Good day, ladies and gentlemen, and welcome to Laredo Petroleum, Inc. Third-quarter 2020 earnings conference call. My name is Frenzy, 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 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; 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 our financial and operating results for third-quarter 2020. 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 our website at www.laredopetro.com.

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

Thank you, Ron. I appreciate everybody joining us for the third-quarter 2020 earnings call. I hope everybody is staying safe as our country perseveres through the challenges posed by the pandemic. Laredo’s performance during the third quarter exemplified what our strategy is all about.

Our actions, not words, demonstrate how we manage financial risk, focus on continuous improvement to optimize existing assets, and execute on our plan of developing and expanding high-margin inventory.

Our strong hedge position continues to support cash flows, contributing to $71 million in free cash flow generation during the quarter, which we used to reduce net debt by $64 million.

We also added to our robust 2021 hedge position that prices above the current strip that supports our future development activities and enables us to operate through volatile commodity price environments.

We continue to drive operational improvements, keeping employee-related expenses in check with costs down 21% from this time a year ago, an equally impressive reduction in our lease operating expenses of 18% as we strive to maintain our operational pull position.

Despite the move from our established position to our required position in Howard County, there’s been no letup in our efficiency, and we are at company record or near record levels in both drilled and completed feet per day, as our completion teams return to action.

As these wells come online by the end of the year that will help to drive an inflection point in capital efficiency during 2021, as we focus our activities in Howard County. Additionally, our base production continues to outperform expectations, primarily driven by wet gas production from our established acreage position.

This outperformance is driving additional cash flows, especially as Waha pricing improves. We are increasing our full-year 2020 production guidance for both oil and total production with no increase in our capital budget, marking the second time this year we have increased full-year total production guidance.

In October, we announced a bolt-on acquisition of over 2,700 net acres in Howard County at extremely low prices for the undeveloped acreage. We have pulled together a very talented team that excels at being both persistent and patient to create these wins for Laredo.

In less than one year, we have added almost 16,000 acres of high-quality oil-weighted inventory that significantly amplifies the impact of our capital investments as a company.

This will remain one of our top focus areas as we look to continue extending our inventory with these types of transactions, which we have funded with our credit facility and are immediately accretive to shareholder value. Bryan will now give some more details on our financial performance..

Thank you, Jason. In the third quarter, we improved our already strong financial position, reducing net debt, debt ratios, and bolstering liquidity. During the quarter, we reduced the amount drawn on our credit facility by $40 million to $235 million, while maintaining a $40 million cash balance.

On Slide 4, you can see that since the end of the quarter, we have paid down another $15 million, while also paying $11.3 million in cash for our Howard County bolt-on transaction. By the end of the year, we expect to further reduce net debt by another $10 million or so.

Our debt ratios came down slightly during the quarter as well, and we expect our net debt to consolidated EBITDAX to remain comfortably below three times in 2021.

In late October, our bank reaffirmed our borrowing base at $725 million, reflecting the strength of our PDP assets, our future development in Howard County, as well as our hedge position in 2021. Turning to Slide 5. We continue to build our robust hedge position in 2021.

We are now about 80% hedged on our anticipated 2021 oil production at a weighted average floor price of almost $51 Brent. On the bottom chart, we demonstrate the downside protection provided in 2021 by our hedge book, enabling us to operate within cash flow in 2021 at approximately $40 WTI.

The cash flows from our hedges support our transition to Howard County in 2021. As we move to higher-margin, more capital-efficient acreage, our 2021 program will better position us for 2022. This dynamic supports our EBITDA and debt ratios in the future years and enables the company to progress toward the consistent free cash flow generation.

With that, I will turn the call over to Karen for an operational update..

Thank you, Bryan, and good morning, everyone. Throughout 2020, our operations teams have done an amazing job of maintaining efficiencies and lowering costs, even as we’ve gone through a series of both decelerations and accelerations of our program during the year.

Added on top of that, this accomplishment has been achieved as we move from our established acreage position to our acquired acreage positions in both Western Glasscock and Howard counties. On Slide 6, the top chart shows that we set another company record for feet drilled per day per rig.

And we are also very near a new record for completed feet per day per crew. On the completion side, the performance in the third quarter is even more impressive, because it is not only our first completions in Howard County, but also our first with a new frac crew, as we restarted our completions operations.

On the cost side, we remain confident that well costs will remain at or below $550 per foot. Service pricing has remained stable. Our efficiencies continue to improve. And as we get more experience in Howard County, we believe that we will be able to further reduce well cost, as we continue to optimize our completions designs.

On operating and G&A cost, we remain intensely focused on maintaining our peer-leading unit cost structure. On Slide 7, we show a demonstrated history of cost reductions and expect to keep personnel costs aligned with our current operational cadence.

As we’ve mentioned before, we expect LOE to increase as we develop Howard County, but believe our average unit LOE in 2021 will be approximately $3 per BOE, still among the lowest in the Midland Basin. Turning to Slide 8. As Jason mentioned earlier, adding high-margin inventory is a key principle of our strategy.

In the last 12 months, we have been extremely successful adding oily, high-margin inventory at accretive prices.

With five combined transactions in Western Glasscock and Howard counties, we have added almost 16,000 net acres, 1,600 BOE per day of production at the time of purchase, and 165 to 200 undeveloped locations, all at prices that few would have imagined a couple of years ago.

We just announced the most recent of these acquisitions for more than 2,700 net acres in Howard County. On Slide 9, the new acreage position is outlined in red, and is directly adjacent to our existing position. Our business development and land teams did an outstanding job of sourcing and closing this transaction at a very low price.

This is a good example of a typical bolt-on transaction that can be accomplished when you have a core operating position.

In addition to adding and extending locations and increasing working interest, we now have new, high working interest blocks that can be leveraged to facilitate more bolt-on transactions that can add more locations as drilling units are formed.

Due to the improved capital efficiency, the inventory in Western Glasscock and Howard counties, acquired since December 2019, immediately move to the front of our drilling schedule. In the second quarter of 2020, we completed a five-well package, on the Western Glasscock position, and we are currently completing a 15 well package in Howard County.

In 2021, all completions are currently planned in either Howard County or Western Glasscock, with the vast majority being in Howard. On Slide 10, the increase in capital efficiency is shown, as we move from our established acreage to the acquired acreage positions.

As shown on the chart on the right, the first year oil productivity in Howard and Western Glasscock is about 40% higher than our established acreage at the same well cost.

As Bryan mentioned earlier, this ties directly to our objective of consistently generating free cash flow in the future, as we build a production base in Howard County and support that with increased inventory from bolt-on transactions that have been financed with our credit facility.

I will now turn the call back over to Jason for some closing comments..

Thank you, Karen. These are very exciting times for Laredo. The plan that we communicated about a year ago continues to build momentum. We are focused on execution and building shareholder value. But we also believe there’s a right way to do business, and that is being focused on the communities where we operate.

That means protecting the land and environment where we drill wells. And at Laredo, it is not just platitudes and empty statements. 15% of our short-term incentive plan compensation is linked to environmental metrics, measuring spill volumes and the venting or flaring of gas.

On Slide 11, the bottom chart shows that our venting or flaring as a percentage of produced gas is about half of that of our peers. And in the third quarter, we only vented or flared 0.14% of our produced gas. Additionally, we believe in supporting the colleges that our employees care about.

In 2019 and 2020, we have facilitated $570,000 in contributions to organizations that make a direct positive impact to the communities in which we live and work. We have implemented a program that gives employees eight hours a year paid volunteer time so they can contribute their time as well as their money.

I’m extremely proud to be leading this company. We have a team that comes in every day motivated to execute our strategy to improve Laredo and build value for our shareholders and make a positive impact where they live. With that, operator, please open the line for questions..

[Operator Instructions] We have a question coming from the line of Brian Singer of Goldman Sachs. Your line is now open..

Thank you. Good morning. Natural gas has historically been a reason for, in some ways, concern on natural gas mix.

But with natural gas prices high and oil prices not, can you talk about how, if at all, that changes either where you choose to drill wells and the prioritization? Or if that has – if that could have an impact on CapEx plans into next year?.

Yeah. Thank you, Brian. Great question. Yes, we look at it all the time. So real choices at the moment are to drill in Howard County or the Western Glasscock acreage that we have picked up. Again, there’s been a significant reduction in the differentials for Waha.

So that is definitely adding some incentives to the gas properties as well as gas price increasing. So we look at it, and I wouldn’t be surprised to see us move to the Western Glasscock acreage potentially earlier. But the wells we are drilling today are in Howard County.

So there is a lag between the timing that we could move over there because we are drilling our wells and packages at Howard County, but it is a great opportunity and flexibility. And one of the things that is probably subtle on Slide 5, we show our cash flows with respect to oil price. But we ran through the kind of forecast and price is $3 gas.

And if you took a spot point, for example, $40, that line would have crossed closer to $300 million in our last iteration, and it’s up to $319 million in this iteration. So, I mean, it’s a material impact on our cash flows as we look to the future, and we are hedged fairly well next year.

But as you look even further into the future, again, it becomes a material impact to the company, especially one that has a market cap of around $100 million today. I think that is an important point for us and a differentiator for us in the basin..

Great. Thanks. And then my follow-up is with regards to the oil production trajectory.

Given the sharp ramp that is expected to get from the midpoint 22,000 barrels a day in the fourth quarter of this year to the average for next year of 28,000 barrels a day, can you just talk to – I mean, since it seems like this is largely on the Howard County well ramp up, what you see as the upside and downside risks to getting to that 27,000 to 29,000 barrel a day range next year?.

I guess for us, I think this is the new area for us. And so we are continuing to modify completions out there, as we highlighted, we have actually drilled faster and completed faster in Howard County than we have on our core position. So great work by the teams there. That creates positive momentum by being able to get wells on quicker potentially.

It also means that our costs have potential to come down. Spacing is one of the things that we look at is the – one of the things that could move things one way or the other. We’ve got our first couple of packages at kind of roughly that 16 well per package development style, but we’ve got the next set that we’re drilling is more like a 12 wells.

So we’re looking at spacing and all that, but we just won’t know until we get our wells with our completion style up and flowing. And we’ve done kind of a different wine rack style, and we see some of our peers doing so.

But those are the two big things that I think could impact it, but we feel really good about the forecast that we’ve got out there because we have pulled all the data from the surrounding wells, and there have been more co-developments, which have more history now. So feel really good about the forecast we’ve got out there.

But again, I think there’s more positive momentum rather than negative going forward..

Great. Thank you..

Your next question comes from the line of Derrick Whitfield from Stifel. Your line is now open..

Thanks, and good morning all..

Good morning, derrick.

For my first question, I’d like to drill down a bit more on Brian’s last question with a focus on completion operations for the first 15 Howard County wells, perhaps for Karen.

From an execution perspective, are there any unique risk factors in your completion operations for this set of wells versus the larger packages you’ve completed in your legacy operations in Glasscock or Reagan?.

Yes. So for us, it was a new area that we were going into. So drilling has been in the area and working for several months since the drilling rig continued. So really, we weren’t seeing anything from a subsurface standpoint.

Now that the frac crew has started up, we have about two months of operations behind us and well over half of that first package completed. We’re really not seeing anything that would really cause us to have any different forecast over how we’ve been completing packages on our legacy acreage position..

Great. And as my follow-up, perhaps for you or Jason.

In light of your success with the bolt-on announced during the quarter, could you share your views on the broader A&D environment in Midland and the potential you see for additional bolt-ons?.

Yes. A good question. I think the thing that’s important for us when we looked at when we closed our first transaction to now – again, we’ve added 16,000 acres in less than one year, and they’ve all come about via different avenues. One was a sale auction. One was a continuous drilling obligation that couldn’t be met.

One was similar to that, but just no cash flow to develop. So all the methods that we’ve used are different. And so it’s hard to point to the specific way that the new acreage will come in. But I think the team has just done a great job of, again, just being persistent, patient, working it.

And our costs have come – on the graph we’ve got there, 20 – we’re paying 10% of what we did for the first acquisition. So I think those things all will work in our favor. I also think, again, with some of the larger M&As that are out there, maybe some acreage that may have been core to one of those companies isn’t today. They’re in our backyard.

And where we can add value is, again, these move out two to three years in our rig schedule, so they’re more valuable for us. So that allows us to chip away at them. But it’s a good market. We’re seeing lots of different types of transactions come in.

Some of those were in more of that gassy footprint, which may start to look a little better than they did in the past, but we’re looking at all kinds of things. Our business development team is busier now than they’ve ever been. So we expect to continue bringing things in at a pace near like what we’ve got.

We only need 5,000 acres roughly a year to replace the inventory that we drill in any one year. And so we’re already making good progress on the next batch..

All right. Great news and update. Thanks for your time, guys..

Thank you..

Again, ladies and gentlemen. [Operator Instructions]. Your next question comes from the line of Noel Parks of Coker & Palmer. Your line is now open..

Good morning..

Good morning, Noel..

I was curious about your future hedge policy for gas.

And just to get a feel, as you look ahead, are you sort of more interested in downside protection or in sort of having some of that, but also trying to preserve your upside?.

Yes. And I’ll let Bryan fill in if I miss anything here. For us, it’s really – this is such a volatile environment right now. And we, as a company, have been fairly hedge heavy. But we really want to protect the cash flows, which is protecting that downside.

When things go bad, they can go bad really quick, what you see with all the companies that are in those distressed states today. Again, we made conscious decisions in the past to really start to lock up our budgets as we get closer to the year.

So as we look to 2021, there’s not a lot that could derail kind of the run-in the two – sorry, two drilling rigs and frac crew. So us, we may lose some upside, but losing that upside is not nearly as bad as what happens when things just start to getting that downwards spiral. So we consider it more protecting the downside.

And even – I mean, our wedge is even hedged with the hedge level that we’ve got today to protect that rig program..

Got you.

And just to check, and that’s on the gas side as well, sort of the same thinking basically?.

Gas presently is not hedged quite as heavily as oil. I think we’re roughly 62% on the gas side today for 2021, where we’re 80% on the oil side, but it’s something that we’ll consider as we go forward and do – we lock in prices as we’ve seen them higher..

Great. And you mentioned that in future developments, you might be looking at altering the spacing a bit, and you’re saying maybe the next one would be more like a 12 well spacing. And I think you said that you’re looking at doing a little bit different wine rack style array of drilling the well compared to your periods.

Could you just talk a little bit more about what’s driving your thinking on that? And what you think or hope you might find?.

Yes, and this is Karen. Yes. So as we’ve continued to look at all the offsets in Howard County, and then obviously, going into our own development, we’re really looking at spacing and completion design across our Howard County acreage.

Kind of east to west as somewhere – so we talked about the original development at 880 spacing in the Upper Wolfcamp, Middle Wolfcamp and 1,320 in the Sprayberry. So still in that range, but really thinking of all the zones somewhere between 808 and 1,320.

So really just optimization for each one of our Wolfcamp landing points and also looking at Sprayberry. So we still see those as the three primary landing points. Based on all of our experience in the legacy acreage, we still definitely plan to codevelop those three landing points to minimize infill, parent child.

So it’s just optimizing as we look at the individual DSUs as we move through the packaging and the same thing on completion design. Right now, we’re pumping kind of on the high end of the completion size of sand and water in the area.

So again, want to continue to look at with inner spacing, how to optimize those designs as we just move through the development..

Great. If I could just ask one more. You did mention that with some of the mergers that have happened recently, maybe some of the other operators who are in your backyard might have acreage that might now be non-core for them. It’s been a while since I’ve looked at a map showing who’s near you in your areas.

Of the deals we have announced recently, are there any in particular you think might have acreage that would qualify?.

Yes. I can’t speculate right now. Again, those companies are in the heat of getting their deals done. But as we talked about gas prices being higher, the Midland Basin starts to look good. Howard County, again, it’s still where we’re focused today.

But all of those companies more or less have acreage that is in the Midland Western Glasscock area and up through Howard. But when we think of acquisitions, things that we are looking for are a little blocky, greater than our 5,000 acres. They traditionally have been more than 55% on the oil front.

We may be a little more flexible with that going forward. But those are the types of things that we look for. And again, there should be plenty of opportunity in our backyard. Again, we are heavily hedged. There’s a lot of other companies that are not hedged to the degree we are that will be more financially stressed next year.

So those are things that we think create these opportunities for us. We’ve got the liquidity to go pick up acreage at all-time lows or discounts. So those things all work in our favor. And again, I don’t see any reason that we won’t have continued success doing what we’ve done over the last year..

Got you.

And just any of those that you do – might have on your radar screen, would any of those be non-op where you might – with changes going around, you might be able to pick up operatorship?.

We probably don’t focus as much on non-op but once we get the operations, I mean, we’re working deals that – we want to extend laterals from 5,000 feet to 10,000 feet, and those create opportunities for either JOAs or opportunities to purchase the acreage because we’re two companies with a 5,000 foot, I’d say – our normal section with 5,000 foot can’t drill wells.

You need those 10,000-footers. So the only reason we look at non-op is it allows us to drill 10,000-foot wells..

Great. Thanks a lot.

Thank you..

Your next question comes from the line of Richard Tullis of Capital One Securities. Your line is now open..

Thank you. Good morning, everyone.

Jason, given the slight uptick in the 4Q 2020 oil guide, and it sounds like drilling and completion in Howard County is going smoothly and maybe even a little quicker than originally planned, what do you currently see as the 4Q 2021 oil production rate? I think in the past, maybe it was kind of talked about that it could be 30,000-plus.

Correct me if I’m wrong, but a day.

What do you currently see the potential for 4Q 2021?.

Richard, it’s Ron. We haven’t given specific guidance on our 2021 exit rate, but we have – you do see with the range that we expect for the year of 27 to 29, so a midpoint of 28,000 a day.

As we progress through our program, a very consistent program within 2021 that operating that frac crew through the whole year, you should see a fairly steady completion cadence on the well packages, so that should lead to a fairly steady gains quarter over quarter. And so you kind of run your average around that 28,000 midpoint.

That will get you pretty close to what you’re talking about on your Q4 number..

Yes. The difference this year with our – I’ll just say we kind of last year saw front-loading activity, which created our contrast and production profile. But this year, with a steady crew, it’s a fairly uniform increase in production profile. Except for this first batch when you got a 15 well slug coming on, it’ll be a big jump early..

Okay. That’s helpful, Jason.

And a follow-up, I’m not trying to hold you to a specific cost here, but Karen, how much lower could average Howard County well costs possibly move to on a footage basis, say, in a $45 oil environment?.

Yes. So this kind of talk about our current performance. When we put out the $550 a foot, it was based on our current performance that we had delivered both on the legacy acreage position and then by then the Western Glasscock.

So we really – since we weren’t operating a frac crew at the time in Howard County, we didn’t want to provide a number that was based on performance that we hadn’t actually achieved. But now we have the frac crew operating. We’ve got a couple of months running.

The start-up – the team did an excellent job of starting up that crew after about a four-month shutdown. And as we showed in the presentation, we’re exceeding where we were before the shutdown of the crew. So that alone, performance-wise, should certainly result in us coming in below our 550 for these first wells.

If we can maintain the performance, which we expect to be able to do, we’ll carry that through this whole package.

So the performance alone, we’re in the $10 to $20 a foot that we’ll be able to drive down at just these performances, not taking into account any additional savings around sand or service costs or completion designs, the other things that we’re also beginning to work on now that we’re back active in Howard counting with our completions..

And they’re staying. Again, like we – we pumped 2,400 pounds per foot. There’s an offset operator that pumps 2,000. So if you decide to make that move and kind of – it’s one of those things that can happen overnight. But we’re looking at it.

My message for the team was our first batch of wells, we want to give them every shot that we can of being as successful as they can and not cut back on some of those completion knobs, or not turn those just yet until we saw the results from the first batch of wells..

Thank you, Jason and Karen. That’s all for me. Appreciate it..

[Operator Instructions]. There are no questions over the phone. I would like to turn it back to Mr. Ron Hagood for any further comments..

Thank you for joining us this morning, and we appreciate your interest in Laredo. This concludes our call. Have a great day..

Ladies and gentlemen. This concludes today’s conference call. Thank you for your participation. You may now disconnect..