Thank you, and good morning. Joining me today are Jason Pigott, President and Chief Executive Officer; Bryan Lemmerman, Senior 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. 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, detailing our financial and operating results for third quarter 2022. The press release and presentation can be accessed on our website at www.laredopetro.com.

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

Thanks, Ron, and good morning, everyone. Thanks for joining us today.

We appreciate your interest in our company. Financially, the third quarter was another good one for Laredo as we continued to execute our proven plan to add long-term value.

We continue to benefit from strong commodity prices and maintain capital discipline to preserve our margins and manage our ongoing inflationary pressures. There are a few highlights I would like to review.

First, we generated $51 million of free cash flow in the third quarter. Second, we used this cash flow and cash on hand to repurchase a combined $170 million of debt and equity, strengthening our balance sheet to a leverage ratio of 1.25x.

And finally, capital investments in the quarter were similar to last quarter with a consistent pace, 2 drilling rigs and 1 completions crew. We will maintain similar levels of activity in the fourth quarter and plan to invest $135 million to $145 million.

Third quarter production was pre-released a few weeks ago. Total production was within our previous range, oil volumes came in below expectations.

Production from Howard County was negatively impacted by high levels of completions activity by offset operators that impacted some of our larger volume recently developed pad. We coordinate the management of producing wells with offset operators, but the recent impacts were greater than modeled.

The strong returns industry is seeing in Howard County, we have no reason to believe that activity levels will decrease in the near future. We have adjusted our forecast to ensure that our estimates in the future better reflect the timing and impact of offset activity.

We included a production graph on Slide 5 of our earnings presentation plotting all Laredo operated wells in Howard County that have been frac impacted. [Technical Difficulty] demonstrates that following a frac impact, wells returned to their pre-frac impacted production curve.

Timing and radius of the impacted wells are the larger drivers of our forecast change rather than reduced post per frac well performance. We've taken significant steps to ensure that our future performance will be stronger and more predictable.

Recently restructured our operations team, eliminating the COO position. These duties were immediately assumed by Kyle Coldiron, VP of Subsurface and Business Development, [Technical Difficulty] a new team member, Katie Hill, VP of Operations.

These leaders now report directly to me and increase our focus on these 2 distinct parts of our business. I'm extremely confident in their ability to deliver in the coming quarters.

While we've had some challenges this quarter, I would like to reiterate some of the progress we've made on our journey over the last couple of years, [Technical Difficulty] of our investor deck. We list a few of the more dramatic changes we have made as a company since 2019 compared to current year-to-date performance.

Just to name a few of those highlights. First, we increased our liquidity 61% to $1.050 billion, grew oil production 28% and we reduced our leverage ratio 38% to 1.25x.

Before I turn the call over to Bryan, I would like to cover a few items concerning 2023. First, we are highly confident in our business plan.

We have all the key components in place today to create value. High-quality assets, a deep inventory, effective risk management and a team of professionals aligned on the importance of delivering our key objectives.

Our focus on capital discipline remained unchanged in 2023, and we expect that we will again deliver free cash flow, reduce debt, strengthen our balance sheet and methodically return cash to shareholders through our buyback program. For activity levels in 2023, we expect to continue to run our current 2-rig drilling program for the full year.

We will also add a spot crew in addition to the existing crew similar to 2022. The continued drilling efficiency improvements experienced year-to-date will enable us to complete 6 more wells in '23 than we did in '22.

This activity level is expected to generate mid-single-digit oil production growth full year 2023 compared to the fourth quarter of 2022. We are working with all of our service providers to ensure Laredo's high safety standards while securing quality equipment and labor at the best rate.

In addition, we are monitoring commodity markets and will continue to utilize derivative markets to ensure we lock in returns and have high certainty in our cash flows. Consistent with past practice, we plan to issue 2023 guidance early next year following our internal reviews and Board approval.

I will now turn the call over to Bryan for a financial update.

Thank you, Jason. Third quarter, we continued to strengthen our balance sheet and return cash to shareholders.

During the quarter, we repurchased $152.5 million base value of term debt at 98% of par. Through Tuesday, November 2, we have repurchased a total of $245 million face value of term debt at 99.2% of par.

Of the repurchases, $90.9 million base value have been of our 2025 notes, increasing our flexibility as these notes need to be refinanced or redeemed in the next year or so. These repurchases have been funded through cash on hand and free cash flow, enabling us to reduce annual interest expense by approximately $21 million.

During the quarter, we reduced total net debt to $1.14 billion. We ended the quarter with $40 million drawn on our $1 billion credit facility and had roughly $50 million of cash on hand.

As of November 2, we had paid our revolver balance to 0 and hold cash of approximately $54 million. On November 1, we finalized our semiannual RBL redetermination process with our bank group.

As part of this process, our borrowing base was increased to $1.3 billion from $1.25 billion and our elected commitments were maintained at $1 billion. The other significant change was that our restricted payments baskets have been simplified and brought in line with where the market is today.

This gives us more flexibility with regard to debt and equity repurchases as long as we remain in compliance with standard ratio tests. During the quarter, we returned $17.5 million of cash to shareholders through our equity repurchase program.

From November 2, we have repurchased a total of $34 million of equity, were approximately 442,000 shares at an average price of $77. With that, I will turn the call over to the operator.

Please open the line for questions.

For my first question, I wanted to focus on Slide 5 and specifically the frac impact period you saw in Howard County. Could you share your expectations on whether you expect similar frac impacts to occur in the future?

And how you are approaching this from an operational planning and guidance perspective?

We'll let Kyle Coldiron, who's Head of our Planning and Subsurface, talk to you about that.

Yes. Thanks, Ron.

So ultimately, the way that we did this analysis and what we're communicating here is that we went back and looked at all of our wells in Howard County that have experienced a frac impact over the last 4 years. And we basically kind of normalized them in terms of the pre-frac hit period and then the post frac hit kind of after they've cleaned up and experienced the frac hit.

And what you can see here is that the wells ultimately return to their prior production rates, and we're not seeing a long-term impact as a result of that frac hit. So ultimately, this well set has both wells that are older that have been online for a number of years and wells that are newer and have only been online for a few months.

And so you can see across that type of well set, we're not seeing a big impact. So we have decided to increase the radius of our expectation of wells that will be impacted by offsetting frac impact.

We've effectively doubled that from what we've assumed in the past. And we've also given older wells a little bit longer time in our modeling to clean up prior to returning to their previous rates.

So that's some of the changes that we've made in our expectations going forward. But the key takeaway here is that the wells returned to their previous rates.

And really, what we're seeing is a deferral of production, not a loss of production due to well productivity.

That makes sense. And then for my follow-up, there's been a lot of attention this earnings season on co-development approaches and impacts on wealth productivity.

Could you provide some details on how you view your program differently versus peers and their approaches that are now just changing?

Yes. So ultimately, what we think we found is the right mix of completion size and well spacing.

If you look at our development in North Howard, there on Slide 5, you can see our North Howard well performance is very strong. Our original 2 packages in Central Howard, which are the orange lines, you can see those were a little bit tightly spaced relative to what we’re doing today, and you can see the result of that on that plot.

So we feel like we’ve got a good combination of well spacing and frac size. Other operators sometimes can space tighter with smaller fracs, some go a little bit wider with bigger fracs.

But ultimately, with our acreage and our footprint, we think we found the right combination.

Thanks so much for the time. Really good work on addressing your liabilities and moving your maturity wall back and cutting it down.

I was just interested on 2025. Those do become -- well, the coal price steps down in January.

As you think about liquidity, is that something that would be a priority for you to take out when the coal price steps down? Or would you like to maintain a bit more liquidity and be more measured about the further reduction of that maturity?

Sure. This is Bryan.

As we've said, what we plan to do is pay these down pretty much in line with cash flow. So as we approach 2023 with prices a bit lower than they had been predicted a few months back.

I think we will address this as it gets closer. As you mentioned, the liquidity is a key component right now.

We have $1 billion of liquidity, which puts us in a good space for acquisitions. So we want to be careful to maintain that.

With the RBL redetermination process completed earlier this week, we have the flexibility to basically call those bonds whenever we want and bring them on to the revolver. So there's not a rush.

I can do it anytime between now and a year from January. The main item would be maintain that flexibility and making the right financial decisions.

So we'll monitor that as we get closer and address it that way.

Jason, you talked a little bit about your production expectations for 2023 in your prepared comments. But could you give us a little color on how you're thinking about capital in '23?

Maybe what you're thinking as far as year-over-year inflation compared to what you're seeing this year?

Yes. Thanks for the question, Zach.

We expect to be around $590 million for the year. Right now, best estimates are around 10% inflation would be a good factor to put in there.

And that puts us right around where consensus is. So I think that's where we are today.

We're still going through the budgeting process right now. We will have, again, a few more completions, but we'll also have less wells being drilled because we've built some kind of DUCs as we've gone into the end of this year.

So that's kind of the plan, I think where we'll be but we're still going through the process of finalizing our budget, and we'll come out with those details early next year.

Zach, to clarify, when Jason said $590 million for the year, he's referring to 2022 and the 10% is relative to '23 relative to '22.

Got it. And then I guess just a follow-up on the buyback.

With the commodity strip in backwardation and leverage still above 1, do you have any thoughts on potentially slowing the buyback in the near term to focus more on debt reduction? Just really, I guess, in general thoughts on how you think about the buyback over -- the pace of the buyback over the near and longer term?

Yes. I think as we've seen price come back, slowing it down as a ratio to total cash going to both the bond and the equity repurchase programs.

it has come back a little bit. As we move into next year, we will definitely use commodity price and free cash flow as a determining factor of how much and what ratio.

Right now, I'd say keeping at the ratio we were is a decent plan. That would still not put us at using the whole thing, paying -- or using the whole $200 million by the end of next year.

But if prices moved higher, I think we'd get more aggressive as prices move down, we get less aggressive. And our primary focus is still on debt reduction.

That is the most important thing to us and then just keeping the equity repurchase program on a methodical pace.

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