Callon Petroleum Company (NYSE:CPE) Q2 2022 Earnings Conference Call August 4, 2022 9:00 AM ET
Company Participants
Kevin Smith – Director, Investor Relations
Joe Gatto – President & Chief Executive Officer
Jeff Balmer – Senior Vice President & Chief Operating Officer
Kevin Haggard – Senior Vice President & Chief Financial Officer
Conference Call Participants
Bertrand Donnes – Truist Securities
Derrick Whitfield – Stifel
Davis Petros – RBC Capital Markets
Fernando Zavala – Pickering Partners
Operator
Ladies and gentlemen, thank you for standing by and welcome to the Callon 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. [Operator Instructions] 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.
Kevin Smith
Thank you, Bill. Good morning, and 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 Balmer, SVP and Chief Operating Officer; and Kevin Haggard, SVP and Chief Financial Officer.
During our prepared remarks, we made reference to 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 Release under the news headings, both of which are located within the Investors section of our website at www.callon.com.
Before we begin, I would like to remind everyone to review our cautionary statements, disclaimers, and important disclosures included on slide 2 of the presentation. We will make some forward-looking statements during today’s call that refer to estimates and plans. Actual results could differ materially due to the factors noted on these slides and in our periodic SEC filings. 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 referenced, we provide a reconciliation to the nearest corresponding GAAP measure. You may find these reconciliations in the appendix to the earnings presentation slides and in our earnings press release, both of which are available on our website. Following our prepared remarks, we’ll open up the call for Q&A.
And with that, I’d like to turn the call over to Joe Gatto. Joe?
Joe Gatto
Thank you, 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 I walk through introductory remarks.
I’ll start off by discussing our accomplishments for the first half of the year. As we enter 2022, we outlined 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 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 the 2024 maturity and removed the second lien notes from the company’s capital structure.
he 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 D&C 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 and completions have increased by approximately 160% on average across all basins.
I also want to highlight the substantial well productivity improvements being delivered with our Delaware Basin development program. Since initiating larger scale program development over the last couple of 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 well performance in 2022 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 note 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 that Callon had entered into multiple natural gas transportation agreements for firm transportation to the Gulf Coast for approximately 75,000 MMBtu 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 ESG. We’re steadily executing on our accelerated emissions reduction goals. We are well on our way of achieving our two-year plan to replace all of our pneumatic devices with zero emission or nobly devices, which will significantly reduce our overall emissions, particularly methane. And consistent with our track record of acquiring improving assets, we’ve been investing this year in facility upgrades in our Delaware South operations to bring them in line with Callon 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 DUC backlog at an increased pace early in the quarter.
Headline production came in at the midpoint of our guidance, a 101,000 barrels of oil equivalent per day carrying oil cut 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 onetime items. First, we set up our workover activity, as we accelerated the implementation of Callon’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 is approximately twice the amount in the first quarter, and pull 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 have seen an average sustained uplift of over 25% 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 well performance, particularly in the Delaware Basin, we are raising the bottom end of our annual production guidance from 101,000 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 in the gathering contract conversion.
Our average well net price 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 an unhedged basis.
As our hedge portfolio steps down as a 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 ESG initiatives I discussed our guidance range for absolute LOE spend has remained unchanged.
GP&T was revised of $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. So, in terms of 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 Permian-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 a 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 million 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.
It was underappreciated by the market at times however by the implications of our life development philosophy which focus on scale codevelopment to optimize the value of a large part of the reservoir system. This 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 maintained a more balanced inventory opportunity set for future development.
On page 11 of the presentation, we referenced a third-party independent analysis that illustrate that concept. The analysis created shaft or shaftly [ph] additive explanation values. They’re used to explain the relative contributions of a group of factors to the outcome of a predictive model. In this case chat 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 shaft value quantifies the marginal impact of rock quality on well performance. These geologic shaft values were aggregated to create a distribution that characterizes a company’s remaining inventory. The meaning 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 of years.
On the contrary Callon had one of the highest positive values, reflecting Callon’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 overtime 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.
Jeff Balmer
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 Eagle Ford, we really didn’t hit our strides 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 frac system. Besides the cost savings due to 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 the arguably maintaining the fracture stage spacing to approximately 200 feet.
On the drilling side, we’ve also seen operational improvements. Through the use of Rotary Steering Tools, Multi-Bowl Wellhead design and Improved Bit and BHA design 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 Eagle Ford. After not placing any Eagle Ford wells on production during the first quarter, we placed 15 wells from three pads online as part of our 26-well, 2022 Eagle Ford 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 multibench development and our life-of-field 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 barrel wells were completed and targeting multibench development and the Wolfcamp A, Wolfcamp 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 it will 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 multibench development in Wolfcamp A and B formations.
In the pad 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 rates 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 will drop our Eagle Ford rig 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 once again like to acknowledge Callon’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 DUC 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.
Kevin Haggard
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 of 1 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 50% increase in wellhead revenue to $82.98 per barrel of oil equivalent. After factoring in hedging and operating costs, Callon reported its eighth consecutive increase in operating margin to $57.58 a BOE, which was a 16% increase over Q1.
Our top-tier operating margins helped us realize adjusted EBITDA of $418 million in the second quarter, a 6% sequential increase over Q1. During the second quarter, Callon 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 at 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 maturity profile by two years. Our next term debt maturity is not until 2025 and has less than $200 million outstanding on. This is an amount we can easily fund with free cash flow in the coming quarters.
And as part of the financing, all three credit rating agencies reviewed the Callon 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% hedged 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 had 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 you can see plenty of feedback about how Callon’s election to useful cost accounting makes it difficult to compare the company’s financials with our peers. As background, the full cost of 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 Callon work from — 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.
Joe Gatto
Great. Thanks, Kevin. Before turning to questions, I’ll leave you with a few key takeaways. We’re driving improved capital efficiencies 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 sustained inventory quality for future drilling as we have steered away from just drilling our best wells at the expense of degrading offsetting locations in adjacent zones.
Our balance sheet and overall financial position is solid and will continue to improve at a fast pace in the 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.
Callon 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 $1 billion below the June 30 PV-10 of just our crude developed producing reserves using last month — 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 model supported by quality assets and people will be rewarded.
Bo, you can open up the line for Q&A.
Question-and-Answer Session
Operator
Thank you, Mr. Gatto. [Operator Instructions] And gentlemen, our first question today will come from Bertrand Donnes of Truist Securities.
Bertrand Donnes
Good morning. You talked 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 shareholders?
Kevin Haggard
Yes. 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 $1.5 billion 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 then swings in commodity prices. So for us it’s not as much a mid-cycle price. It allows us to go low and it allows us to go high. And we have a balance sheet that we feel gets us through the different commodity price environments.
Bertrand Donnes
So would you characterize it you think you want both or just one before you kind of ramp?
Kevin Haggard
I think we’ve been pretty clear that these are both targets we need to hit before the shareholder returns enter the discussion.
Bertrand Donnes
That’s perfect. And then just shifting gears. Last quarter you kind of talked about any additional M&A and mentioned that at 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 that’s changed or whether you’ve had any kind of negotiations?
Joe Gatto
Yes. I think overall, we know that there’s a fair amount of assets that are hitting the market, what we gather from inbounds. But frankly we’re just not very active in that realm right now.
Bertrand Donnes
Thanks.
Operator
Thank you. We go next now to Derrick Whitfield at Stifel.
Derrick Whitfield
Thanks. Good morning, all and congrats on your quarter and operational progress.
Joe Gatto
Thanks, Derrick.
Derrick Whitfield
With my first question I wanted to focus on your capital plan and your progress in continuing to achieve operational efficiencies. Referencing Slide 8, 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 Callon on both drilling and profit placement per day?
Jeff Balmer
Yes. I think that there’s kind of two pieces to that answer. One is 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 even though some challenging years I’d say 2020 where crews and commodity prices, et cetera were difficult to go together, you still see some significant improvements even on a year-by-year basis.
And so we remained 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 do – we’re going to do the exact same thing.
So we’ll bake in some operational improvements some of which will know ahead 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.
Derrick Whitfield
Terrific. And I have just a follow-up, I wanted to focus on Slide 11. I think it’s certainly a very interesting and positive visualization for Callon. Specifically, I want to see if you can speak to what’s driving improving rock quality for Callon. It seems to somewhat defy how I would normally think about development trends which is developing your best first? Thanks.
Joe Gatto
Yes. I think that goes really to the core of what we do in terms of life of development. We’ve been consistent with this through the last few years of going to scale co-development of zones. And there are strategies that are deployed to 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. 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 levels. So with a more balanced approach that means that we have those — a more balanced mix of inventory going forward versus if we just focused on our best stuff and then you’re left with the graded inventory going forward.
So that’s really the essence of — what we’ve been talking about has been something that we’ve done even through 2020 and 2021. So that was 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 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.
Derrick Whitfield
That’s great. That’s makes sense. Look forward to seeing the report.
Joe Gatto
Great.
Operator
Thank you. We go next now to Davis Petros with RBC Capital Markets.
Davis Petros
Good morning all. Thanks for taking my questions. First one and you touched on it in your prepared remarks in the release, but can you just expand a little bit more on kind of the power disruptions in the Delaware causing that increased well failures and specifically kind of where you’re at in the process of addressing and accelerating those artificial lift upgrades?
Jeff Balmer
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, any time 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.
And so 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 hitten sulfide. And while we were out there, we analyzed all the wells that were within that production system and determine whether or not the ESPs were rightsized or a different change in lieu of 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 did feel we’re going to fit our operational model from a safety and performance perspective.
And that realized a little bit more downtime than we would have normally expected it 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.
Davis Petros
Got it. And just to kind of follow-up quickly on that. It was more a pull forward of workover activity in that planned bucket versus an increase. That’s why the LOE, but it was the state cost is that correct?
Jeff Balmer
That is correct. Yes.
Davis Petros
Okay. And then just one last quick one for me and delving into the Delaware a little bit more. I don’t think there was any completions on legacy Primexx assets this quarter, but can you remind us when that first batch of Callon drilled and completed wells that come online and anything so far you continue to see from those wells on those assets?
Jeff Balmer
Sure. We’ve had a handful of wells that came online earlier and they’re probably 150 days in. The Campbell [ph] wells are the ones that stick out at the forefront and that’s a combined 11-well system and they’re performing tremendously. We’ve hit two different benches in there. So the traditional Wolfcamp A, Wolfcamp 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. Our prior — the prior operator did a great job in getting this asset up and running and we anticipate continued terrific performance going forward.
Davis Petros
Got it. Good to hear. Appreciate your time.
Jeff Balmer
Thanks.
Operator
[Operator Instructions] We go next now to Fernando Zavala at Pickering Partners.
Fernando Zavala
Hi, guys. good morning. My question is around the Eagle Ford activity. So I’d assume, that you’re looking to add back an Eagle Ford 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?
Jeff Balmer
Sure. Those are great questions. And yes, you’re 100% correct. We will be bringing an Eagle Ford 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, time frame and we’ll be able to go and get the majority of the year of drilling in 2023.
The nice thing about what Callon 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 established 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 and relationship, with everything from type, 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.
Fernando Zavala
Got. Thanks. That’s all for me. Thanks for that.
Operator
And gentlemen, it appears we have no further questions this morning. Mr. Gatto, I’ll hand things back to you for any closing comments.
Joe Gatto
Thanks, Bo. Appreciate everyone, joining the call today. In the interest, obviously, any follow-up questions please reach out to Kevin, and we’ll get those answered. Otherwise, we look forward to talking to you again after the third quarter. Thanks.
Operator
Thank you. Again, ladies and gentlemen [indiscernible] this morning’s Callon Petroleum Second Quarter 2022 Earnings Conference Call. We’d like to thank you all so much for joining us and wish you all a great day. Goodbye.
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