Good day, ladies and gentlemen, and welcome to the Laredo Petroleum, Inc. Q2 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. 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. Good morning. Joining me today are Jason Pigott, President and Chief Executive Officer, Mark Maroldo, Senior Vice President and Chief Operating Officer, and Bryan Lemmerman, Executive Vice President and Chief Financial Officer, as well as additional members of our management team. During today's call, we will be making forward-looking statements. These statements, including those describing our beliefs, goals, expectations, forecasts, and assumptions, are intended to be covered by the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Our actual results may differ from these forward-looking statements for a variety of reasons, many of which are beyond our control. 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 Q2 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 two years ago, we rolled out a straightforward business model based on three core principles: expanding our high-margin inventory, managing risk, and continuously improving. Our industry has experienced some wild swings over the last two 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 Energy, LLC acquisition on July 1st, in a little over one and a half, we have acquired more than 37,000 net acres of oil-weighted leasehold and have completely transitioned our development activity over to that leasehold. We completed our first package of wells in Howard County during the Q4 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 worked with our financial partners to extend the credit facility and pay down the revolver, providing us a path for future inventory growth, which Bryan 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 surface, 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 drying the sand that occurs at other mines. Mark 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 Mark for an operational update. Thank you, Jason. 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 County, with the majority of our activity in Howard County. During the Q2, we completed 16 wells, all in Howard County. Thirteen of these wells were the Davis package. This is our third well package in what we are now calling Central Howard. This third well package is different from our first two well packages in that we are widening spacing on the wells in the Wolfcamp A formation. In the first two well packages in Central Howard, we targeted spacing equivalent to 12 wells in the Wolfcamp A and four wells in the Lower Spraberry. In the Davis package, we widened the spacing to 10 wells in the Wolfcamp A and four wells in the Lower Spraberry. In all subsequent well packages in central Howard, we plan to develop with eight wells in the Wolfcamp A and staying with the four wells in the Lower Spraberry. These well counts have been included in our gross location counts since Q1, and we do not expect any changes to the gross locations shown on slide five. On slide five, you will also see the Davis cumulative production relative to the 2 more tightly spaced packages, which are the Gilbert Pass Owl and the Trentino Whitmire packages. While still early in its flow back, the Davis package is responding exactly how we would expect with wider 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 1st. 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 for DSU, but with six wells in the Lower Spraberry and six wells in the Wolfcamp A in the North Howard acreage position. The Vince Everett package was actually drilled on a slightly tighter spacing than the 12 wells for DSU. Due to this tighter spacing, we expect its outperformance relative to the other Howard County packages to narrow over time. 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 drilling and completions activities in third and Q4s of this year to finish all of the work in progress that was begun by Sabalo prior to close of the acquisition on July 1st. In the chart on the bottom of slide six, you can see the increase in completed wells being put on flowback in the second half of 2021 with this increase in activity. The additional wells are key to driving the oil production growth in the Q3 and Q4s of this year and building momentum into 2022, as you can see in the top chart on slide six. In 2022, we expect to return to a more moderate activity pace, operating with two rigs and one 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 continued to drive down drilling and completions costs and delivered our wells at an average cost of $525 per foot. As shown on slide nine, our drilling and completions operations continued their strong trend of getting more and more efficient through the Q2. 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 three additional wells in the Q2 for a total of 16 wells. Lastly, turning to slide 11, 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, Mark Maroldo. As Mark Maroldo 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 can 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- 38,000 barrels per day. Again, quarter-on-quarter will 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 continue 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 welcomed four 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 a commitment level of $725 million, and our credit rating saw a one-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 in 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 2022. We are approximately 93% hedged on natural gas in 2021 and 51% in 2022. For NGLs, we are approximately 72% hedged for the remainder of 2021 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 Q3 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 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. Ladies and gentlemen, if you have a question or a comment at this time, please press the star then the one key on your touch-tone telephone. If your question has been answered and you wish to remove yourself from the queue, please press the pound key. Our first question comes from Derrick Whitfield with Stifel. Thanks, and good morning, all. Morning. Good morning. 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 in achieving the Q4 exit rate, given the ramp in your learning curve in Howard County over the last several quarters? From an execution perspective, I'd imagine there's limited science, so to speak, in the 17 wells you're bringing on in Central Howard during Q3. Yeah, 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 1,000 barrels a day each. When a frac crew takes one week longer to get here more than we planned, it can just create uncertainty in the volumes for the quarter. As Bryan mentioned in those prepared comments, these aren't things that necessarily impact the value of it. These are new wells, new packages. Getting the second frac crew spun up on our timing, those are all things that go into some of that. As you see on slide five 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 dense spacing. We needed, as a company, to test the tighter spacing to make sure that we weren't leaving any wells behind. We had already pre-planned to test wells on wider spacing as well. What's great is every subsequent package that we've 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 pair that with slide six, you'll see that we are moving our activity. We'll finish 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. Then perhaps a slight build on that question perhaps for Mark. Could you speak to the differences, if material, between your development approach and that of Sabalo's, and how you plan to bridge the two over the next few quarters? Yeah, sure. I'd be happy to talk a little bit more about how we're going into what we're calling now the North Howard Area. 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 Vince Everett for comparison, again, that, as we move forward, will be based on the 12 wells per DSU. Really overall, the same overall development plan from a total well count. As you move to the north and northwest into the new acreage position, we really see much stronger Spraberry well results. As we move in that direction, really want to focus the transition of the development plan with those well results. Right now, looking at within the 12 well, having a six-well Spraberry and a six-well Wolfcamp A development. We'll continue to 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. Continue to watch and see how the Vince Everett, which was based on the additional Spraberry wells and the Davis package produce out past where we are right now in the early time production Very helpful. Thanks for your time. Thank you, Derrick. Our next question comes from Jordan Stuart with GoldenTree Asset Management. Hey, guys. This is Eric Seeve with Jordan. Question for you on the hedging side. It looks like there's about an $11 million charge for net premiums paid for commodity derivatives that mature during the quarter, which looks like it's a non-cash charge for premiums that were paid prior to this quarter. Could you just talk a little bit, give a little bit more color on what that is? It seems like a non-cash expense, and just curious why is the thought process in terms of whether or not to add that back for your adjusted EBITDA number? You are correct. That is a non-cash charge. Those premiums were paid in 2020. They are being allocated over 2021 as those hedges mature. Actually, 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. It's an adjustment to adjusted EBITDA throughout this year, but is not a cash charge. Okay, what's the expectation for that in future quarters? You will have that in 3Q and 4Q of 2021, but then as you move into 2022, it will cease. Okay, great. Thank you. Moving on. One line item that I guess we don't understand as well and 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 has been climbed. 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 Gulf Coast, but a sizable portion we do. It's calculated based on the purchase at a Midland price and a sale at a Gulf Coast price. 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 MEH premium, both of which we're exposed to on our sales. We related that to Midland, plus the roll, which has been growing as well. 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 transported to the Gulf Coast. That's with the roll-up of the Central Howard, the acquired Sabalo assets being transported to the Gulf Coast. Our transportation should go slightly up. The purchase and sale of third-party oil will go down. The next step change will be in the first portion of next year when the BridgeTex transportation, which is 10,000 a day, expires. Based on where you see differentials today or the future curve for differentials, how should we expect this net charge to trend beyond Q3? It will trend relative to the opening of the differential. Okay, great. Thank you. I'm not showing any further questions at this time. I'd like to turn the call back over to our host. Thank you for joining us this morning. We appreciate your interest in Laredo, and this concludes our call. Pardon me, speakers. Jordan on re-queue. Did you want to go ahead and take that question real quick? Well, ladies and gentlemen, this concludes today's presentation. You may now disconnect, and have a wonderful day.