Callon Petroleum Company

Stand by, we're about to begin. Ladies and gentlemen, thank you for standing by and welcome to the Cal and Petroleum second quarter 2022 earnings conference call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question and answer session. To ask a question at that time, simply press star 1 on your telephone keypad. And please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Mr. Kevin Smith, Director of Investor Relations. Please go ahead, sir.

Thank you, Bo. Good morning. Thank you for taking the time to join our conference call. With me on today's call are Joe Gatto, President and Chief Executive Officer, Dr. Jeff Palmer, SVP and Chief Operating Officer, and Kevin Haggard, SVP and Chief Financial Officer. During our prepared remarks, we may reference the earnings results presentation and our second quarter earnings press release. both of which are available on our website. So I encourage everyone to download both documents if you have not done so already. You can find the slides on our events and presentations page and the press list under the news heading, both of which are located within the investor section of our website at www.calend.com. Before we begin, I'd like to remind everyone to review our cautionary statements, disclaimers, and important disclosures included on slide two of the presentation. We will make some forward-looking statements today during today's call that refer to estimates and plans. Actual results could differ materially due to the factors noted on that slide and in our periodic SEC bonds. We will also refer to some non-GAAP financial measures today, which we believe help to facilitate comparisons across periods and with our peers. For any non-GAAP measures we reference, we provide a reconciliation to the nearest corresponding GAAP measure. You may find these reconciliations in the appendix to the earnings presentation slide, and in our earnings press release, both of which are available on our website. Following our prepared remarks, we'll open the call for Q&A. And with that, I'd like to turn the call over to Joe Gatto. Joe?

Thanks, Kevin, and good morning to everyone on the call. As Kevin mentioned, please refer to the earnings presentation on our website as background for our commentary. I'll be highlighting a few pages in particular as a walkthrough introductory remarks. I'll start off by discussing our accomplishments for the first half of the year. As we enter 2022, we outline several goals, including maintaining momentum on strengthening our financial position, increasing capital efficiencies, and solidifying the foundation for sustainable free cash flow generation. Moreover, we emphasize progressing these goals while committing further reductions in our carbon footprint. Over the first six months of the year, we've paid down debt to $2.5 billion and reduced the company's leverage ratio to 1.67 times at quarter end. In addition, We took advantage of a window in the capital markets and refinanced senior notes with a 2024 maturity and removed the second lien notes from the company's capital structure. The end result of this timely transaction was an extension of our maturity profile and a reduction in our term debt balances. In parallel, our focus on the use of free cash flow for debt pay down this year has put us that much closer to achieving our near-term absolute debt target of $2 billion and a leverage ratio of one times which are key milestones in our return of capital strategy. Switching to operations, we've been focused on improving capital efficiencies, both from DNC activities and well productivity. In terms of the former, our average feet drilled per day has increased almost 50% since 2018 in the Delaware Basin, and profit tons pumped per day in completions have increased by approximately 160% on average across all basins. I also want to highlight substantial well productivity improvements being delivered with our Delaware Basin Development Program. Since initiating larger scale program development over the last couple years, we've acquired a significant amount of empirical production data from co-development to corroborate our subsurface modeling work. Based on this integrated data set, we've employed wider well spacing and begun to incorporate larger completion designs. These efforts have led to average wealth performance in 2022 that is almost 20% better than 2021 production, as you can see on page 10 of the earnings presentation materials. This is a critical catalyst for improving our capital efficiency and reducing our reinvestment rates in 2022 and beyond. I'll have one last operational item on the marketing front, where we continue to be proactive in our approach to moving hydrocarbons and capturing incremental economics. We announced in June the calendar had entered into multiple natural gas transportation agreements for firm transportation to the Gulf Coast for approximately 75,000 mm BTU per day, beginning in mid 2023. These transactions will increase our pricing exposure to Gulf Coast gas pricing and provide additional flow assurance benefits. Turning to EESG, we are steadily executing on our accelerated emissions reduction goals. We are well on our way to achieving our two-year plan to replace all of our pneumatic devices with zero-emission or no bleed devices, which will significantly reduce our overall emissions, particularly methane. Consistent with our track record of acquiring and proving assets, we've been investing this year in facility upgrades in our Delaware South operations to bring them in line with calendar standards and reduce flaring and other emissions. With these and other activities, we remain committed to our goal of reaching a 50% reduction in emissions intensity by 2024. You can read more about our progress and initiatives in our forthcoming sustainability report, which will be released in the coming weeks, so please be on the lookout for that. Now turning to our second quarter results. Operationally, this was a transitional quarter for us as we ramped up our completion activity and placed 33 gross wells on production, almost double the first quarter as we started developing our duck backlog that had increased pace early in the quarter. Headline production came in at the midpoint of our guidance at 101,000 barrels of oil equivalent per day, carrying an oil cut of 61% and total liquids content of 81%. Volumes for the quarter were relatively flat compared to the first quarter and were impacted by a couple of one-time items. We stepped up our workover activity as we accelerated the implementation of Calum's artificial lift program in the Delaware Basin, particularly in the Delaware South area, as we experienced higher levels of well downtime from power disruptions and typical equipment failures that occur after useful life is reached. In total, our level of workover activity was approximately twice the amount in the first quarter and pulled forward workovers for repairs and lift conversions forecasted for later in the year. While the conversion of wells to our artificial lift program does extend downtime relative to normal repairs this initiative has proven to be an important operational synergy that improves production rates and longer term run times as shown on page nine of the materials through the first half of 2022 we've seen an average sustained uplift of over 25 percent through the first 60 days of install which equates to very short payouts after factoring in near-term downtime required to perform the conversion or repair Importantly, it also extends run times and reliability for the longer term. In addition, we restructured one of our primary Midland Basin gathering contracts, changing the contract from a percentage of proceeds structure to a fee-based contract, which increased our natural gas and NGL volumes, resulting in a lower oil cut on a percentage basis. The impact of these items have been factored into our updated guidance for the remainder of the year. Given continued strong oil performance, particularly in the Delaware Basin, We are raising the bottom end of our annual production guidance from 101 to 102,000 BOE per day, with sequential growth expected over the next two quarters. We are also increasing our natural gas mix by 1% on an annual basis to incorporate the additional gas volumes realized from the gathering contract conversion. Our average wellhead pricing increased 15% to approximately $83 per BOE, a level we have not seen since 2014. The top line increase contributed to an eighth consecutive quarterly increase in cash margins, driving quarterly adjusted EBITDA to approximately $420 million on a hedge basis and over $600 million on a non-hedge basis. As our hedge portfolio steps down as percentage of production relative to the first half and associated hedge prices increase, our participation in a strong commodity price environment will improve in the back half of the year. We will also benefit from our ongoing exposure to international and MEH pricing, which represent approximately two-thirds of our oil volumes in 2022 on a combined basis. Beyond strong price realizations, controlling inflationary cost pressures is also critical to preserving our cash margins. While we have seen inflationary pressures from power and fuel on the LOE front and elevated workover costs in the second quarter from the ESP initiatives I discussed, Our guidance range for absolute LOE spent has remained unchanged. GP&T has revised up $5 million, reflective of the Midland Gathering contract conversion, which will increase our exposure to natural gas and NGL volumes, and a new contract that transfers operatorship and maintenance of a compressor station to a third-party operator, which we believe will improve operational efficiency. And finally, G&A expense has been squarely in line with initial expectations. Overall, we have managed our absolute dollar spend well in an inflationary environment, and our per unit metrics will benefit from second half production gains. As we turn to the second half outlook, completion activity will increase over the first half with approximately 40% more wells placed online in the second half. Our second half of 2022 drilling program will remain permanent focused with over 80% of the new wells coming from this area. In terms of mix, the Midland Basin will constitute a larger portion representing approximately 50% of our new wells in the second half of the year. We expect third quarter production volumes to increase to between 102 and 105 MBOE per day, as strong well performance and ongoing contributions from second quarter activity will be bolstered by increased activity in the third quarter with approximately 40 gross wells scheduled to come online. Our operational capital spending is forecasted to be between $245 and $255 million on an accrual basis which is slightly above our second quarter figure. As we've highlighted in the past, we have one of the deepest drilling inventories amongst our peers at over 1,700 locations, equating to roughly 15 years of drilling inventory. What is underappreciated by the market at times, however, are the implications of our life development philosophy, which focus on scale co-development to optimize the value of a large part of the reservoir system. The strategy captures multiple zones that deliver strong economics on both an individual well and project-level basis and minimizes parent-child relationships over time. As a result, we've maintained a more balanced inventory opportunity set for future development. On page 11 of the presentation, we've referenced a third-party independent analysis that illustrates that concept. The analysis created SHAF. or Shapley additive explanation values that are used to explain the relative contributions of a group of factors to the outcome of a predictive model. In this case, Shap values were developed for factors such as geology, well spacing, completion design, and well timing to provide the marginal impact of each on a three-year oil production target outcome. The specific geologic Shap values quantifies the marginal impact of rock quality on well performance. SHAP values were aggregated to create a distribution that characterizes a company's remaining inventory. The median of that distribution is then compared to the median of the SHAP value distribution for wells placed online in 2021 to infer comparability of rock quality for future drilling relative to 2021 rock quality drill. That analysis revealed that out of 16 operators in the Delaware Basin that were included in the study, 12 companies had a negative SHAP value. meaning the company's inventory quality is expected to decline relative to 2021 drilling over the next couple years. On the contrary, Callen had one of the highest positive values, reflecting Callen's inventory opportunity set is expected to improve in quality in the coming years as we execute our life of field development program. We've been consistent in our development approach over time, and we believe this will be an important differentiator in generating free cash flow on a sustained basis with a prospective inventory that has been developed in a more balanced manner. I will now turn the call over to Jeff to cover operations.

Thank you, Joe, and good morning, everyone. From an operational standpoint, this quarter was very impactful as we significantly increased our completion activity. While our second completions crew began operations late in the first quarter due to a crew moving from the Delaware over to the Eagleport, we really didn't hit our stride until the start of the second quarter. And over the three-month period, the number of completed wells increased by 75% versus our activity in the first quarter. And as Joe pointed out, we continue to raise the bar on operational efficiency. This year, we began utilizing a fourth-generation electric frack system. Besides the cost savings through the reduction in diesel costs, we're also realizing operational improvements. And in fact, during the quarter, we set a new company record in terms of our pumping hours per month. This has allowed us to increase the efficiency of our overall completion operations, and we've realized a 160% improvement in profit tons per day, despite largely maintaining the fracture state spacing to approximately 200 feet. On the drilling side, we've also seen operational improvements. Through the use of rotary steering tools, multi-bowl weld head design, and improved bits and bottom hole assemblies, we've seen an increase in our drilling feet per day, Specifically, during the first half of 2022, we averaged approximately 830 feet per day in the Delaware Basin, reflecting about a 50% improvement since 2018. And now I'd like to provide you with an update on each of our operating areas. So let's start with the Eagleford. After not placing any Eagleford wells on production during the first quarter, we placed 15 wells from three pads online as part of our 26-well 2022 Eagleford development program. The remaining 11 wells from this year's drilling program are scheduled to be completed during the third quarter. And as we discussed last quarter, as part of this program, we plan to complete an Austin Chalk test well. We recently drilled and logged the well and plan to complete it and place it on production later this quarter. So shifting to the Midland Basin, we continue to have success with our multi-bench development and our life appeal development philosophy. One example of this are the two Chaparral unit pads that we placed on production in early June. These seven 10,900-foot lateral wells were completed targeting multi-bench development and the Wolf Camp A, Wolf Camp B, and Lower Sprayberry formations. That subsurface system was a combination of infill and co-development, and the results have exceeded our expectations. During the quarter, we had two rigs running in the basin and drilled 16 gross wells. And we plan on keeping the two-rig drilling program on our Midland acreage through the third quarter, and then we'll drop down to one rig for the remainder of the year. Moving to the Delaware, during the quarter, we completed six gross wells and brought online 11, all in the East Delaware. The 11 wells were completed targeting multi-bench development in well camp A and B formations. And the path that I'd really like to highlight are the three drainage unit wells that were completed with a larger profit design. These, on average, 8,700-foot lateral wells achieved strong production results, with a peak average 30-day rate of 1,680 BOE per day, with an oil cut of 75%. Overall, on the drilling side, we finished the quarter with six rigs, and we'll drop our Eagle for Griggs shortly, and then we'll maintain our five-rig development pace for the majority of the remainder of the year. And prior to my final comments, I'd once again like to acknowledge Calend's field operations teams as they continue to perform extremely well across the board. And I'm very proud of everyone on the team. So in closing, in the first quarter of 2022, our focus was largely on building a duct backlog for efficient operations. And now our second quarter was largely focused on ramping up completion activity across our three major areas. With both of these objectives successfully completed, we're now in a great position to operationally deliver sequential production growth in the second half of the year while maintaining our commitment to capital discipline. And with that, I'll now turn it over to Kevin to handle the financials.

Thank you, Jeff. Our strong financial results during the quarter allowed us to continue moving closer to our near-term balance sheet goals of reducing our outstanding debt to $2 billion and our leverage ratio to one times. We generated positive free cash flow for the ninth consecutive quarter, allowing for continued reduction of our debt stack. The high yield markets opened for us late in Q2, and we opportunistically refinanced term debt, allowing us to extend our maturity profile, lower our interest rate, and simplify our capital structure by removing the second lien notes. Let's briefly go through some key financial details. First, Driven by our top-tier high oil-weighted production profile, we realized a 15% increase in wellhead revenue to $82.98 per barrel of oil equivalent. After factoring in hedging and operating costs, Callen reported its eighth consecutive increase in operating margin to $67.58 of DOE, which was a 16% increase over Q1. Our top-tier operating margins helped us realize adjusted EBITDA $418 million in the second quarter, a 6% sequential increase over Q1. During the second quarter, Callen generated adjusted free cash flow of approximately $126 million, which brings us to over $300 million of adjusted free cash flow for the first half of the year. We expect this number to ramp up in each of the remaining quarters of the year and drive continued reductions in absolute debt. Besides using free cash flow to retire debt, we remain opportunistic in taking steps to further strengthen our financial standings when the market windows are open. In late June, we issued $600 million of senior unsecured notes due in 2030, priced to yield 7.5%. We used the proceeds from this offering combined with the free cash flow we generated during the quarter to redeem $780 million of term debt, including the near-term 2024 maturity and our second lien notes. Overall, through this refinancing, we reduced our outstanding term debt by approximately $200 million, eliminated second lien notes from our capital structure, lowered our overall weighted average interest rate, and extended the debt maturity profile by two years. Our next term debt maturity is not until 2025 and has less than $200 million outstanding on it. This is an amount we can easily fund with free cash flow in the coming quarters. As part of the financing, all three credit rating agencies reviewed the calendar name and upgraded our rating. They all took notice of our rapidly improving leverage profile and overall strengthening financial health. With regard to hedging, we have positioned the portfolio with a good base layer of hedges for 2023 and are north of 20% hedge for our WTI volumes. During the second quarter, we added 3,500 barrels per day of swaps at approximately $95 per barrel for Q4 of 2022 through Q2 of 2023. Additionally, we added another 3,500 barrels per day in the first half of 2023 using wide collars that have a floor price of $80 per barrel and ceilings of $110. Finally, I'd like to discuss an upcoming accounting change. As we have met with investors, we have received plenty of feedback about how Callen's election to use full-cost accounting makes it difficult to compare the company's financials with our peers. As background, the full-cost accounting approach was traditionally appropriate for companies with long lead time, large capital projects like offshore drilling. Given that some of the reasons that we originally elected to use full-cost accounting are no longer relevant and to make Callen more comparable to our peers, we are pursuing a project to convert our financial reporting from full cost to the successful efforts accounting method. At this point, we are targeting reporting our first quarter 2023 results using this method. To head off questions, we are not ready to discuss all the ways this will impact our financials, but we plan to provide detailed information as we get closer to year end. However, I can add a couple of early guidance points. First, this change will have no impact on cash flow. Next, We would expect to have no capitalized G&A or capitalized interest in 2023 and beyond. And finally, EBITDA is likely to decrease slightly as the capitalized portion of the G&A comes back on the income statement in 2023 and beyond. And with that, I'm going to turn things back over to Joe before we move to Q&A.

Great. Thanks, Kevin. Before turning to questions, I'll leave you with a few key takeaways. We're driving improved capital efficiency at the well level as we refine our development model in the Delaware Basin, including solid contributions from our asset acquisition last year. Our focus on co-development of top tier zones over time has created a visible path for sustained inventory quality for future drilling as we have steered away from just drilling our best wells at the expense of degrading offsetting locations and adjacent zones. Our balance sheet and overall financial position is solid and will continue to improve at a fast pace into year end. Ongoing improvement will remain a key focus for the longer term, even as we look to implement return of capital frameworks in the future. And finally, we see a compelling value proposition for shareholders. Callen currently trades at a 2023 consensus free cash flow yield of approximately 30%, a price-earnings ratio of 2.3 times, and our enterprise valuation is over a billion dollars below the June 30 PB10 of just our approved developed producing reserves using last month's 12-month pricing and current operating costs under SEC methodologies. While we recognize the challenges faced by investors in a volatile environment, we believe that companies with sustainable business models supported by quality assets and people will be rewarded. Bo, you can open up the line for Q&A.

Thank you, Mr. Gatto. Ladies and gentlemen, at this time, if you have any questions or comments, simply press star 1. And if you are joining us today using the speaker phone, please ask that you pick up your handset before pressing star 1. If you find your question has been answered and would like to withdraw your question, simply press star 1 again, and we'll pause for just a moment. And gentlemen, our first question today will come from Bertrand Donis of Truist Securities.

Good morning, guys. Good morning. You talk about your debt target mostly in a leverage scenario, but you do mention the absolute debt target. So I was just wondering if you could expand on what's more important to you and maybe how you look at that leverage metric versus mid-cycle versus strip pricing and how that would determine when you would ramp up shareholder returns.

Yeah, so this is Kevin. I think the answer is we look at both of those, right? We want the absolute debt levels to be at $2 billion or even lower than that. We'd like to approach a billion and a half over the next kind of medium term. So we look at both of those. The one times and the $2 billion or less of debt allows us to have a balance sheet that positions us to withstand swings in commodity prices. So for us, it's not as much a mid-cycle price. It allows us to go low. It allows us to go high. And we have a balance sheet that we feel gets us through the different commodity price environments.

So would you characterize it as you think you'd want both or just? or one before you kind of ran them?

I think we've been pretty clear that these are both targets we need to hit before the shareholder returns enter the discussion.

That's perfect. And then just shifting gears, last quarter you kind of talked about any additional M&A and mentioned that the current pricing it's a little bit tougher to make an accretive acquisition. Could you talk about just getting a pulse check on that, whether or not, you know, that's changed or whether you've had, you know, any kind of negotiations?

I think overall, you know, we know that there's a fair amount of assets that are hitting the market, you know, what we gather from inbounds, but frankly, we're just not very active in that realm right now.

That sounds good. Thanks, guys. Thank you. Thank you. We'll go next now to Derek Whitfield at Schiphol.

Thanks, Derek. Good morning, all, and congrats on your quarter in operational progress. Thanks, Derek. With my first question, I wanted to focus on your capital plan and your progress in continuing to achieve operational efficiencies. Referencing slide eight, could you speak to what degree of efficiency you baked into your 2022 plan? And more broadly, where do you believe the efficient frontier is for Callen on both drilling and profit placement per day?

Yeah, I think that there's kind of two pieces to that answer. One is, you know, that the progress that's shown here since 2018 and how that's been steady the entire time. I think that points to the fact that the operational teams aren't satisfied with being extremely good. They want to be the absolute best. And so, you know, even though some challenging years of, say, 2020, where cruise and commodity prices, et cetera, were difficult to glue together, you still see some significant improvements, even on a year-by-year basis. And so where we land in the first half of 2022 is extremely good performance, but we always capture the desire to improve on a year-by-year basis. So what you've seen in 2022 represents an expectation that we have to continue to perform extremely well to help offset some of the inflationary pressures that we've seen. And you'll see that same thing in 2023, where we we're going to do the exact same thing. So we'll bake in some operational improvements, some of which we'll know ahead of time that we can put in place and some that will be a little aspirational to try to overcome some of the inflationary pressures we see and really maintain a high level of capital efficiency.

Terrific. I wanted to focus on slide 11. I think it's certainly a very interesting and positive visualization for Calendars. Specifically, I wanted to see if you could speak to what's driving improving rock quality in Gorkallon. It seems to somewhat defy how I would normally think about development trends, which is developing your best first.

I think that goes really to the core of what we do in terms of life and development. We've been consistent with this through the last few years of going to scale co-development of zones. There are strategies that are deployed. Just focus on your best zones and then with the mindset of coming back and getting adjacent zones later, but you're clearly going to see degradation in those zones and maybe to a degree where they're not really economic and compete for capital. So over time, we're obviously hitting our best zones, but we're also getting second and third best zones along the way and capturing really strong economics as part of the reservoir system versus discrete economic So with a more balanced approach, that means that we have those, you know, a more balanced mix of inventory going forward versus if we just focused on our best stuff and then you're left with degraded inventory going forward. So that's really the essence of what we've been talking about. It's been something that we've done even through 2020 and 2021. So that's what's showing up now. And we think it's going to be a very meaningful differentiator going forward to the extent that folks have maybe taken a different tack on that. And this was an interesting analysis. It's a very good report. You have a chance to get your hands on it. But I think it's sort of a complex Concept, like you said, intuitively, maybe you wouldn't have thought that, but this distills it pretty well and shows that there's only a few people that are on the right side of that equation, and we're happy to be one of them.

That's great. That makes sense. I look forward to seeing the report. Great.

Thank you. We go next now to Davis Petros at RBC Capital Markets.

Morning, y'all. Thanks for taking the questions. First one, and you touched on it in your prepared remarks and in the release, but can you just expand a little bit more on kind of the power disruptions in the Delaware causing that increased wealth failures and specifically kind of where you're at in the process of addressing and accelerating those artificial lift upgrades?

Sure. There's, again, kind of two parts to that answer. One of them, and it can really be broken into planned and unplanned downtime. The Delaware Basin South, as Joe had mentioned earlier, anytime we take over a large-scale asset, we always want to make sure that the level of consistency and quality of particularly the production systems, both in the subsurface and at the surface, are consistent with our operating procedures, our safety metrics, and are just consistent across the board. What we did was we went in and proactively looked at opportunities where we knew we were going to have downtime, say we were going to go in and do a facility upgrade for a flaring system, or we put a lot of work into the chemical program and how we treat hydrogen sulfide. And while we were out there, We analyzed all the wells that were within that production system and determined whether or not the ESPs were right sized or a different change in either the sizing or the age or the vintage of those downhole systems needed to be addressed. And we took advantage of those. And then the second half of those were the ones that we came in and were unplanned. And so, again, depending upon the quality of the systems that are in place, We had a slightly higher than expected drop in the systems and their efficiencies. So we went in on an unplanned basis and had to do a certain level of workovers and change outs. When you combine that with a relatively tight market from a workover crew perspective and the fact that we take safety extremely seriously, We did not go out and pick up crews that we didn't feel were going to fit our operational model from a safety and performance perspective. And that, you know, that realized a little bit more downtime than we would have normally expected in any quarter. The nice thing about that is the vast majority of that is taken care of. So we would anticipate industry-leading performance from our ESPs going forward as it's been for the last several years.

Got it. And just to kind of follow up quickly on that, it was more a pull forward of work over activity in that kind of plan bucket versus kind of an increase. That's why the LOE budget was able to stay constant. Is that correct?

That is correct. Yep.

Okay. And then just kind of one last quick one for me and kind of delving into the Delaware a little bit more. I don't think there was any completions on legacy Primex assets this quarter, but can you remind us kind of when that first batch of Calendrilled and completed wells will come online and kind of anything so far you continue to see from those those wells on those assets?

Sure, we've got a handful of wells that came online earlier and they're probably 150 days in. The Kesey-Campbell wells are the ones that stick out at the forefront and that's a combined 11 well system and And they're performing tremendously. We've hit two different benches in there, so kind of the traditional Wolf Camp A, Wolf Camp Bs. Very appropriate well spacing. We built predictive models based on our subsurface analysis, both from a geologic perspective, from the fluid systems that we have in place, and then, of course, all the petrophysical properties that roll in. And our predictive models have been outperformed by about 5 or 10% so far year to date. And again, these aren't wells that are 30 days old. They're in the 150-day range. We're continuing to do a lot of work out in the Delaware Basin South. And as I mentioned before, I think in the first quarter, I'm very excited about this acquisition. The rock quality is terrific. The prior operator did a great job in getting this asset up and running. and we anticipate continued terrific performance going forward.

Got it. Good to hear. I appreciate the time. Thanks. And ladies and gentlemen, a quick reminder, questions or comments, simply press star 1. We go next now to Fernando Zavala at Pickering Partners.

Hi, guys. Good morning. My question is around the Eagleford activity. I'd assume that you're looking to add back an Eagleford rig next year, and if so, How confident are you in the ability to get the rig you need? And how do you think about managing the longer planning cycles to keep activity levels consistent?

Sure, those are great questions. And yes, you're 100% correct. We will be bringing an Eagleford rig back in. We're literally getting ready to lay that rig down at TD, the last well on the pad. And so we'll be dropping that. We'll be picking up another rig ostensibly on the January 1st timeframe. And we'll be able to go and get the majority of year of drilling in 2023 done. The nice thing about what Callen has done in the past and continues to do is we have long-term relationships with all of our vendors. And even if it's a new vendor for us, we establish those well in advance. We put a drilling and completion program together, and we stay very consistent and committed. And Joe had mentioned this about some of the items that he discussed earlier. This allows us to have a very strong planning relationship with everything from pipe to our completion crews, to our sand delivery, our chemical programs. And it's very much appreciated from the vendor community and our partners So while there's always opportunities to have long-term discussions with new partners, we've been very satisfied with the folks that we have. And so we anticipate being able to move from our five-rig program back up to a seven-rig program and have the right pressure pumping services and rigs.

Got it. Thanks. That's all for me. Thanks for that. And gentlemen, it appears we have no further questions this morning.

Mr. Gatto, I'll hand things back to you for any closing comments.

Thanks, Beau. Appreciate everyone who joined the call today. In the interest, obviously, any follow-up questions, please reach out to Kevin and we'll get those answered. Otherwise, we'll look forward to talking again after the third quarter. Thanks.

Thank you. And again, ladies and gentlemen, I will conclude this morning's Cal and Petroleum second quarter 2022 earnings conference calls. Thank you all so much for joining us and wish you all a great day. Goodbye.