Q2 2021 Laredo Petroleum Inc Earnings Call

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Good day, ladies and gentlemen, and welcome to the Laredo Petroleum, Inc. Second quarter 2021 earnings Conference call. My name is Kevin and I'll be your operator for today at this time all participants are in a listen only mode. Following.

We will conduct 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.

Joining me today are adjacent market, President and Chief Executive Officer, Karen Chandler Senior Vice President and Chief Operations Officer, and Brian Lemmerman, Senior Vice President and Chief Financial Officer, as well as additional members of our management team.

During today's call, we'll be making forward looking statements. These statements, including those describing our beliefs goals expectations forecast 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 will be making reference to non-GAAP financial measures.

During the fourth quarter of 2020, and this transition is expected to position us for substantial free cash flow generation and 2022 reflected in the capital efficiency of our development program.

We increased our heads position to protect our anticipated free cash flow generation, which should result, and reducing our debt to EBITDA substantially throughout 2022.

We also work with our financial partners to extend the credit facility and pay down the revolver, providing us a path for future inventory growth, which Brian and we'll discuss and a moment.

We continue to improve operationally, even with the complete transition of our development programs and Howard County.

We reduced D C and a cost of the face of increased cost pressures.

Where our base and leader and establishing a sand mine on our company owned surface, which also mitigated substantial portion of the cost pressure and we estimated saves us approximately $200000 per well and the current environment.

And mine has additional ESG benefits of television trucks off the road because it is a wet sand mine eliminates the combustion related emissions associated withdrawing the sand that occurs with other minds.

Sure and will also highlight how are wider space spells and northern Howard County Wells are outperforming our initial package and central Howard County.

We believe our strategy is working we will continue to follow these core principles that result, and our ability to generate substantial free cash flow and build long term value for our investors and while I will turn it over to Karen for and operational update.

Thank you, Jason and good morning, everyone.

And as Jason gas Wilson, and we had now fully transition our development activities to our acquired acreage position and Howard County, and intellectual last call.

With the majority of our activity and how Kennedy.

During the second call and then we completed 16 wells, all and Halleck channel.

13, and these wells, where the day this well package.

This is our third well package and what we're now calling central Howard.

And start well package is different from our first 2 well packages and that we are aligning space on the wells and the Wolf campaign formation.

And the first 2 well packages and central Highlands, we targeted spacing equivalent to 12 wells and the Wolfcamp Bay and oil wells and the lower sprayberry.

And the day this package, we widen the spacing to 10 wells and the Wolfcamp day.

And 4 walls and the lowest pay day.

And all subsequent well packages and central Howard.

Plan to develop was 8 wells and the Wolfcamp Bay and staying with the 4 wells and the lower stray day.

These well accounts have been included in our gross location counts since first quarter and.

And we do not expect any changes to the gross location and shown on slide 5.

On slide 5 you will also see the Davis cumulative production relative to the first 2 more tightly spaced packages, which are the Gilbert pass out and the Trentino whitmire packages.

While still early and its flow back to Davis package is responding exactly how we would expect with the wider spacing and is outperforming hydrospace packages by an average of 19%.

I'd also like to point out the performance of the Vince average well package on the side.

The Vince ever package was recently completed by the Walo and came with the acquisition on July 1st.

And the symbolic area, which we are now calling north Howard.

Our initial development plan will still be based on 12 wells per section.

But will differ somewhat from the central Howard 12, well development plan.

Reflecting the strength of the lower spray day, as you move north and West and Howard County.

Again, we plan to stay with the wider spacing at a total of 12 wells for D issues.

That was 6 wells and the lowest primary and 612th and the Wolfcamp, a and the north Howard acreage position.

And then service package was actually drilled on a slightly tighter spacing and the 12 wells per day issue.

And due to this tighter spacing, we expected to outperformance relative to the other Howard county packages to narrow over time.

But we are still very excited about the initial performance of this well package.

And when it is potentially telling us about the quality of the north Howard leasehold.

We are currently working to fully integrate the acquired <unk> into our development places.

As we previously announced we will be temporarily increasing both the drilling and completions activities.

And third and fourth quarters and this year.

To finish all of the work in progress that was begun by <unk> prior to close and the acquisition on July 1st.

And the charge on the bottom of slides 6 you can see the increase and completed wells being put on flow back and the second half of 2021 with this increase and activity.

The additional wells a key to driving the oil production growth and the third and fourth quarters and this year and building momentum and to 2022, and you can see and the top shower and slides 6.

And 2022, we expect to return to a more moderate activity pace operating with 2 rigs and 1 completions curve.

We expect to be able to hold the oil production relatively flat and 2022, and Neil and even with the more moderate drilling and completions activity levels.

And the first half of 2021, and we continued to drive down drilling and completion cost and delivered our wells and an average cost of $525 per foot.

As shown on slide 9.

Our drilling and completions operations continues they are strong trend of getting more and more efficient through the second quarter.

These efficiencies coupled with savings from her and oil radio Oh San line.

US fully offset cost pressures that we are beginning to see related to pressure pumping diesel and still price.

At current mass market prices, we estimate that our sand mine is now saving us more than $200000 per oil.

These efficiencies also allowed us to deliver 3 additional wells and and the second quarter for a total of 16 wells.

Lastly, turning to slide 11, and I'd like to point out are flaring and venting statistics for the first half of 2021.

On the chart on the right you will see the strong trend of reduce flaring and venting compared to our 2019 and 2020 numbers.

Our first half 2021 and levels are testament to the work of our operations and midstream teams.

To focus on reducing emissions, even as we transition and build out our operations and Howard County.

I will now turn it over the call to Brian for our financial update.

Thank you Karen.

As Karen mentioned, we are temporarily increasing activity to finish the activity begun by <unk>.

Most of this capital activity is reflected in Q3, and the resulting flow back towards the end of Q3 and and the queue for.

Which drives a steep oil production increases we expect and Q4.

The guidance trajectory and arrange as we have outlined for Q3 and Q4 reflect our best estimate of when these packages will see flow back.

Flow back dates being 10 days faster or 10 day slower and have a substantial impact on the quarter with no real impact to value.

Moving and the 2022 at our moderated activity livable levels, we expect to hold oil production relatively flat at a normalised rate of 36002.38000 barrels per day.

Again quarter on quarter will have variations as we have demonstrated through the capital spend graph on slide 6.

Now turn into the balance sheet.

We continue to make progress deleveraging and improving our capital structure with the <unk> and <unk> Street transactions, concluding our previously announced $75 million ATM program, and the $400 million bond offering and credit facility extension.

The acquisition and divestiture continued to move us and the right direction on the inventory front and we will continue to look for opportunities to extend our inventory runway through additional acquisitions of high quality oily acreage.

The $400 million bond transaction and related credit facility extension provide us with much greater liquidity preserving the balance sheet around future opportunities.

As for the credit facility extension, we were very pleased with the reception, we received and the market as we welcome for New Banks tour facility and had many of our existing banks increase their exposure, replacing the exposure from banks that needed to exit the facility due to mandates around reducing energy exposure.

We feel extremely well prepared going forward with our supportive Bank group.

As part of this credit facility extension and bond offering we maintain the commitment level of $725 million and our credit rating and saw a 1 notch improvement from Moody's.

Our goal moving forward is to continue to pay down debt and strengthen our balance sheet with a recent acquisition and our hedging program. We have enhanced the free cash flow generation profile of the company for the next 18 months.

Currently where approximately 80% hedged per oil for the remainder of 2021 and 70% for 22.

Where approximately 93% hedged on natural gas and 21, and 51% and 22.

And for Ngls, where approximately 72% hedged for the remainder of 21 and approximately 49% hedged for 2022.

Ultimately our goal is to enhance free cash flow generation profile of the company to do this we intend to maintain our capital spending discipline, while focusing on acquiring additional high margin oil and waited properties, where we can apply are efficient low cost of operational capabilities.

With that I turn the call over to Jason per closing remarks.

Our activities and the third quarter were pivotal to our transformation, we have a lot of momentum going into the second half of the year and I'm excited to continue working with our calendar team to maintain the high rate of change that we've experienced over the last couple of years and.

We will now open the line for questions.

Well, ladies and gentlemen, if you have a question or a communist this car and police Prussian starved and <unk> on your Touchtone telephone.

Your question has been answered you wish to move yourself from the queue. Please press the pound G.

Our first question comes from Bill would feel with before.

Thanks, and good morning, and all.

Good morning, good morning.

For my first question I would like to focus on your production trajectory referencing slide 6.

What is the greatest risk factor and your view other than timing and achieving the fourth quarter exit right given the rain from your learning curve and Howard County over the last several quarters.

From and execution perspective, I imagine there's limited science, so to speak and the 17, while you bring it on and central Howard during Q3.

Yeah. That's a great question, Derek I think we and we look to add the frat grew just as we think through some of these wells again, bringing on.

Well, well pads and some of these wells hit peaks of over.

And barrels a day each and so when a Frank crew takes a week longer to get here more than we planned it could just create.

Uncertainty and the volume for the quarter, but as Brian mentioned and those prepared comments these aren't things and necessarily impact the value of it but there are these are new wells new packages.

Getting this the second crack crew spun up it on our timing those are all things that kind of go into some of that but.

As you see on slide 5 and the deck that we've got out there the new packages have been outperforming our initial package. We're really excited about on these are the first ones to.

To come on at the less than spacing, we needed to as a company to test the tighter spacing to make sure that we weren't leaving any wells behind and.

But we had already kind of preplanned to test wells on and wider space and as well.

Which is great because every subsequent Julie package that we brought online is outperforming the initial package for those and and didn't see our update earlier. We also added that Vince every pad, which is on the <unk> acreage.

And Northern Howard County, those wells are do and phenomenal and as you look kind of pair that with <unk>.

5.6 you will see that we are moving our activity and finished work. They started but then we're moving our rigs over to that area and that area, where we dominate most of the turn and lines for 2022.

Great great detail and then.

Perhaps a slight build on that question perhaps for caring.

Could you speak to the differences.

Material between you and development approach and that of Sabawi and how you plan to bridge the 2 of them and the next few quarters.

And sure I'd be happy to talk a little bit more of that how we are going in and what we're calling now and the north Howard area and.

And so his case and Nathan we're showing and well results.

The most recent of our Davis package.

Which is based on the 12 well per section and both the spray Barry and the Wolfcamp a formation as.

As we start looking at the development plan and Howard area looking at the well results and several for comparison.

Again that as we move forward will be based on the 12 wells.

Her idea issue, so really overall and same overall development plan from a total well count.

And you move to the north and northwest into the new acreage position and we really see much stronger spray very well results and.

And as we move in that direction.

Really want to focus the transitions and development plan with those well results.

And right now and looking at within the 12, well, having a 612 sprayberry and and 6 well Wolfcamp a development.

So we will continue to kind of work on net development and plan that translation overall, we do think that the wider spacing at the 12 oil per D. Issue is is really the right as planned for the development plan right now and continuing to kind of watch and see hesitant separate which was based on the the additional spray very well.

And the day this county kind of produce produce out.

Past, where we are right now and the early time production.

Very helpful. Thanks for your time.

Thank you day.

Our next question comes from George Stewart with Goldman Tree.

Hey guidance.

Eric feed with.

Jordan.

Question for you on the on the on the hedging side.

Their day, repetitive, Nevada, and $11 million charge for net premiums paid for commodity derivatives and mature during the quarter, which looks like it from non cash charge.

Premium federal period prior to this quarter could you just talk and will give a little bit more color on on what that is and it.

You would like a non cash expense and.

2 security power wires.

Before processing terms, and whether or not to add that back for on your adjusted EBITDA and number.

You are correct that is a non cash charge. The those premiums were paid in 2020 and so the the but they are being allocated over 2021 as those hedges mature.

Actually we had sold and they were.

They were with puts and if we had sold those puts earlier and this year, but the allocation of those premiums still occurs throughout the year and so it's it's a and.

A an adjustment to adjusted EBITDA before.

Out this year, but is not a cash charge.

Okay, and what's your expectation and for that and future quarters.

So you will have that in <unk> and <unk> of 21, but then and as you move into twenty-two there it will it will cease.

Okay, great. Thank you.

Moving on.

Why and item.

I guess, we don't understand as well and the level of more color on the purchase oil.

And it looks like you're expecting the loss from that activity to expand a little bit and Q3 based on the guidance can you elaborate a little bit on what that represents and wired turning to where it's a trend and and maybe where we can expect beyond Q3.

Yes. This has been inclined the purchase oil losses really to calculation.

Derived by the amount of crude oil we have on transport to the Gulf Coast.

And excess of our net production that we transported to the Gulf coast not all of our production we transports the Gulf Coast.

Hi, proportion we do.

And it's calculated based on the purchase of Muslim price and.

And a sale of the Gulf Coast price and really the function for the growth. This quarter is the results of the basis closing.

You can see and the and the appendix we've summarized the burnt premium and summarize the meat's premium both of which were exposed to on our sales and we related that to Midland.

But we'll which has been growing as well so the differential and closing has been made made the takeaway they're going forward. After this quarter, we're going to have a larger portion of our crude oil and transported the Gulf coast.

And what's the role of the.

Central Howard the acquired Walo assets being transported to the Gulf Coast. So our transportation should go <unk>.

Slightly up but.

The purchase and sales third party of oil will go down and.

And so and then the next step changes will be and the first portion of next year we.

And the British tax transportation, which is 2000 per day expires.

2 very from where you see differential today or in the future per per differentials, how should we expect group net charge to trend beyond Q3.

It will trend relative to the opening of the differential.

Okay, great. Thank you.

And emotional and any further questions.

Time or electric complex over to our house.

But thank you for joining us. This morning, we appreciate your interest in Laredo and this concludes our call.

Harvey speakers.

Jordan and I'll re cute did you want to go and take my question reports.

Well, ladies and gentlemen from conclude today's presentation. You may now disconnect and have a wonderful day.

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