Vital Energy Inc (VTLE) 2021 Q2 法說會逐字稿

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. (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.

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 our press release and presentation that we issued yesterday that details our financial and operating results for the second quarter of 2021. We will refer to the presentation during today's call. If you do not have a copy of this presentation or press release, 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.

Good morning, and thank you for joining us today. When I started with Laredo, just over 2 years ago, we rolled out a straightforward business model based on 3 core principles: expanding our high-margin inventory, managing risk and continuously improving. Our industry has experienced some wild swings over the last 2 years, yet we never wavered from these core principles and our activities during the quarter and subsequently to the close, have accelerated our progress. Since we announced our first acquisition of oil-weighted properties in November of 2019, our transformational rate of change has been steep. With the closing of the Sabalo acquisition on July 1. And a little over 1.5 years, we have acquired more than 37,000 net acres of oil-weighted leasehold and it completely transitioned our development activity over to that lease hold. We completed our first package of wells in Howard County during the fourth quarter of 2020, and this transition is expected to position us for substantial free cash flow generation in 2022, reflecting the capital efficiency of our development program. We increased our hedge position to protect our anticipated free cash flow generation, which should result in 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 will discuss in a moment. We continue to improve operationally even with the complete transition of our development program to Howard County. We reduced DC&E costs in the face of increased cost pressures. We were a basin leader in establishing a sand mine on our company-owned circus, which also mitigated a substantial portion of the cost pressure, and we estimate it saves us approximately $200,000 per well in the current environment. The mine has additional ESG benefits of keeping trucks off the road and because it is a wet sand mine, eliminates the combustion-related emissions associated with drawing the sand that occurs at other mines.

Karen will also highlight how our wider space wells and Northern Howard County wells are outperforming our initial package in Central Howard County. We believe our strategy is working. We will continue to follow these core principles that result in our ability to generate substantial free cash flow and build long-term value for our investors. I will now turn it over to Karen for an operational update.

Thank you, Jason, and good morning, everyone. As Jason just mentioned, we have now fully transitioned our development activities to our acquired acreage positions in Howard County and Western Glasscock, with the majority of our activity in Howard County.

During the second quarter, we completed 16 wells, all in Howard County. 13 of these wells were the [Davis] well package. This is our third well package in what we are now calling Central Howard. This third well package is different from our first 2-well packages in that we are widening spacing on the wells in the Wolfcamp A formation.

In the first 2 well packages in Central Howard, we targeted spacing equivalent to 12 wells in the Wolfcamp A and 4 wells in the Lower Spraberry. In the Davis package, we widened the spacing to 10 wells in the Wolfcamp A and 4 wells in the Lower Spraberry. In all subsequent well packages in Central Howard, we plan to develop with 8 wells in the Wolfcamp A and staying with the 4 wells in the Lower Spraberry. These well counts have been included in our gross location count since first quarter, and we do not expect any changes to the gross locations 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 Tretino/Whitmire packages. While still early in its flowback, the Davis package is responding exactly how we would expect with lighter spacing and is outperforming the tighter space packages by an average of 19%.

I'd also like to point out the performance of the Vince Everett well package on this slide. The Vince Everett package was recently completed by Sabalo and came with the acquisition on July 1. In the Sabalo 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 Spraberry as you move north and west in Howard County. Again, we plan to stay with the wider spacing at a total of 12 wells per DSU. But with 6 wells in the Lower Spraberry and 6 wells in the Wolfcamp A in the North Howard acreage position. The Vince Evert package was actually drilled on a slightly tighter spacing than the 12 wells per DSU. And due to this tighter spacing, we expect this outperformance relative to the other Howard County packages to narrow over time. But we're still very excited about the initial performance of this well package and what it is potentially telling us about the quality of the North Howard leasehold.

We are currently working to fully integrate the acquired Sabalo leasehold into our development plans. As we previously announced, we will be temporarily increasing both the drilling and completions activities in third and fourth quarters of this year to finish all of the work in progress that was begun by Sabalo prior to close of the acquisition on July 1.

In the chart on the bottom of Slide 6, you can see the increase in completed wells being put on flow back in the second half of 2021 with this increase in activity. The additional wells are key to driving the oil production growth in the third and fourth quarters of this year and building momentum into 2022, as you can see in the top chart on Slide 6.

In 2022, we expect to return to a more moderate activity pace operating with 2 rigs and 1 completions crew. We expect to be able to hold oil production relatively flat in 2022 and beyond, even with the more moderate drilling and completions activity levels. In the first half of 2021, we continue to drive down drilling and completions costs and delivered our wells at an average cost of $525 per foot.

As shown on Slide 9, our drilling and completions operations continued their strong trend of getting more and more efficient through the second quarter. These efficiencies, coupled with savings from our Laredo owned sand mine helped us fully offset cost pressures that we are beginning to see related to pressure pumping, diesel and steel pricing. At current market prices, we estimate that our sand mine is now saving us more than $200,000 per well. These efficiencies also allowed us to deliver 3 additional wells in the second quarter for a total of 16 wells.

Lastly, turning to Slide 11. We I'd like to point out our flaring and venting statistics for the first half of 2021. On the chart on the right, you will see the strong trend of reduced flaring and venting compared to our 2019 and 2020 numbers. Our first half 2021 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 in Howard County. I'll now turn over the call to Bryan for a financial update.

Thank you, Karen. As Karen mentioned, we are temporarily increasing activity to finish the activity begun by Sabalo. Most of this capital activity is reflected in Q3 and the resulting flowback towards the end of Q3 and into Q4, which drives the steep oil production increases we expect in Q4. The guided trajectory and ranges we have outlined for Q3 and Q4 reflect our best estimate of when these packages will see flowback. Flowback dates being 10 days faster or 10 days slower and have a substantial impact on the quarter with no real impact to value.

Moving into 2022 at our moderated activity levels we expect to hold oil production relatively flat at a normalized rate of 36,000 to 38,000 barrels per day. Again, quarter-on-quarter, we'll have variations as we have demonstrated through the capital spend graph on Slide 6.

Now turning to the balance sheet. We continue to make progress deleveraging and improving our capital structure with the Sabalo and Sixth 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 in 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 in the market as we welcome 4 new banks to our 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 maintained the commitment level of $725 million and our credit ratings 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 the recent acquisition and our hedging program, we have enhanced the free cash flow generation profile of the company for the next 18 months. Currently, we are approximately 80% hedged for oil for the remainder of 2021 and 70% for '22. We are approximately 93% hedged on natural gas in '21 and 51% in '22. And for NGLs, we are 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-weighted properties where we can apply our efficient low-cost operational capabilities. With that, I turn the call over to Jason for closing remarks.

Our activities in the third quarter were pivotal to our transformation. We have a lot of momentum going into the second half of the year I'm excited to continue working with our talented team to maintain the high rate of change that we have experienced over the last couple of years. We will now open the line for questions.

(Operator Instructions) Our first question comes from Derrick Whitfield.

For my first question, I'd like to focus on your production trajectory referencing Slide 6, what is the greatest risk factor in your view, other than timing and achieving the fourth quarter exit rate given the ramp in your learning curve in Howard County over the last several quarters? From an execution perspective, I imagine there's limited science, so to speak, in the 17 wells you're bringing on at Central Howard during Q3?

Yes, that's a great question, Derrick. I think as we look to add the frac crew, just as we think through some of these wells, again, bringing on 12 well pads, some of these wells hit peaks of over a 1,000 barrels a day each. And so when -- if a frac crew takes a week longer to get here more than we planned, it could just create uncertainty in the volumes for the quarter, but as Bryan mentioned in those prepared comments, these aren't things that necessarily impact the value of it, but there are -- these are new wells, new packages, getting the second frac crew spun up on our timing. Those are all things that kind of go into some of that. But as you see on Slide 5 in the deck that we've got out there, the new packages have been outperforming our initial package. We're really excited about them. These are the first ones to come on at the less in spacing. We needed to as a company to test the tighter spacing to make sure that we weren't leaving any wells behind. But we had already kind of preplanned to test wells on wider spacing as well. So what's great is every subsequential package that we brought online is outperforming the initial package for those that didn't see our update earlier. We also added that Vince Everett pad, which is on the Sabalo acreage in Northern Howard County. Those wells are doing phenomenal. As you look kind of pair that with Slide 6, you'll see that we are moving our activity -- we'll finish with the work they started, but then we're moving our rigs over to that area. And that area will really dominate most of the turn in lines for 2022.

Great detail. And then perhaps a slight build on that question, perhaps for Karen. Could you speak to the differences if material between your development approach and that of Sabalo and how you plan to bridge the 2 over the next few quarters?

Yes, sure. I'll be happy to talk a little bit more about how we're going into the -- what we're calling now in the North Howard area. I mean so as Jason mentioned, we're showing the well results, the most recent of our Davis package, which is based on the 12 well per section in both the Spraberry and the Wolfcamp A formation. As we start looking at the development plan in the North Howard area, looking at the well results of insert for comparison. Again, that, as we move forward, will be based on the 12 wells per DSU. So really, overall, the same overall development plan from a total well count. As you move to the northwest and to the new acreage position, we really see much stronger Spraberry well results. And as we move in that direction, I really want to focus the transition of the development plan with those well results. So right now, looking at within the 12 well having a 6-well Spraberry and a 6-well Wolfcamp A development. So we'll continue to kind of work on that development plan, the transition overall. We do think that the wider spacing at the 12 well per DSU is really the right base plan for the development plan right now, and continue to kind of watch and see how the benefit, which was based on the additional Spraberry wells and the Davis County kind of produced out past where we are right now in the early time production.

Next question comes from Jordan Store from Golden Tree.

This is Eric with -- Eric Seeve with Jordan. A question for you on the hedging side. There's a -- it looks like there's about an $11 million charge for net premiums paid for commodity derivatives that matured during the quarter, which looks like it's a noncash charge for premiums that were paid higher to this quarter. Could you just talk a little bit -- give a little bit more color on what that is? And it seems like a noncash expense. And just curious why it the thought process in terms of whether or not to add that back for your adjusted EBITDA number?

You are correct. That is a noncash charge. The -- those premiums were paid in 2020. And so the -- but they are being allocated over 2021 as those hedges mature. Actually, we had sold -- they were they were with puts and we had sold those puts earlier in this year, but the allocation of those premiums still occurs throughout the year. And so it's an adjustment to adjusted EBITDA throughout this year, but it's not a cash charge.

Okay. And what's the expectation for that in future quarters?

So you will have that in 3Q and 4Q of '21. But then as you move into '22, it will cease.

Okay. Great. Moving on, one line item that, I guess, we don't understand as well, I would love a little more color on is the purchased oil it looks like you're expecting the loss from that activity to expand a little bit in Q3 based on the guidance. Can you elaborate a little bit on what that represents and why it's trending the way it's trending and maybe what we can expect beyond Q3?

Yes. This is Ben Klein. The purchased oil loss is really a calculation derived by the amount of crude oil we have on transport to the Gulf Coast in excess of our net production that we transport to the Gulf Coast. Not all of our production, we transport to the Gold Coast, the sizable portion we do. It's calculated based on the purchase of the Midland price and the 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 in the appendix, we summarized the Brent premium. We summarized the MEA premium, both of which were exposed to our sales, and we related that to Midland plus the role, which has been growing as well. So the differential is closing is the main takeaway there. Going forward, after this quarter, we're going to have a larger portion of our crude oil transport to the Gulf Coast. That's with the roll up of the Central Howard, the acquired (inaudible) assets being transported to the Gulf Coast. So our transportation should go slightly up, but the purchase and sale of third-party oil will go down. And so -- and then the next step change will be in the first portion of next year, when we -- when the BridgeTex transportation, which is 10,000 a day, expires.

So based on where you see differentials today or the futures curve for differentials, how should we expect this net charge to trend beyond Q3?

It will trend relative to the opening of the differential.

And I'm not showing any further questions at this time. I'd like to turn the call back over to our host.

Well, thank you for joining us this morning. We appreciate your interest in Laredo, and this concludes our call.

Pardon me speakers, Jordan I requeued, did you want to go and take that question real quick? Ladies and gentlemen, this does conclude today's presentation. You may now disconnect, and have a wonderful day.