Callon Petroleum Co (CPE) 2020 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to Callon Petroleum Company's Fourth Quarter and Full Year 2020 Results and Operating Outlook Webcast. (Operator Instructions) And as a reminder, a replay of webcast for the call will be archived on the company's website for approximately 1 year.

I will now turn the call over to Mark Brewer, Director of Investor Relations for opening remarks. Please go ahead, sir.

Thank you, Chris. Good morning, and thank you for taking the time to join our conference call today. With me this morning are Joe Gatto, President and Chief Executive Officer; Dr. Jeff Balmer, our Chief Operating Officer; and Jim Ulm, our Chief Financial Officer.

During our prepared remarks, we'll be referencing the earnings results presentation we posted yesterday afternoon to our website. So I encourage everyone to download the presentation if you haven't already. You can find the slides on our Events and Presentations page located within the Investors section of our website at www.callon.com or under the General Presentation page.

Before we begin, I'd like to remind everyone to review our cautionary statements, disclaimers and important disclosures included on Slide 2 and 3 of today's 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'll 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 presentation slide and in our earnings press release, which are available on the website. Following our prepared remarks today, we will open the call for Q&A.

With that, I'd like to turn the call over to Joe Gatto.

Thanks, Mark, and thanks, everyone, for joining us this morning. We're certainly glad to be back in the office this week following a very different situation just 1 week ago in the state of Texas. However, we clearly recognize the hardships that continue for so many, even though temperatures have risen and basic services are mostly back online. And we certainly look forward to brighter days ahead for all.

Over the last several days and months, our industry has once again been in the headlines and opinion polls for very good reasons. The evolution of the broader energy landscape will not be an easy path and certainly not move in a straight line. We firmly believe that there is a substantial role for low-cost, sustainable producers like Callon at play in underpinning the global economy in our way of life for years to come.

Focusing on that future. Our actions and decisions this past year have enabled us to deliver on our promises to investors, including meaningful free cash flow generation and improved financial strength. As we further our life of field development model across our balanced portfolio in coming years, we project $500 million to $800 million of free cash flow generation through 2023 in a band of $50 to $60 per barrel benchmark oil prices, adhering to reinvestment rates at 75% of discretionary cash flow and below. That cash flow will be directed to absolute debt reduction, keeping us squarely on the path to a leverage ratio goal of below 2.5x by the end of next year.

This operational financial outlook doesn't carry much weight, unless it is complemented by our commitment to improve sustainability throughout our organization and day-to-day processes. Meaningful change in this area can't be accomplished merely through just redesigned protocols and initiatives. It requires a change in mindset across the company. And our achievements in 2020 clearly demonstrate that our team has embraced that perspective.

You can see on Slide 5, the performance for the fourth quarter as well as the full year 2020, exceeded expectations in every category. At a high level, we generated approximately $125 million of free cash flow over the last 3 quarters after pivoting our capital plan and portfolio allocation in March. Obviously, this free cash flow number captures several components of our business model, the most impactful of which were better-than-expected capital efficiency and cost synergies achieved this year as the organization did a remarkable job integrating in a far from normal environment.

In sum, there is an impressive list of achievements on this page that came together to advance our debt reduction goals. And over the second half of 2020, we were able to reduce our net debt by $350 million.

2020 was also a year that saw our overall ESG program and sustainability initiatives progress significantly. Our preliminary emissions figures and flare volumes were much improved, spill volumes saw a reduction of over 60% and our water recycling program continue to grow. Safety has always been a core tenet of our business. This past year marked a new record low for total reportable incidents for the second consecutive year. Importantly, this progress is complemented by a change on the governance front. We recently formalized the responsibility for ESG oversight within our committee structure, which will drive increased focus and accountability going forward.

Since it doesn't always get as much attention as the improvements on our environmental scorecard, I wanted to highlight and commend our employees' engagement and support of those in need during this pandemic. Outreach the first responders, support for our schools and direct contributions to food banks were just a few of the ways people at Callon chose to make a difference.

We will be publishing more detail on these and many other topics in our next SASB aligned sustainability report this summer. And we will also be providing an update in the coming weeks regarding changes to our compensation design, which will include enhanced linkages to ESG performance.

Slide 7 provides a snapshot of our proved reserve base. While the more than 30% reduction in benchmark oil prices certainly made an impact on our PV-10 valuation, the fact that it only reduced total preserved volumes by approximately 5% pro forma for divestitures speaks to the strong margins and quality of projects inherent in our asset base.

In terms of proved undeveloped reserves, we lowered the number of locations within our development window to align with our moderated development activity and projected reinvestment levels. Separately, certain undeveloped opportunities were removed as we continue with the application of more tailored spacing and stacking design and select operating areas.

In the right-hand chart, we have provided an alternative forward-looking view of our proved reserve value, utilizing the same reserve database and development assumptions, with the only change coming in the way of pricing. Utilizing flat benchmark pricing of $50 per barrel for WTI oil, $2.75 per MMBtu for Henry Hub natural gas and $22.50 per barrel for natural gas liquids, our proved reserve value increases to just over $4.6 billion, almost doubling from year-end SEC pricing and highlighting a significant foundation of proved reserve value and future cash flow generation potential.

I'll also point out our PDP F&D cost of just over $10.50 per BOE that highlights our low-cost resource base and will be a key element on the next slide. After ending our first year -- full year reporting cycle as a combined company, we have introduced additional detail to provide investors insights into the building blocks of our balanced multi-basin model, which is outlined on Slide 8. On a total company basis, our cash margins, including corporate and interest expenses, is projected to be amongst the leaders in the industry at over $20 per BOE. This is a great chart, in that it captures so many important elements of our business, including commodity mix, physical marketing strategy and risk management, operating cost control and corporate expense management.

Compared with a low-cost resource base, it allows us to reduce our reinvestment rates, while sustaining reserves and production. Our strong corporate cash margins will drive long-term free cash flows that are durable through periods of volatility. As I've discussed, our priority remains debt reduction, which will translate into the interest expense reduction. Once our leverage targets are met, we see the opportunity to redirect those interest expense savings to shareholders over time.

Before I leave this page, I'll point out a new element of our go-forward IR materials and financial reporting. We provided an overview of production, realizations and operating costs for both the Permian and Eagle Ford areas. Overall, both operating areas provide support from resilient cash margins and significant flexibility for capital allocation decisions and diversification across physical pricing points and commodity mix.

As a follow-on to our debt reduction priorities that I highlighted earlier, Slide 9 illustrates our path to attaining our goals on that front. As a baseline, our $430 million operational capital budget for 2021 implies a 75% reinvestment rate based on $50 per barrel WTI. We are committed to no more than this level of activity, so the implied reinvestment rate will only move down with a higher oil price outlook.

Looking out to 2022 and 2023, our 2021 investment plan will provide us optionality for multiple paths, depending on our outlook for commodity prices and capital costs after global supply and demand dynamics play out in 2021. Overall, we envision reinvestment rates below 75% under these planning price scenarios that will generate cumulative free cash flow of $500 million to $800 million over the next 3 years and drive leverage potentially below 2x by the end of 2023 just from organic free cash flow, excluding the impact of monetizations. While divestitures are not explicitly captured in these numbers, any transaction that we pursue must result in improvement to our credit metrics and overall leverage profile. We recognize the importance of aligning these key financial metrics with the strength of our operations and asset base and are very encouraged by the magnitude and pace of improvement that we see in the coming quarters.

At this point, I'm going to turn things over to Jeff to discuss operations.

Thanks. Thank you, Joe. Our team did an amazing job of handling a quick ramp down and then return to activity in 2020, all while driving down development and operating costs. We put together a plan for 2021 that utilizes a more consistent approach to activity than what we find ourselves having to do during 2020. We currently have 3 rigs and 2 completion crews in the field to kick start the year. We'll dial that back slightly towards the middle of the year, but the overall program should average roughly 3 rigs and 1 to 2 completion crews with balanced activity across each of the asset areas as depicted on the pie chart on the right. Altogether, we are targeting no more than $430 million in operational capital spending, and that's inclusive of seismic we've seen in various facility improvements, et cetera. This should result in somewhere around 60 drilled wells and 95 completed wells by year-end.

We continue to migrate towards larger average project sizes, expecting an average of approximately 5 wells per project and just under 9,000 lateral feet per well. With this continued level of efficient development, our project portfolio for 2021 has an average project IRR of over 45% at just $45 WTI oil. You may recall that we were originally targeting a slightly lower capital range. But to support the future optionality that Joe covered in the previous slide, we've elected to minimally bump off our spending this year. Even with this slight change, we expect to generate meaningful free cash flow with a stronger production exit rate for 2021 than our prior forecast.

Speaking of production, we're getting very close to having everything back online from the results of the storms, and we expect to wrap up the remainder of return to production work in the Delaware before the end of February. Our Eagle Ford is pretty much 100% recovered, and the Midland Basin production is right behind. As mentioned in our earnings press release, the impact was severe with nearly all of our production off-line for a period of time.

During this weather event, our development activity was paused out of an abundance of caution. And while we probably lost a few days, our efficiency has been so prolific that I'm very comfortable that we'll pick those days back up without any issue. At this point, we don't see any lasting effects other than the production deferrals and some minor spending for some facility repairs, which is still well within our LOE guidance. I'll leave it up to Jim to update everyone our 2021 full year guidance later in the presentation.

Before I move on to the next slide, I want to take a moment to recognize our entire field operations team. The efforts, expertise and attitude of this team in the face of serious adversity, not just over the past 2 weeks with this extreme weather, but throughout a very tough 2020, is purely remarkable. Your work is acknowledged and appreciated, and we're all extremely proud of the way you performed, and I look forward to a front-row seat and having us knock it out of the park again this year.

On Slide 11, I've spent much of the last few quarters outlining various levers. We pulled in the fuel to help drive operating costs down and increase production uptime and reliability. At the same time, we focused on reducing our environmental impact and improving as a steward of our natural resources. It should come as no surprise that improving our field operations has benefited our ESG initiatives, while simultaneously lowering our lease operating expenses by about $30 million from pro forma 2019 spending levels. Optimization of our chemicals, compression, gas lift and water management programs were meaningful contributors to those savings this past year and will continue to be areas of focus in 2021.

Some additional areas of concentration are the expansion of our Eagle Ford electrification efforts, increasing our produced water recycling and advancing efforts around tank vapor capture and those types of things. One additional area I'd like to highlight is our peer-leading ESP runtime. So those are the electric submersible pumps, which are down inside existing producing wells. That runtime is now well over a year, which reduces work-over frequency and of course, overall costs.

Moving to Slide 12. While our operating cost improvements have been meaningful, our development cost savings have been extraordinary. Our Delaware costs are down more than $400 per lateral foot, representing a 35% reduction from 2019. Maybe more surprising has been our ability to cut our projected Midland Basin development costs by almost half, despite having it be a more mature asset. We attribute much of this to continuing to acquire and analyze data and examine and refine our surface and subsurface assumptions and practices continuously. The customized spacing programs, landing zone optimization, reduced water loadings and advanced completion design and changes to the pullback program all demonstrate the continued efforts to squeeze every last bit of economics out of our portfolio. These improvements along with faster cycle times are driving our fuel-level efficiencies and lowering our overall economic breakevens.

That's all for operations. So I'm going to turn things over to Jim.

Thank you, Jeff. Turning to Slide 13. You can see that our 2021 oil production has been hedged primarily with NYMEX WTI collars, providing us with upside participation as prices have risen. In the second quarter of 2020, we had an RBL requirement to hedge a portion of our 2021 PDP production via fixed price swaps. We have been active in restructuring those positions to provide the best available cash flow protection, and we moved out of numerous swaps executed during significantly lower commodity windows into more friendly collars as the year evolved. We are also more hedged in the first half of 2021 than in the back half of the year, allowing us to opportunistically top off positions as the curve continues to shift up to meet what appears to be an improving supply and demand equation.

We've been very patient with entering positions for 2022 and then, thus far, been employing wide collars with a $45 floor and $60 ceiling with just over 3,700 barrels per day locked in at this time. We will continue to be patient and systematically employ protection for 2022, but we'll likely lean towards mechanisms that provide meaningful upside with firm downside protection.

While natural gas makes up a much smaller portion of our physical production and revenue base, we have floors in at $2.60 per MMBtu for just over 60,000 Mcf with upside to $2.85 per MMBtu on average. At the bottom right of the slide, we provided a sensitivity analysis of realized pricing post the hedge impact of our current positions. You'll note our projected realizations climb meaningfully in the second half of 2021, coinciding with our ramp-up in production.

Turning to Slide 14. I will say that looking back into last year, I'm happy to say we've made significant progress in improving the amount of our RBL and total debt outstanding through our second lien offering, exchanges, monetizations and the continued focus on free cash flow generation.

In the chart on the left, you can see where we have significantly reduced the outstanding borrowings on our credit facility, alongside a net debt reduction of nearly $350 million since the end of the second quarter. We will continue to review all of the options for additional reductions in leverage and will evaluate these opportunities as we manage our debt maturities.

On Page 15, speaking of maturities. Our earliest maturity is the 2023 senior notes. With the significant reduction in our credit facility borrowings, the improved opportunity for significant free cash flow generation over the coming next 3 years in what has been a resurgent high-yield market, we see several avenues to continue improving our capital structure and financial flexibility. As Joe mentioned earlier, we are still looking at additional monetization opportunities this year to increase our debt reduction near term. I'd like to point out that we have set a goal of having our net debt-to-EBITDA below 2.5x by the end of 2022.

Slide 16 provides our updated guidance for the full year 2021. Some of this has already been covered by Joe and Jeff already, but I do want to point out some important points. Our annual production guidance is 90,000 to 92,000 BOE per day with an average approximate oil cut of 63%. This is after accounting for the winter storm impact of roughly 2,000 BOE per day on an annualized basis. Based upon that impact, we currently expect the first quarter to average somewhere around 80,000 BOE per day with an oil cut likely closer to 62%.

Given our meaningful improvement in lease operating costs, the midpoint of guidance sits at $200 million, which is below the bottom end of last year's guidance rate. GP&T is slightly higher on an annual basis this year, but this is the first time with a 4-quarter impact reflecting our firm transportation capacity to the Gulf Coast. We only began recognizing this as a meaningful line item in mid-second quarter of 2020. We are budgeting for operational capital of up to $430 million. This is a 12% reduction from last year's spending levels and well below last year's revised guidance. As outlined in the earnings release, we are currently running 3 rigs and 2 completion crews during the first quarter. So we would expect first quarter capital to be a bit higher than a pro rata 25% of the annual operational capital spend. With the ramp of completion activity expected through the second quarter, we would also expect it to follow suit and end up slightly higher than the first quarter.

At this point, I'd like to turn the call back over to Joe.

Thanks, Jim. Past year showed that our team is highly capable of managing through extraordinary circumstances and find creative and thoughtful ways to protect and enhance value for our shareholders. Investors have spoken, and we have listened. Our goals are clear and achievable. Our leadership and Board are keenly focused on optimizing free cash flow generation, reducing our data obligations, safely and efficiently maximizing the value of our assets and achieving our sustainability goals. We will continue to improve the talent value proposition in ways to create a durable, low-cost business that can return capital to shareholders once net debt is reduced to our target levels.

With that, I'm going to turn it over to Chris for opening up Q&A.

(Operator Instructions) Our first question is from Neal Dingmann of Truist.

Joe, my first question is really just kind of on completions, maybe broader about this. It's been interesting, some of your peers, and Marathon had talked about this have seemed to have for whatever reason have gone to maybe what I'd call a tighter focus. They've focused on fewer zones, they've focused on wider spacing, maybe even in more sort of less broad areas where you all have been able to sort of continue with this, what I'd call, more diverse plan on all those facets. I mean could you talk about, will that continue to be the plan? And are you able to do that just because you're continuing to see strong enough returns when that's been the case?

Neal, yes, I think your last comment sums it up pretty well. I mean there's a lot that goes into that. But as we've talked about, we've been very consistent in terms of our, what we call, life of field development approach. We've a substantial multi-zone resource base, certainly in the Permian, employing a scaled model, which was a big thesis, obviously, the Carrizo transaction to allow us to have the critical mass to co-develop the zones the right way.

Now that's not to say that we're chasing every zone that we see in the stack. And we are making decisions for zones to carry their weight. But given the strength of multi-zone opportunity, we see that there's extreme value to capturing that and not letting them degrade over time and cherrypick what we have. So this is all about sustainability over time and trying to get too focused on the near term to make decisions that will impact longer-term value.

Got it. Got it. And then, my second question, probably for you, Jim. Definitely, it's not lost your -- what I'd call your sort of longer-dated plan that obviously has debt coming down nicely. But you can't help but notice, not only has the equity have been on a nice run in the last few weeks but obviously the creditors or the bonds have as well. So I'm just wondering what that said, are there -- you've probably talked about this in the past, I don't know, because the credit has run like it has like the equity, cost of capital now is cheaper. Are there going to be potentially other opportunities sooner than that? Or is look -- or do you sort of stick with like our eye on the ball is still going to be on that longer-term plan and if something comes up, so be it? I'm just wondering how you all kind of viewing the near-term versus longer-term plans?

Neal, this is Jim. I'll kind of answer that briefly and then if Joe has anything to complement it with. We have said pretty continuously for the better part of the year, priority #1 is absolute debt reduction. But a refinancing or something along those lines of some of the nearer-term maturities would give us additional runway for free cash flow generation. I -- your point is well taken that the capital markets appear to be improving. We've tried to really look at what the best opportunity is at the time. And I think you'll see us continue to do that. But again it's about absolute debt reduction, it's about free cash flow and just continuing to evaluate opportunities as they come up.

Joe, I don't know if there's...

Yes. The plan we laid out with the free cash flow generation and complemented by, I think, a reasonable monetization targets that we think can expand in this type of market and to underpin it. Our options are only going to expand more if we continue to execute on that baseline. So we'll be opportunistic. And if there's things that make sense in the broader capital markets, we'll certainly be evaluating all of those that we do every day.

So guys, does that mean with the refinance mean you would consider even buybacks in the open market, given, I guess, what some of these bonds are still kind of sub-80? When you talk about refinancing, Jim, I guess that's what I'm wondering, is it -- how you think about, is that refinanced pretty broad as far as either traditional refi or going back in the open market?

Yes. Neal, that's a good point. One of the things that you've seen is our bonds have traded up into the 70s and 80s. As I look forward into the year, I think one thing that could make sense would be open market repurchase. But again, it -- that will be on an opportunistic basis, and we're going to focus on the free cash flow generation, the other initiatives that Joe mentioned and really just keep methodically moving forward and getting the debt down.

The next question is from Scott Hanold of RBC.

Just kind of curious on that longer-dated outlook through 2023 you all had. Obviously, in the 2021 outlook, you do show a fairly balanced development plan. Can you give us some color and flavor, like how that progresses over those other couple of years? And also, maybe a little bit of color on where you see the IRRs of those opportunities because I think you had mentioned with the 45% IRR on the 2021 plan? How does that look in mix and returns going forward?

Yes. The project portfolio is excellent. So we would anticipate those types of project returns to be sustainable for many, many years. And as Joe had mentioned, the idea behind the development program has been consistent for multiple years in the past and going forward, where we evaluate the full stack. We have a very well-developed proprietary set of data and algorithms that determine the way we should make sure that we get it while we're out there in 1 or 2 zones, and maybe we can come back and give them at a later point in time. But I would say that our project portfolio is excellent and sustainable.

Okay. And the mix, will the mix stay fairly balanced?

Yes. Thank you for reminding me. Yes. Obviously, there's more runway in the Delaware, which are fantastic returns. But we still have a fair amount of drilling to do that in Eagle Ford and in the Midland Basin. So for the -- certainly for the next couple years, you'll see the continued mix of assets.

Okay. Great. And then looking at those well costs, obviously, you guys have really pushed the envelope on getting cost down on a dollar per foot basis. And it seems like you're obviously lending some data to show that you think there's some sustainability. But again, maybe reflecting, obviously, with the 2021 plan firmly out there. But like as you look at '22, '23 again, can you sustain those costs that lower? Where would you see some pressures if you were to see some?

Sure. And that's a fantastic question. From an efficiency standpoint, we've made improvements every year. And so we would continue to project that we'll get better and better at what we do, dropping down the overall costs and cycle times. From a contractual standpoint, our partnerships with our vendors, the reality of it is if we're in a $60 or $65 oil or whatever the number is, we would all expect to see cost increases potentially, but they would be than offset by the improvements in free cash flow. I don't feel like we have a lot of exposure in 2021. We've got a lot of good contractual systems put in place. And so I mean, I think it would be a good problem to have if costs went up because we're making a lot more money on the revenue side.

Okay. And I mean I'm just kind of curious if you could give us some sensitivity around that. Like what we were to say -- see a kind of a $60-ish kind of outlook in those out years, where do you think the sensitivity is on some of those costs overall?

I'd be using a bit of a crystal ball in that forecast. Again, I think focusing on 2021, we're going to be well within a couple of percent, maybe if we see some upward prices on the back half of the year. But if you look back and you glue together what historic well costs have been based upon the contracts versus the efficiencies, I don't anticipate that we'll have a significant negative effect on the overall cost structure. And again, just to reiterate, from a profitability standpoint, we'll be even better in higher oil prices.

The next question is from Brian Downey of Citigroup.

For Jim or Joe, as you think about the free cash flow and debt reduction targets you've laid out on Slide 9, are you approaching either the pace or strategy of hedging any differently entering this year? Jim, I know you mentioned you started on the 2022 hedging program, but does the medium-term strategy change around hedging as you're thinking about those 3-year goalpost?

I would think, generally, we've hedged during the calendar year, somewhere in the 60% to 65% range. I think that's probably a pretty good approximation. There may be moments where we opportunistically go higher than that. But I think generally, that's right. I think as we look at '21 and '22 and '23 sequentially, the thought would be to use things that have price participation, as I said, but firm downside. So that's potentially swaps, collars or puts, those types of things.

And then I think really what's maybe different going forward in '21 and '22 is that we'll really be focused on kind of what that free cash flow breakeven price is and make sure that weighted average floors that we have are supportive of generating that free cash flow over the coming quarters.

And I guess, is -- the time horizon over which you're extending those hedges, is that going to be pretty similar? Or would you start going out any further than normal?

I think we'll be looking very closely in 2021 for places to optimize or maybe layer in, in the second half. The hedges that we have in place right now are really first and second quarter of 2022. So we'll be methodical about it and kind of layer in as it makes sense. And again, part of that will be just driven off of what the curve does in 2022. We -- I think we'll end up 2022 in a similar absolute level. And I think we'll be watching that over the next couple of quarters.

Great. And then for my follow-up question, Jeff, you continue to make progress on the capital efficiency front for some of the other questions this morning. You talked about scale development program. I believe you mentioned a 5-well average project size for this year. I'm curious what else you're thinking about for 2021? We've heard others in the industry talk about things like electric fracs and simul fracs. I'm curious if your view of your current program and pad size is conducive to trying some of those techniques either this year or is that 3-year planning period on hold?

It is as a matter of fact, we have converted over to using -- we're breaking in and getting up and running a dual fuel completion crew, which we're really excited about. Based upon the recent weather, I think we're going to start with diesel for the first pad and just make sure everything works just fine. But we go into dual fuel for the entire year of 2021 on that frac crew. And then we will also be testing an electric frac fleet with an independent set of wells and development program that we have here towards the end of Q1 or the beginning of Q2.

In addition, there's other projects that are underway that we've touched on a little bit like the continuous focus on electrification projects for the Eagle Ford and some other areas, Callon has 3 substations that we own and operate that really help improve the reliability and drop down some of the emission systems. So yes, all of that stuff is not only on the plate but will be a big part of what we do in 2021.

(Operator Instructions) The next question is from Derrick Whitfield of Stifel.

Perhaps for Joe or Jim, your reiterated guidance in the face of material weather impacts in Q1 would seemingly suggest a higher 2021 exit rate as you noted in your prepared comments. Could you share with us the shape of your production trajectory and where you'd expect to exit the year?

Yes. I mean coming off of the first quarter, obviously, a meaningful impact there. Coming into '21 before the storm, we were going to be -- the shape was a little bit lower in the first quarter before we started working through that DUC inventory, that had a substantial amount of completions in the first half. I think we're up 55 or so. So we have that increased trajectory going into the second and third quarter.

In terms of exit rate, we haven't put that out there yet. I think we're making sure we get past the storm and reconfigure things in the right way. But certainly, we're going to see a pretty hefty increase off of the first quarter into the second and third quarter that will certainly impact going fourth quarter and give us some momentum into 2022.

Great. Fair. And perhaps for my follow-up, sticking with you, Joe, your team has really navigated this environment about as well as any. Regarding the additional asset monetizations of $125 million to $225 million that you referenced in your press release, could you speak to the nature of those assets included in the health of the A&D market for those assets?

Yes. Well, I'll certainly address your first comment, take that. The team has done a remarkable job. So I appreciate you recognizing that. And it's putting us in a position to take advantage of the opportunity sets in front of us. And we've been patient on the monetization front. We're able to get some fields done last year, the right transaction for that type of a market. We had deferred a bit on our classic working interest transactions last year because we just didn't see the value proposition, certainly didn't see a path of getting transactions done that would be credit enhancing.

So as we talked about last year, when we established our $300 million to $400 million target on the back of the Carrizo transaction, there was a broad pool of opportunities. In other words, a lot of ways to be right. So we still have that broad pool. Just a lot more of them are back on the table. So we have a couple packages in the Delaware and the Eagle Ford that we've been looking at over time. Again, we didn't push it. We've been patient, and I think that patience will pay off here. We've maintained the dialogue importantly and the momentum. So as windows open up, we'll be able to hit those markets pretty quickly.

The water business we've talked about over the last few quarters, certainly, is an opportunity to monetize that asset and also potentially monetize some of the latent capacity in that system. Again, being patient there has allowed us to put forward the plan we did today, right, to show potential bidders that we have a sustainable plan. We have the free cash flow, that when you look at the asset base, you're not going to heavily risk it because there's all some certainty.

We've shown in the past for potential bidders at this point that you sign up for these types of water volumes and value them, we're going to deliver that and then so. So that continues to proceed, but in a volatile market and yes, it's been a lot better last month or so. We can't just follow up with any one path. We got to keep a lot of doors open. We'll continue to do that and hope to be updating everyone in the coming quarters on that front.

The next question is from Dun McIntosh of Johnson Rice.

Appreciate all the color. Just one quick one for me. If you could talk a little bit about how you thought about DUCs historically, a little bit of a bump on CapEx to exit the year I was thinking of kind of where did you come into the year with DUCs? And kind of what's an ideal level that you think about kind of keeping in the program over this kind of 2- to 3-year plan that you laid out?

Yes. Where we're see coming in (technical difficulty). My apologies, I think there's a little feedback. Where we came into 2021, we were kind of in the mid-60s, give or take, from a DUC count. We had been very rigorous in our assessment of capital spend in 2020 and so probably came into the year a little bit higher than would be normal. We'll end the year 2021 with the current game plan, roughly half of that going in into 2022. And that's a good spot to be for the -- where we sit relative to the capital program and having modestly consistent production, where you don't see those significant peaks and valleys. So that's kind of where we sit.

I guess the other items I mentioned is all DUCs are, of course, not created equal. So where we came into 2021 with -- probably half of those were sitting in the Eagle Ford, which are very profitable, but smaller wells from a production standpoint. The mix right now going into 2022 would represent a higher percentage of what is being in the Permian Basin versus the Eagle Ford.

Ladies and gentlemen, we have no further questions in the queue. And this concludes our question-and-answer session. I would now like to turn the conference over back to Mr. Joe Gatto for any closing remarks.

Thanks, Chris. Thanks, again for, everyone, joining. I think we might have had some audio issues off and on. So we'll certainly get that transcript out there, and please feel free to give us a call with any follow-up questions, but hopefully, that wasn't too bad. Again, we look forward to talking to you all in May with first quarter earnings and another update. Thanks, again.

Thank you very much, sir. Ladies and gentlemen, that concludes this event. Thank you for attending today's presentation, and you may now disconnect.