Laredo Petroleum, Inc.

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 the press release and presentation we issued yesterday that detail our financial and operating results for second quarter 2022. Press release and presentation can be accessed on our website at www.laredopetro.com. I'll now turn the call over to Jason Pygott. President and Chief Executive Officer.

Thank you, Ron. Good morning, and thank you for joining us for our discussion of our second quarter results. With our financial and operational results for the quarter, we have also updated our 2022 outlook and given capital and oil production projections and updated free cash flow sensitivities for 2023. I'll start with our quarterly results. our second quarter results exceeded expectations, delivering company record adjusted EBITDA and free cash flow. Second, we immediately began delivering on our $200 million equity repurchase program and debt reduction targets we announced on May 31st. To date, we repurchased $16.1 million of equity and $91.4 million of face value term debt. In addition to reducing absolute debt, our leverage ratio decreased from 1.9 times in the first quarter to 1.4 times in the second quarter. Third, we continue to demonstrate capital discipline. Second quarter capital came in a little higher than expected, primarily due to acceleration of operations associated with the timing of ongoing completion, associated facilities, and a small amount of non-off activity that was expected in the second half, not changing our full year 2022 capital budget of $550 million. Moving to our updated 2022 and 2023 outlook. Near the end of the second quarter, we turn into line a six-well package, the leach wells, consisting of six 15,000-foot wells in our most southeastern unit in Howard County. These wells are still in the flow-like stage. The oil production ramp has taken much longer than the offset wells, and the wells are underperforming our prior forecast. Oil production for full year 2022 is now expected to be between 38 and 39,000 barrels of oil per day versus prior guidance of 39.5 to 42.5 thousand barrels of oil per day. Full year 2022 free cash flow at prices of $100 per barrel WTI for the remainder of the year is now expected to be approximately $280 million versus prior projections of $350 million. initial outlook for 2023 we have incorporated the impact of the leach package our current capital expenditure projection additional drilling and completion efficiencies and interest savings from debt repurchases to date currently at 90 dollars per barrel wti price for 2023 we expect free cash flow of approximately 560 million dollars versus prior projections of 550 million dollars and expect low single-digit oil growth compared to the new 2022 oil production range. I stress that nothing has changed the trajectory of the company or our debt reduction and equity repurchase plan. There is no impact to inventory counts or how we execute our development plan. Overall financial impact of all of our updates over the second half of 2022 and full year 2023 is approximately $60 million. We are committed to delivering on our $200 million equity repurchase program

absolute debt reduction target of 700 million dollars and our leverage ratio target of sub 1.0 times i will now turn the call over to karen hey jason and good morning in the second quarter we completed 11 wells until seven wells production was within our guided ranges even when including the working interest adjustments to wells that reach payout prior to the quarter that was outlined in the earnings release. Total expenditures were slightly above expectations, mainly due to a slight acceleration of operations associated with the timing of ongoing completions and associated facilities, and acceleration into the second quarter of a small amount of non-op capital that was expected in second half. About a quarter of the increase was due to inflation, which was primarily related to diesel expenses running over 40% higher on average than our original estimates. For second half, we've incorporated these higher diesel costs into our capital numbers. We expect capital to be approximately 120 million in both the third and fourth quarters and to maintain our full year 2022 budget of $550 million. As Jason mentioned, Six of the seven wells that we tilled during the quarter were 15,000 foot Wolf Camp A wells in the leach package, developed on the far southeastern edge of our central Howard acreage position. We generally feel that rock quality in Howard County degrades to the south. Very good well control and data from previous packages in and around the leach area and decided to take measures to de-risk the package and improve projected returns based on this information. We developed only the Wolf Camp A formation, despite traditionally co-developing with the Lower Sprayberry, also widened spacing in the Wolf Camp A. These changes resulted in a six-well development in the unit versus our standard development plan of 12 wells per DSU. Despite these efforts, production results have been disappointing. The leach package has been on pullback for a little more than two months and is still producing significant amounts of water and low oil production. We're currently working on options to optimize our artificial list strategies and evaluating other potential remediation strategies as we continue to watch and gain additional understanding of the well production over time. Given the abundance of offsetting well data in Central Howard, the remainder of our development being west and north of the leach wells, we do not believe this impacts any of the 23 remaining locations in Central Howard. These locations, five are expected to come online in 2023 and direct offsets to the Worthy-Buchanan and Connor packages completed in fourth quarter 21 and first quarter 22 respectively. 18 are expected to be developed in 2024, giving us plenty of time to apply the learnings from the leach package and adjust how those DSUs are developed if needed. Leach well results do not impact our long-term trajectory or inventory count. the deep inventory of high-quality, drill-ready locations and flexibility in our development plan. The remainder of our tills in 2022 are all in North Howard, and more than 90% of all tills in 2023 are in North Howard. Cleve rock quality is substantially better in Howard County as you move northwest And as you can see on slide six in the earnings presentation, our production data bears that out. Focus on North Howard in the second half of 2022 and full year 2023 benefits our oil production expectations for 2023. In the preliminary 2023 outlook we issued within our earnings release, our projection of low single-digit oil growth compared to updated guidance for full year 2022 is driven by the expected productivity of North Howard. Within our preliminary 2023 outlook, we have a capital estimate of approximately $585 million. The primary difference from the $550 million budget in 2022 is related to the spot frack crew that is currently anticipated to operate for most of the first half of the year. With continued performance improvements in drilling feet per day, we are anticipating being able to run the spot frack crew for a total of five months without adding any additional drilling activity above our current two rigs. Overall, keeping our duck count low and using the spot frack crew as early as possible in the year, provides our most capital-efficient operations program. This additional completions activity is also the reason we are able to fully offset the expected negative production impact from the leach wells next year. I will now turn the call over to Brian for a financial update.

Thanks, Karen. We delivered very strong financial performance in the second quarter. We generated company record free cash flow and adjusted EBITDA. We took our revolver balance to zero. We reduced leverage by half a turn. And we aggressively repurchased our debt and equity, fulfilling our commitment to return capital to shareholders. Taking a look at the balance sheet, we ended the quarter with $146 million of cash. And as of Tuesday, we have approximately $114 million of cash, with our revolving credit facility completely undrawn. Liquidity stands at $1.1 billion, with quarter-end leverage at 1.4 times. We reiterate our leverage goal of achieving a sub-one times leverage goal, which we believe we will achieve in Q2 of 2023. Also reiterate our absolute debt reduction target of $700 million, putting us at approximately $700 million of net debt. The $700 million target leaves us in a position to be approximately one times levered in lower price environments. Through Tuesday, Laredo has purchased $91.4 million of our notes at an average price of $98. These purchases have been skewed toward the 2029s and 2028s, with approximately $52 million of the 2029s, $29 million of the 2028s, and 11 million of the 2025s purchased to date. We plan to repurchase a total of 250 million of notes through the end of the year. On the equity side of the equation, through Tuesday's trading, we have repurchased approximately $16 million of our stock at an average price of $87.62 a share. We will continue to repurchase shares somewhat methodically, but when our share price indicates that we can repurchase our shares, which are a proxy for our assets, at prices below where assets are trading on the M&A market, we will accelerate those repurchases. Our free cash flow for the second quarter came in at $110 million, in line with our expectations, and these cash flows were directed towards our debt and equity repurchases. Dated for current guidance, under the same pricing scenario we used in our last guidance, Laredo is expected to generate $280 million of free cash flow for 2022 and approximately $840 million of free cash flow through the end of 2023. This represents a decrease over the two-year period of approximately $60 million over our prior guidance. On the M&A front, we have been actively looking at opportunities in the market and have not found many that have the right mix of inventory to PDP. I do still believe that scale matters and that M&A will be a part of our strategy for the foreseeable future. But we will remain diligent in what we go after and how we finance it so that it is accretive to shareholders and does not derail our deleveraging goals. With that, I will turn it over to Jason for final comments.

Thank you, Brian, and thank you all for joining us today. Operator, please open the line for questions.

And as a reminder for everyone, if you do have a question today that will be star one, we'll pause for just a moment. We'll hear first today from Derek Whitfield with Stifel.

Thanks and good morning all. Good morning, Derek. For my first question, I wanted to start with the leached DSU. It appears that both pre- and post-trail data indicated this was your highest risk DSU within Howard County. Could you speak to your degree of confidence that the DSU to the west, which you plan to develop in 2024, would be a commercial DSU, and perhaps also speak to if there's a noticeable difference in well performance from east to west within the leached DSU?

Yeah, thanks, Derek. This is Kyle Fuller. So, yes, absolutely. Within the leach DSU itself, the westernmost wells are the highest producing wells. As we move to the east, we see a higher water cut and lower oil production in the easternmost wells. And so, that combined with our current offsetting production around the undeveloped DSUs that will be developed in 2024, We have strong production around those DSUs on both sides, which ultimately gives us confidence that they are unaffected by the issues that we're seeing in the leach package.

Terrific. And just as a follow-up to put some parameters around this leach DSU, Could you frame the NPV impact associated with it if your oil cut doesn't meaningfully appreciate? At most, it would just seem to be the cost of the wells, but you already trade at a discount or at your PDP depending on your discount rate. Am I thinking about that correctly?

Yes, Derek. This is Brian. The capital has already been spent. I think the way to think about it is the impact on cash flows going forward and the largest portion of that would be the 70 million impact in the back half of this year. That will get almost all of your NPV impact.

Terrific. That's all for me. Thanks for your time.

And at this time I'd like to turn things back to Mr. Haygood for any closing remarks.

Thank you for joining us this morning. We appreciate your interest in Laredo. This concludes this morning's call.

And again, that will conclude today's conference. Thank you all for joining us. You may now disconnect.