Callon Petroleum Company (NYSE:CPE) Q3 2023 Earnings Call Transcript

Callon Petroleum Company (NYSE:CPE) Q3 2023 Earnings Call Transcript November 2, 2023

Operator: Ladies and gentlemen, thank you for standing by. Welcome to Callon Petroleum’s Third Quarter Earnings Conference Call. [Operator Instructions] Just as a reminder, today’s conference call is being recorded. [Operator Instructions] I would now like to turn the call over to Callon’s CFO, Kevin Haggard. Please go ahead, sir.

Kevin Haggard: Thanks, operator, and good morning, everyone. Apologies. We had a little hiccup with the link to the webcast. I think we’re now all in, and there will be a recording afterwards. So we appreciate your interest in Callon. With me today are our CEO, Joe Gatto; and our COO, Russell Parker. We will happily take your questions at the end of our prepared remarks. We will reference our third quarter earnings release and supplemental slides, which are available on our website under the Investors tab. Today’s call will also include forward-looking statements that refer to estimates and plans. Actual results could differ materially due to risk factors noted in our presentation and SEC filings. We will also refer to some non-GAAP financial measures, which we believe help facilitate comparisons across periods and with our peers.

For any non-GAAP measures referenced, we provide a reconciliation to the nearest corresponding GAAP measure in the appendix to our slide deck and our earnings press release, both of which are available on our website. With that, I will now turn the call over to Joe.

Joe Gatto: Thank you, Kevin. Good morning, everyone. Cowen posted solid results for the third quarter, marking our 14th consecutive quarter of adjusted free cash flow generation, cash flow that we are using to reduce debt and repurchase our shares. Our corporate priorities are clear. We are focused on maximizing free cash flow, aggressively driving down our cost structure, reducing absolute debt and returning cash to owners through our share buyback program. I’ll divide today’s call into 3 segments. First, I’ll summarize third quarter financial and operating results. Overall, it was a good quarter with total production and key operating costs in line with expectations and capital investments below guidance. However, we did experience some headwinds related to our near-term oil production, which I will address shortly.

Second, I’ll cover our unrelenting focus on safely driving cost out of the system and creating sustainable operational efficiencies. Our focus on financial and operational cost controls is producing impressive gains, and we’ll pay increasing dividends into 2024 in terms of both free cash flow generation and lower breakeven prices for our Permian inventory. Next, I want to spend a bit of time on the sustainable benefits of our life of field co-development model. This is an ongoing and proven development process that maximizes the long-term value of inventory, where real-time learnings are then applied to future capital investments. We continue to see well productivity at Callon as moving counter to industry trends. However, we recognize that we need to continue to optimize that model over time with new information in order to properly balance near-term returns with longer-term opportunities.

Lastly, I will conclude with some early thoughts on 2024. Our recent efficiency gains in both drilling and completions are expected to be sustainable and will allow us to maximize value in 2024 through the enhancement of 2 key financial metrics, capital efficiency and free cash flow conversion of EBITDA. Let’s get started with third quarter results. For the third quarter, total production averaged 102,000 BOE per day. Oil sales averaged about 58,000 barrels per day. The shortfall in oil volumes is related to 2 key factors: first, the extreme temperatures and related power and midstream issues we experienced in July, which we discussed on the Q2 call, continued into August and September in the Delaware Basin, especially in our oil areas like Delaware East.

Power outages impacted our electrical submersible pump program and reduced expected order volumes due to downtime days as well as the time to ramp the ESPs back to normal operating levels. The second factor is related to oil production from recent multi-zone projects in the Delaware West, our most gas-weighted area. About 1/2 of our third quarter turn in lines or 15 of the 33 were in Delaware West. While total production on a BOE basis from recent completions was relatively in line with expectations, gas-to-oil ratios were much higher than expected. The commodity mix from these wells will also have an impact on our fourth quarter oil volumes. As an additional note, we recently accelerated a change in our Delaware Basin artificial lift program that was previously slated to start in 2024 to improve uptime performance.

This program will incorporate an increasing proportion of gas lift installs relative to ESPs over time to reduce production downtime from power and weather events, lower workover expense and enhanced longer-term resource recovery. In the fourth quarter, we do see some negative impact to production as compression-related equipment is procured and installed in areas where nearby gas lift installations don’t fully exist. With the program up and running this quarter and firmly incorporated into our planning process, we don’t expect to see this timing issue going forward. Overall, we expect fourth quarter oil production in the range of 56,000 to 59,000 barrels per day, with total production in the range of 100 to 103 BOE per day, comprised of approximately 79% liquids.

As part of our fourth quarter activity, we expect to turn 14 gross wells in line in the fourth quarter in our oilier areas, the Delaware East and Midland Basin, which will benefit our 2024 mix. Our forecasted capital investments for both full year and fourth quarter 2023 remain unchanged, despite an increase in drilling and completion activity driven by improving cycle times that I will hit upon in a minute. This clearly demonstrates the cost efficiencies we are realizing today. The corollary to the cost and capital efficiencies we are experiencing is that we are improving our rate of conversion of EBITDAX to adjusted free cash flow. In today’s deck, we show how this conversion has increased throughout the year. A few additional points to highlight.

G&A costs are now lower as a result of focusing the business solely on the Permian and streamlining our organizational structure. We are creating sustainable efficiencies across the business that will lead to improved results in future periods. We generated nearly $50 million in adjusted free cash flow this quarter. This gave us the flexibility to kick off our share repurchase program and opportunistically increase working interest in upcoming projects through several land initiatives. We are laser-focused on reducing absolute debt and strengthening our capital structure. At quarter end, total long-term debt was approximately $1.9 billion, down more than $300 million from the period — prior period. Our outlook for higher free cash flows in the fourth quarter will allow us to keep on pace with reducing debt and buying back additional stock through year-end.

We have benefited from recent acquisitions and are now a Permian-focused oil and gas company with scale. We added quality assets in the Permian and extended our runway of high-return long-lateral development locations. In terms of our recent Delaware acquisition, our first 5-well project is currently coming online, and we are encouraged by early time oil production rates and wellhead pressures. We will keep you updated on progress here. We have materially strengthened our balance sheet and implemented a cash return program for shareholders. We plan to use up to 40% of our adjusted free cash flow to repurchase shares in the fourth quarter. While we are focused on reducing absolute debt, we see buying back our shares at today’s valuation as a very attractive use of cash flow.

We have strengthened our leadership team and redesigned our operating teams. Our new COO, Russell Parker, is leaving no stone unturned as he assesses our business and benchmark our performance against industry. He is making an impact, applying has years of experience to safely enhance operational practices, lower costs and create sustainable synergies to drive future performance. I know it is eager to share some additional highlights and talk about his team some more during our Q&A. But as a start, early operational wins include: one, we are materially reducing days versus depth through the elimination of casing strings, which decreases cycle times and enhances project returns. Each of our developments going forward will have a fit-for-purpose casing design, tailored to maximize value.

We’ve provided a couple of examples of this on Page 7 of the presentation materials. Reductions in cost per lateral foot are being realized through the optimization of drill bits and the ability to drill long laterals. On the completion side, we’ve increased completed lateral feet per day by as much as 20%, and we’re seeing repeatable efficiencies and pumping rates and hours pumped per day. The combined impact of these realized improvements are driving overall performance into year-end. We now anticipate to complete approximately 50,000 more lateral feet and commenced drilling an incremental 5 wells relative to our midyear forecast. This additional activity will benefit 2024 production, all while staying within our existing budget. These accomplishments have been realized in a very short period of time after we’ve revamped our operations in recent months.

This has demanded a tremendous amount of effort, and I want to thank the entire organization for making this possible. Let me shift gears and discuss our life of field co-development model. This thoughtful approach to development has been constantly evolving over the past 5 years. It differentiates us from our peers and our well productivity is performing counter to industry. We have learned a great deal about interactions between our codeveloped zones and associated well spacing and placement. This continuous learning provides the foundation for ongoing tailoring of projects to maximize returns. For example, our recent co-development in our Delaware South area demonstrated that our deepest target zone could be developed separately over time, allowing us to reduce overall project sizes and cycle times as well as reduced facility investments.

This continuous improvement is critical to maximizing our NPV proposition. Let me wrap up today’s call by providing some of our early thoughts around 2024. Consistent with prior practice, look for formal guidance from us early next year. First, we will continue to focus on maximizing free cash flow. Our top cash flow priorities are to fund our high-value developments, reduce debt and repurchase shares. We believe that allocating capital appropriately across these buckets will drive improvements in our cost of capital. We will continue to be very disciplined with our capital investments. With recent efficiency gains in drilling, completion and facilities, we expect to do more with less in 2024 and forecast average DC&F cost per well to be down over 15% versus 2023.

In addition, ongoing high-grading of investments within our co-development model will allow us to target lower investment rates to enhance free cash flow. Our production trajectory in ‘24 will benefit from pulling forward more drilling and completion activity than initially planned as we are improving cycle times in the second half of this year as well as the return of a second completion crew early in the next year. In terms of our early thoughts on 2024 production outlook, increases in activity to drive top line growth will be secondary to drive an improved capital efficiency, as we prioritize debt reduction and share repurchases. I’ll also point out that we expect our oil mix to improve over the coming quarters as we focus on high-return oil areas in the Delaware and Midland Basins.

We will remain nimble as our 2024 program progresses, and we’ll evaluate increases in our activity to the extent we achieve DC&F reductions in excess of our original plan, similar to what we’ve done in the second half of this year. We appreciate your investment in our company, and we look forward to taking your questions. Operator?

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Q&A Session

Operator: [Operator Instructions] Our first question comes from Neal Dingmann with Truist Securities.

Neal Dingmann: Joe, my first question, maybe kind of get right to it, maybe for Russell. Just you talked about some 15% reductions and just really highlighting completion drilling, there’s just a lot of things. I’d love to hear straight from Russell just when he looks at ‘24, where he thinks a lot of these savings potentially could come from?

Russell Parker: And I appreciate the question. And actually, we already started to see some of this come to fruition as we modify our casing strength. It’s going to be a different mix of savings across the portfolio, probably the way it will shake out, we take 15% plus on average per well DC&F. And the way that breaks out, it’s about a 15% on average savings on the drilling side, about a 5% average on the completion side and about 50% savings on facilities. And really, what that all boils down as a little bit of cost of services. There is a little bit of that single digits, 3% to 5%, depending upon which input you’re talking about. But really, the big change is coming from shifting from kind of a standard mindset, a standard way of doing things to a fit for purpose.

So we’re looking at each individual location and looking at where we can reduce casing streams, reduce hole sizes, run our bit program and our bit life much longer than what we have been potentially drilling with conventional tools instead of rotary steerables. And in some places, we actually save money doing that and we can keep the tools in the whole longer. And then on the facility — on the completion side, a lot of that savings is coming from sand. That’s not unique to Callon. Now some of the logistics is — are unique to Callon. That’s the bulk of where we see that savings coming from. We think we could probably stretch a little bit further on the completion side even as we go into 2024, and that will be our goal. As we look to increase our pump rates, potentially complete 2 pads at the same time.

We’re throwing a lot of ideas out there. We’re going to let the team really stretch their legs, really kind of push the envelope of engineering excellence to help reduce those costs. And then on the facility side, it’s really, once again, it’s fit for purpose. So we’ve spent a good deal of money over the years with our life of field model, building up an infrastructure of equipment and flow lines and tank batteries, what have you. We’re pulling out of the point where we can actually, one, start harvesting less of that equipment, but two, also look at maybe building our on-pad facilities a little bit differently, using more [bulk lines] and trunk lines, integrating gas lift systems that while it takes a little time to get together, actually, over time, will save us money.

So it’s a large combination of the projects. If you had about 4 hours, I’d love to take you through all of it, but we don’t have that kind of time today, but — and a whole lot of folks working on it. But basically, that fit-for-purpose design versus just taking a standard.

Neal Dingmann: Great details, Russ. And then definitely will take you up on that and love your more sometime offline. And then Joe, my second question is just on capital allocation. I’m just wondering what would be the primary drivers or what is the primary drivers would you and Kevin decide that now on a go forward lean into the buybacks versus allocate a bit more on the growth side?

Joe Gatto: Yes. Look, we’ve talked about the 3 buckets that we have in terms of adding value, clearly investing in the asset base in a disciplined way, the first stop. But we are very focused on debt reduction, we put goals out there. We’re serious about getting to them and also following through on our share repurchase program. So we have a lot of efficiencies that Russell’s talked about here, not only from a cost perspective, but also from cycle times, but we are going to be cognizant. We don’t want those efficiencies to drag us to higher reinvestment rates. So by focusing on high-grading our opportunity set going forward, we can find a nice balance in between there to deliver high-return projects, keep our reinvestment rates in check, have more free cash flow to deliver to incremental debt reduction and share repurchases.

Operator: Our next question comes from Zach Parham with JPMorgan.

Zach Parham: First, could you give us a little more color on what you’re seeing from those gassier wells in the Delaware West area? Maybe add some thoughts on how you think about future development in that area? Do these well results change kind of how you think about your inventory that you have remaining over there?

Russell Parker: Sure. I’ll take that question. The Delaware West particularly has been our gassiest part of our portfolio. That’s nothing new. That’s no real surprise. The good news is we have a lot of places to invest money going forward too. So as Joe has alluded to, we’re going to look at, one, how we’re designing, spacing, completing, landing and developing the property with a lower cost structure going forward in order to continue to maximize value. And then also in the near term, our other assets, the East and the Midland Basin, obviously, will help pull up that oil mix as we’re going forward.

Joe Gatto: And I think specifically on the Delaware West project, we said we had a lot higher GOR ratios than we expected. I think some of that is attributed to — look, it’s an active area around us over time. So some of that activity most likely led to some depletion effects in that area. But there are lessons learned from that project going forward. We still think Delaware West is an attractive area. But with co-developments that we’ve got to evolve over time. So we’re probably putting a few more less — or sorry, a few less sticks in the deeper zones in the Wolfcamp B and C would be one thing that we take away from that. But overall, Delaware Western area will be back to over time. Part of our program with scale development is to rotate our projects, because we’re not overtaxing infrastructure, leverage the infrastructure we have in place, and there’s very similar returns across the portfolio for different reasons.

But hopefully, that gives you a sense of where we’re heading from Delaware West, but there’s certainly some takeaways there that we’re incorporating in our designs going forward.

Zach Parham: Got it. And then maybe just following up on Neal’s question. You’ve talked a lot about cost reductions on DCF. Can you give us any sense of what 2024 CapEx might look like if costs play out the way that you think they will? Should we be thinking about a similar number of turn in lines next year and CapEx is just simply 15% lower year-over-year? Or is it more complicated than that?

Joe Gatto: Yes, Zach, we wanted to give you the building blocks here, certainly around DCF average well costs. But I said the cycle time element is really critical here in terms of how we plan out for next year. Obviously, we have a good pathway into the beginning of the year with getting a jump start on activity into the first quarter from the savings we’ve had in ‘23. But yes, it is more complicated than just taking down 15%. We do want to be mindful, as I said, around reinvestment rates. We could — with everything that we’ve shown in recent months on the drilling side and completion side, that allows us to go faster in general. But we’re going to moderate our investments appropriately to balance all of our free cash flow objectives.

So we’ll be able to fill in the holes here in the next couple of months, but certainly, I wanted to give you some of the building blocks going into next year, again, being lower DC&F per well, improved cycle times and a good trajectory going into the beginning of Q4 with some oil-weighted projects.

Operator: Our next question comes from Oliver Huang with TPH.

Oliver Huang: Joe, Kevin and Russell. Certainly, good to see the incremental detail around a lot of the cost initiatives that you all been working around and I mean, 15% is certainly a meaningful number. But maybe just kind of a follow-up to Neal’s earlier question. How immediate are these savings? Is that something that we’d expect to start in full force at the beginning of 2024? I know you all have already made headway on that to date. Or is that something that we should expect to kind of layer in a bit more gradually?

Russell Parker: It’s already happening now. And I’d say, as we get into Q1, we should be in the neighborhood of already realizing that, hopefully, definitely averaging us through the year, maybe even beating it as the year goes on, depending — of course, depends on where commodity prices and service rates are. But to that point, and Joe mentioned it earlier, we’ve got extra projects that we’re actually drilling and completing this year, about 50,000 extra lateral feet, another handful of wells that we’re going to spud in ‘23 that were not in our anticipated budget at midyear. These projects are going to add production in Q4. So obviously, Q1, you won’t see them in Q4, adding production next year. But we’re able to do that and still stay within our original budget.