.

As you can see on the bottom chart, our hedge position substantially mitigates the impact of an oil price decrease versus an unhedged position. Additionally, the combination of puts and unhedged oil exposes 65% of expected production to increasing prices. We pursue a consistent methodical hedging strategy.

We enter into hedges to support our cash flows and lock in returns as much as possible. This process has served the company well, generating cumulative settlements of more than $700 million since the beginning of 2014, including $87 million in the second quarter. Turning to Slide 15, we are well positioned for the next few years.

We have no term debt maturities until '25, substantial liquidity provided by our revolver and we are in a great position on our debt ratios. Additionally, we expect to reduce net borrowings with free cash flow in the second half of the year.

On the other hand, it is quite obvious that many companies in our space have too little equity relative to debt, including Laredo.

We are committed to bringing equity to the balance sheet in constructive and value-added ways to our stakeholders, whether that be through using equity structures to acquire bolt-on acreage or working with all of our stakeholders and others to consolidate larger positions or entities.

We plan to make incremental steps every chance we can, wherever it makes sense, while looking for a larger opportunity to benefit our stakeholders by substantially increasing scale. As I said at the onset of my comments, I am honored to be here working with so many great Laredo employees.

I believe thoroughly that as an industry and a company we must continue to evolve, and Jason's commitment to continual improvement was a large driver in my decision to come here. Laredo employees are committed to find ways we can continue to improve processes and use technology to become better and more efficient.

With that, Operator, please open the line for questions..

[Operator Instructions]. Our first question comes from the line of Derrick Whitfield, with Stifel..

Perhaps for Jason, with the understanding that you're providing more visibility than most with your current plan, on Page 7, would it be fair to say the current capital plan steadies the ship within cash flow for the period shown and generates meaningful absolute growth in free cash flow in 2022 and, with the hedging you guys have effectively put in place, it's simply an implied bet on your ability to execute?.

Great question, and I agree with everything you said there. Our goal has been to be free cash flow neutral. We've been that way since last year, and that's the plan that we've laid out for you today. And as you can see in Slide 7, especially on the right there, again we are returning our production values to what we had in 2019.

And if you look at our covenant ratios, they materially improve as part of the process, as well. So we feel confident about it. And we get a lot of questions. Inventory is one of the things that stands out. But as I sit here, I look back a year ago. All of the wells that we are drilling today weren't in our portfolio a year ago.

And so I feel really confident that in this lower-price environment, where there's more kind of stress on some of our peers or PE companies, we'll have a great opportunity to add additional acreage. There's continuous drilling obligations that are out there. There's acreage that's expiring. So we're really focused on kind of two different strategies.

One is just bolting on to the Howard County. There's lots of open acreage around us there. We've been very aggressive in reaching out to other operators for opportunities there. And then on a macro level, as well. The companies that have low cost structures are the ones that win in this environment.

And as you've seen from our results this quarter, we reduced LOE, we reduced G&A, we reduced our D&C. So we think in this environment, again, Laredo is well positioned to not only add those bolt-on opportunities, but have the capability to do something on a larger scale that could really, again, double the size of the company overnight.

So those are the things that we're focused on. I have a lot of confidence in our team's ability to execute on the plan and continue to load the rig schedule with additional opportunities..

Great. And then as my follow-up, I'd like to shift over to your recent well cost savings projections.

Perhaps for Karen, how should we think about the sustainability of your year-to-date well cost improvements on Page 10? And specifically, what I'm targeting is, how much of that improvement from the $660 level is structural versus market?.

Thank you for the question. As we talked about, we're currently budgeting with a $550 per-foot cost, going forward. So through the first quarter we delivered right at, the Cook wells we mentioned specifically, about $620 per foot. As we entered 2020, we were budgeting at about $680 a foot.

So we've continued to see, as we continued to have drilling and completions operations which was through early May, to see a reduction, primarily due to performance improvements and some cost structures. We saw diesel and things coming down during that time. From that point, from the $620 per foot, forward to the $550, that's all service cost.

So what we've assumed is that we will be running at the same performance levels that we were able to deliver in the first half and, working with our current service providers, have incorporated there the actual service costs that we're currently operating at.

Having said that, drilling has continued to operate and has fully transitioned to Howard County, as we mentioned. They've continued to see performance improvements and are working a number of areas around additional cost savings and are delivering below the implied $550 a foot.

So we could continue to see some performance improvements also impacting that number..

And our next question comes from the line of Brian Singer, with Goldman Sachs..

As you consider the right level of activity and capital spending, how do you contemplate maintenance mode with free cash flow, versus the more accelerated pace that you're going at here? Or do you guys get to more of the same levels of free cash flow regardless? I'm just thinking about the goal of delevering and whether that gets accomplished more by net debt paydown versus by EBITDA growth..

Sure. This is Bryan. I think the plan that we've outlined here targets free cash flow neutrality in some of the same ways the plan would have in the lower-price environment. I think the main difference is if you look forward, in a situation where we were doing the earlier plan, your debt metrics and your balance sheet I think struggle more.

Sure, you can generate some cash flow and you can pay down some debt, but your debt-to-EBITDA ratios will be much weaker than in the plan we have here. And in my opinion, the company is in a lot stronger position, with higher production, higher EBITDA, even with a slightly higher amount of debt..

Great. And then you mentioned just here earlier that you want to try to be nimble here to pursue acquisition opportunities that may come about.

What do you see based on your own leverage goals as the importance of targeting leverage reduction? And then what do you see as the scope for capital that could be deployed to acquisitions?.

This is Jason. I'll take a stab at it. Again, we're ultimately, as we've highlighted, trying to delever the company. Again, we started last year before we made the acquisitions in the debt-to-EBITDA range of 1.7 to 1.8. As a company, again, ultimately we want to drive down to that 1 range, but you've got to pass through 2.5 and 2 to get there.

So I think one of the things that we are looking at as we think through the world of M&A, again, we will try to use equity as part of those transactions, which will allow us to delever as a result of it. So we're actively thinking through those. There's assets that are coming to market via bankruptcies. Again, there are bolt-on opportunities.

So it's hard to say exactly what is going to come to us, but we've been very successful with our bolt-on strategy and working things like that, as well. So again, it's not quite clear exactly which one of these levers we're pulling is going to be successful first, but we're kind of pursuing them all simultaneously right now.

But again, at the end of the day, I'd say I think the way we're trying to run the business it's clear, and we're going to continue to grow. The plan we've got here, I think one of the things we probably need to highlight a little or stress a little bit more is we're going to run the 1 completion crew.

That's where we see the most operational synergies. As prices rise or if there's a benefit there, we're not planning to increase activity. We use that extra cash flow to pay down debt, as well.

So again those are things that as the world improves and oil drops as a result of some of the cutbacks, oil protection drops, again we're going to take advantage of that. We're not going to ramp up to do it. We create a healthy growth rate with just the 1 completion crew. So we're kind of working all these angles together.

Again as I mentioned, we didn't have any of the inventory we're looking at today 8 months ago. So we've been executing on the plan. I think it slowed down a little bit as oil prices dropped so dramatically. But now that things have stabilized, I think you can start to value properties with the current strip price.

And for us, I think one of our other advantages are we don't have -- because we don't have the length of inventory, the things that we acquire come to the front of the rig schedule.

So we can create value from some of these opportunities out there that some of our peers can't right now, because they've got inventory and there's not as much competition because some of them are more distressed than us, as well. So I think we are well positioned.

It's hard to say exactly what that next deal is going to look like, but I think they're out there, and Laredo has set itself up as the low-cost operator to take advantage of..

Great. Great.

If I could just add one quick accounting question, what is the sufficient period of time auditors look forward to consider the material weakness that was highlighted here remediated?.

You bet. I don't know that there's a definite answer. I look at it as a quarter or two. That's what I'll be using..

And our next question comes from the line of Richard Tullis, with Capital One..

Jason or Bryan, as we piece together the increases in '20 and '21 CapEx guidance, I know that you provided the '21 oil production guidance.

Could you give us a view, I know it's a long way off, but your possible 2021 oil production exit rate or maybe 4Q21 average?.

So Richard, as you can see, the average for the year is going to be higher. And I think the way you need to think of it is what we guided for our 4Q20 exit rate, you can see where that is. And from there, pretty continual march up. And so obviously, with the average where it is, 4Q of '20 is going to be considerably higher..

4Q21, Ron?.

I'm sorry. Yes, 4Q21..

Okay. Okay. That's helpful.

And Jason, going back to the M&A comments a little earlier, could you kind of give us the lay of the landscape of what areas you're open to looking for acquisitions? Is it beyond the Midland Basin?.

Again, I think where we are efficient today is in our backyard, in Midland Basin. You only need to go about a couple of miles west from where we are today to get oily. When we're looking at things, what we've bought before has 5,000 acres and greater and kind of blocky. We're looking to pivot our oil to a 55% yield, or better.

And so those are the targets that we look at, is blocky and oily. So you can go a couple of miles west, which you saw in the Cook acquisition in the Howard County. We're really focused right now on just trying to expand from our position in Howard County, where we've got water infrastructure and things like those in place.

But I think a lot of the things that we do just really about the way we run our business are applicable to other basins. So if the opportunity came up in Delaware Basin, again that was blocky and sizable enough to apply the synergies we create, that's good. Again, I'm a fan of the Eagle Ford.

Things don't really come to market as much there, but I like those kind of plays. Again, it's aligned with oilier, and it fits kind of our business plan, going forward. So those are probably the 3, 2 extra places I would look outside of Midland right now, but we're open to opportunities.

When we think about the world and M&A, we have cash flow and there's inventory out there. And when we can take someone's inventory that maybe they're lacking the cash flow and we put these 2 things together, that's where you get the 1+1=3 type scenario, and those are the things that we're looking for..

And our last question comes from the line of Noel Parks, with Coker & Palmer..

I think it's easy, especially for those of us who are industry observers, to kind of think of the Permian as sort of monolithic. We think, okay, it's oily here, it's gassier there, that's less desirable.

But I was wondering, are there areas that have, like, a product mix, oil, gas, NGLs, where you feel they're persistently undervalued, like a discount that even just isn't rational? And I wonder if any of those are sort of in the mix of things you're looking at, though I understand the advantages for being oilier.

And also wondering, how sustainable a gas rally would you have to see before the economics in decline would start to creep back into competition with your newer acquisitions?.

I'll start with your last question first. And we had it in our last investor deck. We had a plot out there that showed decline versus different gas prices. So the areas that we are developing in Howard County are oilier. And so they don't benefit from the gas price increases. But that's, again, we're more capital efficient there.

Our Cline and our core position we have today does definitely benefit from higher gas prices. I don't have that slide in front of me. But as gas prices rose, it started to compete with the Howard County [indiscernible]. But it takes $3, $3.50 gas to really push that above our Howard County. But we don't talk about the Cline as much in this presentation.

Again, it's focused on Howard County. But that is kind of the next layer of wells that we would go drill. So if gas prices improve over time, those economics in those wells are in our back pocket.

And it's hard to say, again, if you think in macro Permian, you see there's definitely a differentiation in productivity from -- there's oily parts of it, again like you have in a Howard County. I can't say that any of them are more or less discounted.

What we see when we think through the different companies that we evaluate and the different properties are the NPV degradation occurs when you can't get to a well within, let's say, a 5-year period. So there's lots of value there that's being destroyed when you're not able to get to it.

And again, that's where we think we've got an opportunity, is we're able to bring value forward for again those properties or those companies, and that's the way we're thinking about the world right now..

Got it. And I was thinking in the hedge book it looked like some of what was added for 2021 were some new floors. And just sort of as a reality check, what sort of premiums do you have to pay to sort of get puts in this environment? I'm just, I haven't paid a lot of attention to that market lately..

I'd say those are all swaps..

The incremental adds from the last time that we gave our hedge position were all swaps, in 2021 and 2022..

Earlier this quarter, again, and it's one of those things that's a little bit lost because we did it, is we bought puts for next year with some of our cash flow that we anticipate for this year. That occurred in the second quarter.

So if you hadn't done that, our second quarter would have been free cash flow positive, I think to the tune of about $27 million. And what we did is we made the decision to add the activity to Howard County. We wanted to secure our cash flow and to fund the capital required to bring that activity forward and lock it in.

And I think the team has done a really good job. We haven't talked about it too much or had any questions on it. But in our deck, on Slide 14, that's just the impact of our hedge strategy. And you can see if coronavirus or COVID that lingers around and prices start to fall again, what we've been able to do is just protect the downside.

So we've got the puts that are going to allow us to benefit if oil prices rally. But we've really started to, again and this is part of our strategy, is protect our stakeholders when you get into an environment where prices fall.

So we've added some swaps this quarter to protect this incremental activity, and we'll continually look at adding another layer. We're about 70%, over 70% hedged right now, but may look to add more as we solidify kind of our plans for next year..

Great. And just one last one for me. And I'm sorry if you touched on this already. Your goal per foot of the cost of the new pads you're going to be doing, because I think it's going to get into more scrutiny. Your cost, those are drilling and completion costs per lateral foot.

And then are those also burdened with any facilities or infrastructure costs, as well?.

This is Karen. So everything that is facilities related that's associated with an individual wellbore is included in that AFE. So for example, roughly for a $5.5 million, 10,000-foot lateral, we've got about $500,000 of facilities costs associated with that AFE..

Great. Because there are certainly other companies that are struggling to even get into the $700s on a per-foot basis, and I just wanted to double check that we're all talking apples-to-apples with those..

Thank you. And this does conclude today's question-and-answer session. I would now like to turn the call back to Ron Hagood for closing remarks..

Thank you for joining us today. We appreciate your interest in Laredo. This concludes our call. And have a great morning..

Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect..