Callon Petroleum Co (CPE) 2022 Q1 法說會逐字稿

Ladies and gentlemen, thank you for standing by, and welcome to the Callon Petroleum First Quarter 2022 Earnings Conference Call. After the speaker's presentation, there will be a question-and-answer session. (Operator Instructions) Please be advised that today's conference is being recorded. (Operator Instructions) I would now like to hand the conference over to your speaker today, Kevin Smith, Director of Investor Relations. Please go ahead, sir.

Thank you, Julian. 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, Chief Financial Officer.

During our prepared remarks, we may reference the earnings results presentation and our first quarter earnings press release, both of which are available on our website. So I encourage everyone to download those 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 heading, 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 findings.

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 slides and in our earnings press release, both of which are available on our website. Following our prepared remarks, we will open the call for Q&A.

And with that, I'd like to turn the call over to Joe Gatto. Joe?

Thank you, Kevin, and good morning to everyone on the call. As always, I encourage you to review the earnings presentation on our website as background for our commentary. I will start with a review of our first quarter results.

We got off to a great start to the year with operating and financial results exceeding both guidance and consensus expectations. For the quarter, total production came in above the top end of guidance at over 102,000 barrels of oil equivalent per day, carrying oil come at 63% and a total liquids content of 82%.

Part of the outperformance was driven by well productivity from the initial round of larger scale projects in our new Delaware South area that was better than forecast in both the Wolfcamp A and Wolfcamp B formations. Just as impactful, we made meaningful progress lowering operating costs despite inflationary pressures in the field. We're able to reduce absolute lease operating costs by $6.2 million and gathering and transportation expense by $1.3 million, both on a sequential basis.

As Jeff will discuss in his prepared remarks, we are taking additional steps to further decrease operating costs over the course of the year. Strong oil and natural gas price realizations experienced during the quarter, combined with structure improvements, resulted in the 7th consecutive increase in quarterly operating margins, driving a leading operating margin exceeding $58 per Boe in the first quarter.

Switching to the capital program. Our disciplined reinvestment rate of just over 45% drove another quarterly increase in free cash flow while also setting us up for efficient production growth in the second half of the year.

During the quarter, we increased our drill but uncompleted backlog by 15 to a total of 42 wells. With our DUC backlog at a more normalized level, we are now positioned to start increasing our completion pace. This activity will drive a projected 10% increase in daily oil production by the fourth quarter, as previously outlined in our 2022 operational plan in February.

Callon's operational capital spending for the first quarter was $157 million, below our guidance of between $175 million and $185 million. These savings were driven by a deferral of a portion of our Permian infrastructure spend, which we now expect to occur in the second quarter in addition to realized capital efficiencies.

As we have all heard in the starting season from energy companies across the value chain, inflationary cost pressures have continued to build in the labor, materials and equipment markets. As a reminder, we factored in an average price escalator of 10% for our 2022 capital budget at the beginning of the year to account for inflation estimates at that time. This outlook also gave consideration to capital efficiencies from longer laterals and expected integration synergies related to Delaware South.

Given the rapid increase in oil prices and resulting market tightness, we have been proactive in recent months entering into new or modified agreements that provide a certainty of key services to ensure execution of our program with top-tier service and materials providers. I'm pleased to say that we have secured all of our needs for completion crews, drilling rigs, sand and steel casing for 2022 and for some of these categories into 2023.

In addition to reliable access, these agreements come with a varying level of price certainty. For example, the agreement for one of our completion crews provides a full year of firm pricing in 2022. However, in other agreements, we are exposed to price reopening discussions over the course of the year, which is typical for these types of industry agreements.

Given the rapidly developing dynamics of the service market and recent industry data points, we are evaluating several scenarios for incremental headline inflation impacts on our capital program for 2022. Depending on the outcomes of upcoming pricing discussions and the overall pace of oil [and fuel] price increases as the year continues to unfold, some scenario shows [service] inflation impacts moving into the mid- to upper single digits.

However, as evidenced by our first quarter capital spend in a rising price environment, we will continue to drive initiatives that increase our operating efficiency to help mitigate potential drilling and completion-related price increases in the coming quarters. Importantly, our operational program remains intact and remain confident in achieving our targeted leverage metric of between 1 to 1.25x EBITDA by year-end 2022 if price is well below current strip. This outlook covers a wide range of outcomes from our vendor pricing discussions and benefits from both having 4 months of the year behind us and the cost certainty embedded in some of our existing service agreements extending into year-end.

We also remain focused on lease operating expense to preserve our differentiated cash margins. Good progress has been made to offset inflationary cost pressures with first quarter results serving as a good example. We delivered a sequential decrease in absolute LOE spend in large part from synergies we have realized in the Delaware South area.

Lastly, thanks to the strong start to the year, we continue to pay down debt and strengthen our balance sheet at a faster-than-anticipated pace -- have been generating over $180 million in free cash flow in the first quarter, which was our eighth consecutive quarter of generating free cash flow and third consecutive quarterly increase. We are on pace to achieve our goals of exiting this year with a leverage ratio nearing 1x EBITDA and absolute debt approaching $2 billion.

As we turn to the second quarter outlook, we recently accelerated the timing of a portion of our 2022 Eagle Ford program to navigate potential Permian bottlenecks that we saw earlier in the year and mitigate some pricing pressures. Looking at our second quarter production profile, we expect volumes to be relatively flat with the first quarter of 2022, while momentum builds from increased completion activity into the second half of the year.

The number of oils drilled will be relatively similar in the second quarter versus the first quarter, but [our place on] production wells are expected to rebound to over 30 net wells. With a meaningful uptick in activity, our operational capital spending is forecast to be between $225 million and $240 million on an accrual basis, including a catch-up on some deferred spending from the first quarter. I will now turn it over to Jeff to discuss our operations.

Thank you, Joe, and good morning, everyone. As Joe mentioned, we had a great start to the year. Operationally, we exceeded our production forecast as well results in the Delaware and Midland Basins (inaudible) our expectations. And despite the ongoing inflationary environment, we maintained discipline with our capital costs coming to below forecast.

Lastly, I'm proud to report that we are successfully implementing our strategy to reduce operating expenses on our Delaware South assets (inaudible) response to the increase in oil and natural gas prices. During the quarter, we elected to add a workover rig and increased the company's workover activities by approximately $3 million sequentially.

Workovers and recompletion activity are some of the highest rate of return projects in our portfolio with payback periods of less than 2 months. And during the 3-month period, we [elected] to increase the pace of installation of electric submersible pumps, or ESPs, and installing some of these ESPs after only 2 months of initial production versus the normal 4 months.

Specifically, at our (inaudible) wells, we realized average production increases of 40% within days of installing the downhole pumps. We remain extremely focused on the overall operating expenses in all of our areas. We've had an excellent start in 2022, and the (inaudible) of the inflationary pressures by increased operational efficiencies, such as improvements in overall artificial lift strategy, compression advancements and sourcing cheaper supplies like chemicals.

And I'm also very excited to mention that our efforts to reduce our methane intensity to remain on track as our program to change out pneumatics has had a great start. Now I'd like to provide you with an update on each of our operating areas. So starting with the Eagle Ford.

During the quarter, we drilled 9 wells on 3 pads as part of our ongoing 5-pad (inaudible) development program. We commenced completion operations on the first of these pads in early April and plan to complete the remaining pads in the second and third quarters. As we discussed last quarter, as part of this program, we will be drilling [completing] Austin Chalk test well, and we plan to complete this well in the third quarter.

Shifting to the Midland Basin, we continue to have success with our multi-bench development and our life of field development philosophy. One example of this are 2 (inaudible) pads that we placed on production in our side (inaudible) that we completed at year-end. The 9,500-foot lateral wells were completed, targeting multi-bench development in the Wolfcamp A and B, and lower Spraberry formations and had an average 30-day production rate of 1,150 Boe per day with 84% oil.

During the quarter, we had 2 rigs running in the basin and drilled 9 wells with completion operations commencing at the beginning of April. We plan (inaudible) drilling program on the Midland acreage through the second quarter and then drop down to one rig for the remainder of the year.

Moving to the Delaware. All of our completion activity in the first quarter was focused on our Delaware acreage. And during the quarter, we completed 16 wells and brought online 11. The [abandoned] wells were completed targeting multi-bench development in the Wolfcamp A and Wolfcamp B formations.

Two pads that I'd like to highlight are the 6-well Kesey Unit and the 5-well Campbell Unit (inaudible) Delaware South acreage. These 9,000-plus foot laterals achieved strong production results with the Kesey is generating a peak average 30-day rate of 1,312 Boe per day and the Campbell wells with an average 30-day rate of 1,199 Boe per day and around 80% oil.

By increasing the [pad] size from 2 to 3 wells to 5 and 6, respectively, we were able to realize cost benefits. Given the lower cost in the strong production profile, we expect these wells to pay (inaudible) 6 to 7 months for boosting our capacity and to generate free cash flow.

(inaudible) well results, we've made strides in lowering our operating costs on our Delaware South asset. During the quarter, we switched to service providers on items like chemicals to enter into more favorable pricing. This helped reduce our LOE per Boe on our Delaware South asset by 23% sequentially.

We've scheduled some facility upgrades for the asset later in the year, which should also provide the opportunity to increase efficiency rates and further lower our feature [costs]. Before turning the call over to Kevin, I'd like to discuss the current service price environment and the steps that we've taken into contract our service needs and mitigate price volatility. Over the last several quarters, we felt inflationary cost pressures on many different circumstances, such as the labor materials, like [fuel, steel], sand and also equipment.

Our multi-basin asset base provides flexibility as the service market is not [as side] in the Eagle Ford as it is in the Permian Basin, which provided us the opportunity to flex our program as we've done in the second quarter.

Additionally, we used our scale and steady development base to enter into service contracts that reduce price volatility and provide greater service assurance. We entered the year operating 7 rigs with staggered maturities locked in for most of 2022. Executing with our original plan, we'll be dropping one rig next month.

On the completion side, we're utilizing 2 crews. We entered into a long-term contract for one of the completion crews in the fourth quarter of 2021 that is renewable on an annual basis for 2 additional years with embedded performance incentives. We also restructured our locally sourced sand supply contract during the quarter to lock in our sand requirements for our 2 completion crew program toward the remainder of the year.

We've contracted steel facing to meet our drilling program needs for 2022. Therefore, we feel really good about the steps we've taken to provide service assurance while maintaining our focus on margin improvement.

And with that, I will now turn it over to Kevin to handle the financials.

Thank you, Jeff. It's a great way to start the year generating financial results like those we achieved this quarter. We increased our operating margin by 20% sequentially, and our adjusted EBITDA was up 16% sequentially.

The strong free cash flow generation in the quarter resulted in continued debt reduction. I am happy to be able to point out our LTM net debt-to-EBITDA metric now starts with a 1 handle at 1.97x. Now let's go through the details.

Our peer-leading operating margin once again increased, driven by a 23% increase in oil price realizations on a per unit of production basis. On the cost side, the actions that Jeff discussed helped lower lease operating expenses compared to last quarter. We also realized the total dollar increase in our gathering, processing and transportation cost.

However, both LOE and GP&T increased on a per unit basis due to the sequential reduction in production volumes. Our top-tier margins helped us generate an adjusted EBITDA of $394 million in the first quarter. The increase in adjusted EBITDA, combined with the reduction in interest expense and continued capital conservatism, drove a significant sequential increase in adjusted free cash flow.

During the first quarter, Callon generated adjusted free cash flow of approximately $183 million. This is a good place also to remind you that our 2022 oil hedges are more weighted to the first half of the year and in particular, the first quarter was our highest hedged quarter of the year.

Our near-term plan continues to be to use our free cash flow to pay down debt. During the quarter, we paid down our bank debt by approximately $73 million, exiting the quarter with just over $700 million drawn on the facility. When we look at the second quarter, using current strip prices, we would end Q2 with less than $600 million drawn on our credit facility, continuing the debt pay-down.

As part of our work to optimize the balance sheet and increase cash flow, we will look to retire some of our high-cost term debt this year. As mentioned on the last call, we expect to retire the 9% second lien notes when they are callable on October 1. We also have a small portion of 8.25% bonds that are callable at reasonable premiums as well. Thankfully, with the free cash flow we are anticipating generating this year, we have many options to further reduce our overall debt balance and continue our process of extending our maturities, while at the same time, lowering our weighted average interest rate.

We laid out one of these options on Page 10 of our first quarter earnings slide deck. Turning to hedging. Our hedging program for 2022 is essentially complete with approximately 45% of our oil production hedged for the balance of the year. As we look to 2023, we have positioned the portfolio with a good base layer of hedges. With strength in the oil and natural gas (inaudible) terms, we will look to opportunistically add 2023 hedges over the remainder of this year.

However, we will note as our leverage continues to decline and our balance sheet strengthens, we expect to hedge less volumes or said another way, a lower percentage of production that we have historically. Finally, I want to hit off the likely questions from our Q&A session regarding the timing of shareholder returns. At current commodity prices, we are targeting using free cash flow to repay debt until we achieve a net debt-to-EBITDA ratio of 1x and are below $2 billion in total debt. In addition, we would like the flexibility and time to do some balance sheet cleanup and optimization this year, including the second lien redemption I discussed earlier.

Before starting to return capital to shareholders, we want to make sure we have a balance sheet that could support a full range of commodity prices, including a mid-cycle oil price and a downside case with WTI as low as $40.

While we work to continue to achieve new leverage objectives, we will also be working internally to evaluate our financial capacity to offer sustainable shareholder returns. And as I mentioned on our last call, it is important for us to retain corporate flexibility to invest in our business. which ultimately allows us to deliver sustainable long-term returns to our shareholders through all phases of the commodity cycle.

And with that, I'm going to turn things back over to Joe before we move to Q&A.

Thanks, Ken. Just to wrap up, we entered the second quarter having consistently exceeded our commitments to leverage reduction and operational performance. Our LTM net debt-to-EBITDA ratio is now below 2x, and free cash flow generation has been repeatable and rising.

Importantly, Callon has one of the deepest inventory of top-tier projects amongst our peer group, putting us in an enviable position for a critical component of the free cash flow discussion, that being sustainability over time. This longer-term visibility will provide numerous capital allocation options for shareholder value, including further debt reduction, return of capital and reinvestment in the business.

Operator, you may now open the lines for Q&A.

(Operator Instructions) Our first question comes from Neal Dingmann from Truist Securities.

My first question is on operations. Joe, maybe for you, or Jeff. Just specifically, can you all talk a bit more on -- I really like to hear more on that build-out of the documentary in the new Delaware South acreage. I'm just really wondering around that what will this do to sort of future developments and results? I like that you all, unlike some others, are really building this out to a larger full-scale development. But then when I heard about the DUC inventory as well, curious to know what you think the upside will be around this?

So this is Joe. I'll start off, and if Jeff wants to chime in on the back end. But if you recall, we stepped into the position of historical operator was really doing 1, 2 well types of pads. That's not our philosophy, as you know, from a life of field development, co-development mindset.

So in order to create flexibility to move to larger projects, we had to build out a DUC inventory over the last couple of quarters. And by the first quarter, we started getting after it with 5-well pad and a 6-well pad. So we're sort of steady state now, but it was really a onetime event to get that area ready for the type of operational development that we've redeployed.

Yes. And just one other thing to add is we've got a nice [fulsome] development program throughout that acreage. So each of the different areas that we have taken over for putting some pads in across the entire Delaware South acreage, testing the entire stack, both Wolfcamp A and Wolfcamp B and it's -- the wells have performed extremely well so far. Very, very happy with that acquisition.

Great details, both. And then maybe, sorry, just a follow-up again for you, Jeff, just one more and this one on logistics. Specifically, you guys continue to do a nice job of -- again, I know everybody else is seen -- everybody is sort of seen inflation out there. My concern is more about potential logistical issues that I'm sure you're facing each day.

What are you guys doing to sort of overcome that? It doesn't appear that you have any potential upcoming shortages, whether that be pipe casing, frac spreads, et cetera. So I just want to hear more about what you do to sort of stay in front of this because it really does seem like you guys are doing a great job.

Yes. Thank you very much. It's a complement to the team as a whole that we've been able to work effectively in the current environment. We've got outstanding partners. And we took advantage of the kind of the foresight of what 2022 might look like by entering into agreements for '22 relatively early in 2021.

And then when things started changing relative to the profit margins for our partners, we just sat down and got together and figured out things that were going to work that would allow us security for delivery of pipe, in particular, is the big one (inaudible). The labor market and other items are a little more of a green area because they're so dependent upon that individual discipline or a supplier. But in large part also to our (inaudible) having a multi-basin asset base, when things did pop up, we can just shift and do a little more Eagle Ford work or give some folks some relief in some of the sourcing supplies and that generally tends to be a win-win situation for both the partners.

So we feel very good about our ability to effectively put 2022 program into the ground and have some continued discussions ongoing about what we'd like to do for '23.

Our next question comes from Derrick Whitfield from Stifel.

Derrick Whitfield. Certainly, congrats on your quarter and operational progress.

Thanks, Derrick.

With my first question, I wanted to focus on your capital plan and build on Neal's question, if I could. As the majority of the sector has announced CapEx increases or firmly messaging inflationary pressures, I wanted to first again complement you on the progress you've made on holding a lot of CapEx. And secondly, ask if you've quantified or could quantify the degree of self-help or operational efficiency you're effectively achieving in your capital budget?

Yes. I guess Derrick -- start that -- we had baked some of that in at the beginning of the year with our operational plan at that time. So I'd say headline inflation at that point was in that 12% to 15% or so that we saw across the sector, incorporating some of the, what you call, self-help, whether it be increase efficiencies, we continue to deliver over time, get wells down faster over time. And then maybe a little bit unique to us being able to reach some synergies from the Primexx acquisition, we are closer to the 10% at that point. So hopefully, that gives you a sense of what kind of a few percentage points that we saw on a self-help delivering to us.

And on the operational side, we made some modifications in particular on the completion design in the Delaware Basin South assets, where we lowered some of the fuel of the water loading and still within the same amount of sand changed the completion design from a perforation scheme, et cetera.

And so you (inaudible) going into well on some of the upfront water costs, the larger pads work out a little bit better from a distribution of the upfront costs. And that is overall operational efficiencies on having very effective completion crews and knocking out the wells on a regular basis consistently. So that's all been kind of a standard what Callon has always tried to do, and so far, so good in the first part of '22.

That's great. And again, congrats to you guys on those measures. And as my follow-up, I wanted to ask a Delaware ops question focusing on the operating cost side. Referencing Slide 8, could you perhaps quantify the absolute gross volume improvement from the installation of ESPs and speak to the amount of well maintenance projects you have planned for the balance of the year?

Well, it's a good question. It's kind of an ongoing effort because all the wells don't necessarily react the same. So the wells that we've quoted here were a little bit heavier on the water side. And so we proactively came in and put in ESPs to give that -- it's a density issue, oil being lighter than water. So if you have a little more water, the lifting mechanisms from [natural] process are worse the initial flowback period.

And so what we're going to do is systematically look at all the wells that we have in our portfolio that are not on the [lift] and then determining when the best time is to put those on. Normally, what you've seen, if you look at a long-term projection of a well over 18 months, for instance, that usually has a component of an artificial lift installation being done to it at some point in time.

And so while we don't expect necessarily every single well to have an immediate 40% uplift, you generally speaking, do see some of those uplifts initially. These happen to be consistent and are going to be sustainable. The other ones just tend to be kind of part of the normal process for the well might and you wouldn't necessarily achieve a greater EUR, for instance, by having ESP and so on. These wells, I do believe, are overall going to be benefited from these installations.

That's great color, Jeff. And great update, and thanks again for your time.

(Operator Instructions) Our next question comes from Davis Petros from RBC Capital Markets.

Just kind of a first one, and I realize kind of debt reduction until you work towards that 1x leverage and $2 billion aggregate, that level remains the focus for now. But is there an update on when you think kind of discussions around the shareholder return strategy can start? I mean do those targets need to be met? Or can those start kind of a quarter or 2 ahead of time? .

Yes. So let me take this one. I think all I want to say on this is we're heading towards these numbers at the end of 2022. So the focus this year is taking that free cash flow and helping get our balance sheet in a position where we can weather future commodity cycles.

So all I want to say is we're heading towards those numbers at the end of 2022. We're going to be cleaning up some of that high-cost debt and at the same time, doing our homework on shareholder returns. And this homework includes sensitivity work on our cash flows to ensure that whatever we decide on is sustainable through cycles. It gives us corporate flexibility and then frankly, meet some needs of the shareholders. So I don't want to put a specific timing out there at this point other than we're going to get close to these numbers at the end of 2022.

Got it. Makes sense. And I guess just kind of as a follow-up, one of your peers recently announced kind of a bolt-on acquisition in your backyard in Howard County. I'm wondering if there's any updated thoughts kind of on Callon's role in industry consolidation kind of moving forward as well as kind of how you're seeing the M&A market today.

Yes, it's a good question, and we've seen a little bit of an uptick in activity, although in the volatile markets. Sometimes it's a little bit more challenging to get things done. Say -- for us, it's a very high bar on the acquisition front. Certainly, anything that we're going to focus on of any size will have to be accretive to our asset quality, but more importantly, advance the balance sheet, just like (inaudible) was a great example of that.

Jeff talked about the results of that property just as we thought. This is going to compete well and attract capital. But effectively, we're able to finance it with 75% equity and be accretive to free cash flow per share. So we checked a lot of boxes.

We'll certainly continue to evaluate opportunities like that, but I think it's a very high bar. In terms of the overall M&A market, I think there is a lot of hope coming out of the gate this year. There'll be a lot of assets moving, private sellers trying to monetize their positions, (inaudible) I think the bid-ask becomes pretty tough at this point. But again, there is nothing for us to chase right now. We've got a deep inventory, as I talked about. If an opportunity comes along and it checks all those boxes, we'll certainly take a look.

Got it. Okay. And just one last one, if I can squeeze it in, kind of building off that prior question regarding the short cycle projects you all are doing. Can you remind me kind of how exactly those flow through to financials? Would that be kind of a capital cost? Or is that a workover LOE cost?

It will be a mix depending on the type of project (inaudible) breakdown, but some fall into capital workover summer expense.

We have no further questions in queue. I'd like to turn the call over to Joe Gatto for any closing remarks.

That's great. Thank you. Thanks, everyone, for joining. Before we go, I'd like to take a quick moment to pass on a big thank you on behalf of all of us at Callon to Larry McVay, who will be retiring from our Board at our upcoming annual meeting. Larry's contribution to the Board over the last 15 years have (inaudible) valuable, and we wish Larry and his family all the best in the future.

Again, thanks, everyone, for dialing in today, and we look forward to talking to you next quarter. Thank you.

Thank you for joining us on this call and for your continued interest in Callon. We look forward to speaking with you again next quarter. This concludes today's conference call. You may now disconnect.