Good morning, and welcome to Centennial Resource Development's conference call to discuss its Q1 2022 earnings. Today's call is being recorded. A replay of the call will be accessible until May 12th, 2022 by dialing 855-859-2056 and entering the conference ID number 303538, or by visiting Centennial's website at www.cdevinc.com.
At this time, I will turn the call over to Hays Mabry, Centennial's Senior Director of Investor Relations, for some opening remarks. Please go ahead.
Thank you, Ludy, and thank you all for joining us on the company's first Q1 earnings call. Presenting on the call today are Sean Smith, our Chief Executive Officer, George Glyphis, our Chief Financial Officer, and Matt Garrison, our Chief Operating Officer. Yesterday, May fourth, we filed a Form 8-K with an earnings release reporting Q1 results as well as operational results for the company.
We also posted an earnings presentation to our website that we will reference during today's call. You can find the presentation on our website homepage or under presentations at www.cdevinc.com. I would like to note that many of the comments during this earnings call are forward-looking statements that involve risk and uncertainties that could affect our actual results and plans.
Many of these risks are beyond our control and are discussed in more detail in the Risk Factors and the Forward-Looking Statement sections of our filings with the Securities and Exchange Commission, including our quarterly report on Form 10-Q for the quarter ended March 31, which will be filed with the SEC later this afternoon. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance, and actual results or developments may differ materially.
We may also refer to non-GAAP financial measures that help facilitate comparisons across periods and with our peers. For any non-GAAP measure we use, a reconciliation to the nearest corresponding GAAP measure can be found in our earnings release or presentation, which are both available on our website. With that, I will turn the call over to Sean Smith, our CEO.
Thank you, Hays. Good morning, and welcome to Centennial's Q1 earnings call. Overall, Q1 was a strong quarter, and we are very pleased to have started the year off with robust financial and operational execution. From a financial perspective, we generated record free cash flow that allowed us to fully repay all borrowings under our credit facility and build a significant amount of cash. This net debt reduction delivered leverage of 1.1x at the end of the quarter, a level that is ahead of previous expectations.
Operationally, we continue to deliver from a technical perspective with strong well results from our Northern and Southern Delaware positions across a variety of zones. Additionally, we were able to deliver capital expenditures in line with our expectations despite completing six more wells than originally anticipated.
This dynamic underscores our operation team's focus on continued drilling and completion efficiencies, as well as continuing our quarterly success of drilling and completing wells ahead of schedule and under budget. In my comments from the year-end 2021 call, which is highlighted on slide 5, I laid out a differentiated 2022 game plan that was predicated on 3 core principles. 1st, delivering meaningful free cash flow generation and reducing leverage below one turn.
2nd, targeting top-tier oil production growth of 10% to 15%. 3rd, announcing and executing on our 2 year $350 million share repurchase program once we have achieved our leverage target.
As I look back at our execution in the Q1 and look ahead to our expectations for the remainder of the year, we believe that these objectives are not only on track but are ahead of schedule relative to our initial expectations. From a growth perspective, we believe we are well-positioned to deliver on our targets based on our strong well performance and continued operational efficiencies to date.
From a free cash flow and deleveraging perspective, we have made significant progress in Q1 and are raising our free cash flow target by $150 million from greater than $400 million to now greater than $550 million at today's strip.
Third, with our revolver fully repaid, meaningful free cash flow on the balance sheet, and leverage nearing our target levels, we look forward to commencing our share repurchase program in the near term. All in all, Q1 was a very strong quarter, and I'm excited for our continued financial and operational execution of our 2022 game plan. With that said, I'll turn it over to George to review our financial results.
Thank you, Sean. Turning to our financial and operating results on slide 12 of the earnings presentation, overall Q1 results were in line with our expectations. As we had previewed during our Q4 earnings call back in February, Q1 production levels declined quarter-over-quarter due to the shift to larger development packages in addition to the carryover of DUCs from Q4. As a result, net oil production for the Q1 was approximately 32,750 barrels per day.
While average net equivalent production totaled approximately 61,400 barrels per day. Oil as a percentage of total production declined to 53% from 55% in Q4, due in part to the completion of six wells in the high GOR area of our Reeves County acreage, several of which were the highest rate of return wells in the quarter.
Despite lower production levels compared to Q4, total revenues increased by 10% quarter-over-quarter to almost $350 million as a result of higher oil and NGL prices. Overall, unit cost during Q1 came in within expected ranges relative to full-year guidance. Q1 LOE per barrel was slightly higher than Q4 due to elevated workover expense, but was still within our guidance range for the year. GP&T was slightly above expectations, mainly because of higher than anticipated natural gas and NGL prices, which increased the expense associated with our percent of proceeds contracts.
As I mentioned on the last earnings call, Q1 is expected to be our lowest production quarter this year, and we expect our overall unit costs to decline in subsequent quarters as our production base increases.
We generated approximately $89 million of free cash flow during the quarter and used that cash flow to fully repay borrowings under our revolving credit facility and to build cash on hand. Adjusted EBITDAX totaled $217 million, which was up approximately 16% from Q4. Lastly, net income for Q1 totaled approximately $616 million. Excuse me. Turning to CapEx. During Q1, Centennial incurred approximately $115 million of total capital expenditures.
For the quarter, we spudded 13 wells and completed 18 wells, compared to 12 and 9 respectively in the prior quarter. While Matt will touch on this further, it is important to note that as a result of efficiencies, we completed 6 more wells during the quarter than anticipated, but still posted CapEx in line with our original expectations.
This acceleration of well completions into Q1, coupled with over half of our Q1 wells being brought online during the last month of the quarter, sets Permian Resources up for significant quarter-over-quarter production growth and strong free cash flow in Q2. On slide 8, we summarize our capital structure, leverage and liquidity. Total net debt decreased by 8% from year-end to approximately $765 million at March 31st, and net debt to LTM EBITDAX declined to 1.1x compared to 1.4x at year-end.
The significant improvement in our balance sheet and strong outlook resulted in one-notch upgrades from both Moody's and S&P. At March 31, revolver borrowings were 0, providing us nearly full access to the $750 million of elected commitments under the credit facility.
Additionally, we had approximately $51 million of cash on hand, which we expect will build over time. Finally, with our 1st note maturity scheduled for early 2026, Centennial has significant financial flexibility going forward. Turning to our share repurchase, I'd like to reiterate a few points we covered on the last earnings call. 1st, we have the free cash flow profile and balance sheet to return a significant amount of capital to our shareholders. In fact, our $350 million program represents approximately 15% of our market capitalization.
Second, we expect the share repurchase program to be accretive to our long-term shareholders as it delivers higher per share ownership of production and cash flow as the plan is executed over time. With an already differentiated production growth profile, share repurchases can enhance our already strong metrics on a per share basis.
In addition, the share repurchase provides flexibility to drive value over time. Our strategy will allow for both regularly timed buybacks as well as opportunistic repurchases during periods of market dislocation. As time progresses and we build an execution track record, we are likely to revisit the size and duration of the current program in addition to evaluating potential additional return of capital options.
With respect to execution, we have previously communicated our intent to begin repurchasing shares when leverage fell below 1x. With March 31st, leverage at 1.1x and strong anticipated free cash flow in Q1, we look forward to beginning to repurchase shares in the near term. With that, I'll turn the call over to Matt to review operations.
Thank you, George. Q1 was an outstanding quarter for the operations group as we continued to build upon the significant operational efficiencies gained last year with incremental improvements to completion cycle times. We have also made the shift to larger packages of 4 to 6 well development projects to capture additional efficiencies via economies of scale.
We see the utilization of larger development units and the usage of shared facilities as key drivers of capital efficiency going forward. Staying on this topic, on slide 6, as we first mentioned during our Q3 call last year, our operations team began testing a new completions design which utilizes less fluid, resulting in shortened pump times and additional cost savings.
As you can see on the slide, we've driven a step change in our completion cycle times, increasing both stages per day and lateral feet completed per day by 17% and 32% respectively when compared to Q1 of 2021. Most importantly. Since we began pumping this new design late last year, we've seen strong initial production results as essentially every well utilizing this design has been at or above our original expectations.
As George alluded to, these completions efficiencies were the primary driver of us completing 6 additional wells during the quarter and places Centennial on a strong footing for the start of the year. On the drilling front, our team continues to carry over the efficiency gains from last year, which has been driven by larger pad developments and reduced mobilization times.
Additionally, we recently drilled our longest lateral in company history, the Challenger AC32H, which reached total depth in just under 16 days for a 2.5-mile lateral, or approximately 24,000 feet of total depth. For reference, our previous data point for a 2.5-mile lateral in Reeves County was the Doc Gardner AU-23H, which drilled to a total depth of approximately 23,000 feet in 44 days back in 2018.
This really puts into perspective, in my opinion, and demonstrates the material step change in performance from our drilling group. It is important to note that our team has not stopped at the drilling and completions process to drive efficiencies into the program or cut costs.
Shifting to the bottom right-hand side of slide 6, we began implementing centralized tank batteries in our development program during 2018 and continue to increase the percentage of our development program utilizing this new facility design. Once built, these centralized tank batteries are easily expandable to accommodate additional nearby wells and can do so at significantly lower costs than new build facilities. For 2022, we expect that roughly 60% of our new wells will flow into existing expandable facilities, a significant uplift compared to previous years.
Finally, we will be evaluating the potential to retire some of our legacy facilities over time and flow those wells into nearby newer facilities with expandable capabilities. This will have a positive impact on our LOE. Overall, our operations department is constantly innovating from a technology standpoint to drive further efficiencies.
The team's continued focus on innovation and efficiency will be particularly critical as we look to help offset some of the inflationary pressures we continue to see in 2022. Now turning to our recent well results on slide 7. In Reeves County, Texas, the Powder Donut wells came online in our Miramar block, which as many of you know, is the higher GOR portion of our Texas asset. This 4-well development consisted of laterals in the 3rd Bone Spring sand, Wolfcamp A, and Wolfcamp C, with average lateral lengths of almost 10,000 feet.
The pad delivered an average IP 30 of over 2,400 BOE per day per well with a 42% oil cut, or approximately 1,000 barrels of oil per day per well. Notably, the maximum IP 24-hour rate for the 4-well pad was over 41 million cubic feet of natural gas per day.
These wells represent our highest rate of return project for the quarter, and we expect this development on average to pay out in roughly 3 months. These are outstanding results from our team and a testament to their advanced planning and operational flexibility as we accelerated the development of this pad given the recent strength of natural gas prices. Furthermore, the Powder Donut wells represent another solid infill result from the 3rd Bone Spring and Wolfcamp C, further bolstering our confidence in our remaining inventory across the Texas acreage position.
In New Mexico, we completed 2 separate six-well developments during the quarter, both targeting the Second Bone Spring sand interval. In the central portion of our Lea County position, the Chimichanga and Queso Blanco wells were drilled as a six-well development with approximately 8,400-foot average lateral lengths.
These wells generated robust results averaging IP 30s of over 2,100 BOE per day or approximately 1,800 barrels a day of oil. Further south in the New Mexico acreage position, the Pac-Man and Donkey Kong wells represent another 6-well development, this time utilizing a staggered pattern in the upper and lower portions of the Second Bone Spring sand with approximately 8,500-foot average lateral lengths.
Like the Chimichanga and the Queso package, production numbers were strong, posting IP 30 numbers of approximately 1,750 BOE per day, or over 1,400 barrels a day of oil. Overall, our team did a tremendous job during the Q1 and brought online some outstanding wells. More specifically, we estimate that all our wells brought online during the quarter will achieve payout in approximately 4 months, assuming the current strip prices.
The well results this quarter continue to demonstrate the high quality of both of our assets. Lastly, I'd like to finish up reviewing our outlook for natural gas takeaway and how Centennial plans to navigate the potential headwinds. Depending on future Permian production growth, we do believe that natural gas egress out of the Basin could become tight in future periods until a new pipeline is built.
As such, we have been evaluating and are close to executing multiple term sales contracts, which would provide transportation for essentially all our expected gross residue gas in the near term out of the Permian Basin during these expected periods of tightness. Overall, our objectives are to maintain flow assurance for all product streams at a low transportation cost without entering into long-term contracts.
Given where we are in these discussions, we feel very good about our ability to execute on these agreements over the next few months and look forward to discussing in more detail on future calls. As you can see, our operations team is firing on all cylinders and doing an excellent job navigating the current oilfield service environment. While we continue to focus on driving further efficiencies in an effort to partially offset inflation, we are also very mindful to avoid any material delays or lost time to our operations.
In light of the current oilfield supply chain challenges, our team has been very focused on sourcing the necessary equipment well in advance of the anticipated schedule. We also work diligently to keep good lines of communication with our service providers so that Permian Resources can continue to efficiently develop our acreage on time.
Year to date, we have not experienced delays or procurement issues, primarily due to our team's efforts on both the planning and execution fronts. Overall, this is a strong start to the year from our operations team, and we look forward to building upon this performance going forward. With that, I'll hand the call back to Sean.
Thanks, Matt. In closing, we are very pleased with our execution in the Q1 and excited about the go-forward game plan for Centennial. We have put the company in position to continue to generate significant and sustainable free cash flow with a balance sheet that is resilient to commodity price volatility and provides financial flexibility.
We continue to have a differentiated growth profile supported by our high-quality assets in the premier US oil basin, an operations team with a proven track record and inventory depth that will allow us to continue to execute our game plan. These factors will allow Centennial to embark on the next chapter of our company with a focus on shareholder returns, which we expect to commence in the near term and have us well positioned to succeed for the remainder of 2022 and beyond.
Thanks for listening, and now we'll go to Q&A.
Thank you. The question-and-answer session will be conducted electronically. If you would like to ask a question, please do so by pressing star then the number 1 on your telephone keypad. If you would like to withdraw your question, please press the pound key. One moment please for our first question. Your first question comes from the line of Neal Dingmann from Truist Securities. Your line is open.
Morning all. It's Jordan Lavigne for Neal Dingmann. 1st, just wanted to compare the 2 lead developments you brought on this quarter. Both seem like really strong results, both 6 well developments, one kind of in that stack staggered pattern. I'm curious how you think about the comparative economics and performance versus your expectations in each of those developments, given they're kind of in relatively same zip code.
Sure. I'll take that. You know, we've been very pleased. The 2nd Bone Spring Sand in New Mexico has been kind of a bread-and-butter target for us for a while. We have been very pleased with both the stack stagger programs that we've been working in the upper and lower 2nd Bone Spring Sand, as well as some of the end zone tests of the lower 2nd Bone Spring Sand.
One of the things we've been very pleased with this year, by virtue of the larger development units, is the increase in percentage of parent wells relative to child wells as we move in and execute offset wells in a larger package of wells at one time.
You know, in past years where we were doing, you know, 1 or 2 wells or maybe, you know, smaller groupings, a higher percentage of our new wells brought online were subject to some of the depletion effects that we saw from prior producers. What we've seen in the shift so far is that the percentage of child wells in any incremental development unit drops significantly, and we've enjoyed more parent-like production from the offset wells.
Relative to our internal expectations, these wells are performing kind of right on par with what we expected them to, and the costs coming in kind of right where we needed them to come in, relative to, you know, these expectations.
Thanks for that. 2nd, I know you mentioned you hadn't experienced any delays or cost overruns, which is great to hear. Just want to get a sense of, you know, in the current service environment, what you are seeing, whether internally, or in talks with your neighbors, whether from a workforce perspective or a cost perspective.
Sure. You know, what we're seeing primarily, you know, the highest ticket items on any given well really are related to steel pricing and fuel pricing. We see those as kind of the dominant, you know, drivers of inflationary pressure. What we do is, we procure, we order that steel, we order the casing and the tubulars, you know, 2 quarters at a minimum in advance of the program.
We really have been committed to our contractors as well as the rigs. We have not had any material changes in terms of rig cadence or number of rigs that we contract at any given time.
We've been able to manage that schedule pretty far in advance and try to negotiate pricing and things like that. What we have heard people waiting on
A lot of times with sand delivery, relative to completions, and things like that. With our vendors and our lead times that we put out there, we have not had any of those kinds of delays relative to our operations, and we've been very proud of that working relationship with our vendors and our folks in the field with the long-term planning.
That's great to hear. Thanks so much.
Thanks, Jordan.
The next question comes from the line of Davis Petros from RBC Capital Markets. Your line is open.
Good morning, y'all. Thanks for taking my questions. I guess, kind firstly, just kind piggybacking on that last point, is there any updated thoughts on when you guys could maybe look to add a third rig, or even if that's a consideration at this point, just given the long kind of procurement lead time on securing those supplies?
Yeah, I appreciate that, the question, Davis. I'll take that one. You know, as we look at our program, I will say that, I think Matt described it very well. We haven't seen any delays or issues with procurement because of our advanced planning. Our current 2-rig program does provide significant growth on a year-over-year basis, differentiated from most of our peers, I would say, to the tune of 10% to 15%.
As we think about growing the business, we're going to do so within our own current operations and don't have a necessary need to add a 3rd rig to provide additional growth. We're already doing that with our existing program. Should we want to add a 3rd rig in the future because prices remain strong down the road, we could make that decision.
I do think there is, you know, a fair amount of lead time that you would need to put in place. Again, I'll reemphasize that our two-rig program to date provides the growth that others may need to add a rig, to accomplish. Pleased with what we have, in our plan going forward.
Got it. Yep, that makes sense. Definitely a good program. I guess maybe just a quick follow-up on that and might be getting a little nuanced. As you think maybe early 2023 thoughts at this time, is a third rig a consideration, or is that kind of a to be determined at a later date?
Yeah, I think that is a to be determined at a later date. You know, as
Got it.
As we think about, you know, commodity prices and the flexibility of what's going on relative to the macro situation out there, whether it's China or Russia or OPEC, there's a lot of factors that come into play. I am a believer in where commodity prices are today. I think it's a sustainable system around where we are right now. That being said, we're not looking into 2023 yet to provide additional guidance.
What we are going to focus on is growing our business, our production as it stands right now at 10% to 15% year-over-year. That's where we're focused on. That's what we're going to execute and, you know, look forward to giving, you know, further 2023 guidance in coming quarters, if you will.
Got it. All right. Just one last question. Is there any updated thoughts on how quick that buyback pace could be out of the gates? I think you should reach your leverage target this quarter. Just wondering kind of given the free cash flow outlook that y'all increased for this year, I mean, is realistically could you exhaust that kind of a year-end or early next year, or kind is there any more color on that you can provide at this time?
I think you know it's a good question, particularly as we look at our cash flow. As you heard probably in my prepared remarks, we are increasing our free cash flow this year up from an estimated $400 million to greater than $550 million. Your point is valid as we think about that. I will say that we you know we've yet to begin the execution of that share buyback program, so look forward to beginning that in the near term and executing against that.
You know as we get towards the point where we are exhausting that share repurchase program, I do think there's additional opportunity to be incremental to that down the road.
Got it. Thanks for taking the questions.
Thanks, Davis.
Thank you. Once again, if you would like to ask a question, simply press star then the number 1 on your cell phone keypad. The next question comes from the line of Zach Parham from JPMorgan, your line is open.
Hey, guys. Thanks for taking my question. I guess first just an operational one. You all continue to drill and complete wells faster. As we get into the back half of the year, if these efficiencies continue, you know, how do you think about the capital program?
Would you consider, you know, raising the budget a little bit to potentially drive more turn-in-lines and maybe a bit more growth in 2023, or would you take a frack holiday kind? How are you thinking about managing that in the back half?
Yeah. Thanks, Zach. I think that first of all, it's a compliment to our operations team that we have been ahead of schedule, I would say significantly ahead of schedule, bringing on 6 more wells this quarter than originally anticipated. That's really an operational efficiency improvement. Should that continue throughout the rest of the year, I think we'll be towards the high side of our estimated completed wells for the year, which then of course translate likely to a towards the high end-is of our capital budget.
That being said, at this point, we're not moving our ranges, our guidance for capital. I do think that there's an opportunity there to have flexibility at the end of the year, whether that is pushing completions into next year.
Some of that will depend on commodity prices. Right now, I'm a fan of completing wells in these commodity prices, and so not building a significant DUC inventory. That being said, you know, there's a lot of things that can happen between now and the end of the year. Flexibility is key for us.
Again, with the efficiencies we've driven out of the field, we've got some real options down the road as to how many wells we're going to complete. You know, if that gives you some thought process and indication of where we can go by the end of the year, I hope that's helpful.
Yeah, that's great color. Certainly a good problem to have. I guess just one follow-up on the buyback. You've talked about getting started on that near term, so should we expect that you'll be repurchasing shares into Q? You know, if so, can you talk about, you know, potentially how aggressive you would be or how much free cash flow you would dedicate to cash returns in the near term?
Yeah. You know, we were very specific, I guess, in what we provided last quarter on leverage targets and whatnot before executing. As you probably heard and saw from the release, our quarter ended at 1.1x, and we have been very specific of reaching a leverage target of less than 1x before initiating our share buyback program.
That program is kind of two different ways of executing that, regularly timed buybacks as well as opportunistic repurchases. We will be executing that in the near term, and we're in the position to do that, but I can't be more specific as to when we'll be in the market. It doesn't make sense for us to release that information at this point.
All right. Thanks, guys. Appreciate the color.
Thanks, Zach.
The next question comes from the line of John Annis from Stifel. Your line is open.
Good morning, all. With the current commodity price environment driving inflationary pressures for the entire industry, I just 1st wanted to compliment you on holding the line on CapEx. With my 1st question, just building off of the previous questions on inflation, could you speak broadly to the % of remaining 2022 spend where you have locked in price and supply needed to execute your program?
Yeah, I can talk about that a little bit. You know, without revealing much in the way of the specifics around what we have or haven't locked in, I would say generally what we've sought to try to do is lock in you know portions of our sand in terms of fixed price costs.
So we've been able to kind work one deal currently. We've got about 50% of our sand termed up in a comfortable contract that we feel is competitive and below spot pricing.
The other thing we try to do, as I said, in an earlier Q&A question, is we try to order our steel far enough in advance for tubulars and things like that that we can you know accommodate you know the delays in terms of the production timing for steel costs. When you do that, there's you know portions of that that you can lock in in terms of cost as well.
At this time, based on what we can see, we don't anticipate seeing you know additional inflation relative to our steel pricing for the remainder of the year, just by virtue of what we've kind of been able to work through so far.
Then lastly, you know, the rigs are going to be termed up, and they're finished, you know, through the rest of the year. We don't anticipate, you know, incremental contractual increases in rates. We've already been through that with these two rigs, and we've had these 2 rigs in our service now for almost 2 years.
You know, we feel very good about where we are with those rigs and that vendor, as well as, like I said, the sand and the steel.
That's great. I appreciate the color. For my follow-up, with the understanding that you have 15 years of quality inventory that was highlighted by some strong wells this quarter, I wanted to ask how you see Centennial playing a role in industry consolidation and your views on the A&D market today.
Yeah. We continue to look for opportunities. I'd say we have a very active deal team. I doubt that there's been anything that's gone on in the Delaware Basin that we haven't at least been part of from a review point of view. I would say that we have very high standards. Because of that 15-year inventory, we're not out to fill a void from an inventory perspective. We are looking for opportunities that are accretive across a number of fronts. It has to be accretive financially, but also from an inventory perspective.
They don't have to compete for capital in the near term. We look at those opportunities, they have to be very specific in what they would add to our company going forward.
I do remain focused on trying to grow the company, both organically as well as inorganically, but we've got very specific needs, qualifiers, if you will, on adding any other opportunities to our existing base. What I don't want to do is dilute the shareholders, relative to inventory quality, and certainly not from a cash flow per share basis or anything like that. It's a very specific set of needs that any assets and/or companies would need to qualify for us to add it to our existing position.
That's great. Thanks for the time.
Thank you. Appreciate it.
We have a follow-up question from Davis Petros from RBC Capital Markets. Your line is open.
Hey, appreciate you adding me back into the queue. Just one last question. Y'all started to book a statutory GAAP tax rate this quarter. I think it was around 30%. Can you provide any more color on kind how we should think about that going forward, either for the rest of the year into 2023, and then as well as kind of an updated cash tax horizon?
Sure. Good morning, Davis. It's George. I'd say with respect to the rate you saw this quarter, that was kind of a one-time true-up related to a state apportionment rate, which gets a little bit complicated. I'll just kind leave it at that on why that 31% occurred. You're not likely to see that rate going forward. It should be much lower, at least in Q2. I think from a tax standpoint overall, you know, the first thing I'd say, it's fairly remarkable that we're discussing cash taxes so broadly within the industry.
That's my 1st observation. With respect to CDEV specifically, we're very fortunate to have a significant federal NOL position.
If you dig through our 10-K, you'll note that it's, you know, approximately $500 million at year-end 2021. We came into the year with a very meaningful tax shield. As we look at the current business plan, activity levels, commodity environment, we believe we're a couple years away from fully utilizing those NOLs and being a federal cash taxpayer. To summarize, you know, we're relatively well-positioned not to have any material cash tax liabilities in the near term.
Got it. Just to clarify, to make sure I'm thinking about it correctly, kind of 2Q onwards, that book tax rate probably going to be closer to peers around, I don't know, 20% to 25%, something like that, correct? Then cash taxes, they'll probably maybe 2024 beyond. Is that the right way to kind summarize that?
I think that's directionally okay way of thinking about it. I don't wanna specify.
Yep.
A specific percentage. It will be below 31% on the book tax.
Got it. Appreciate the time.
Thank you. We have reached the end of our Q&A session. I would now like to hand the conference over to our CEO, Mr. Sean Smith, for the closing remarks.
Thank you, Ludy. All I can say is that I'm very pleased with how the company is positioned. We have a bulletproof balance sheet, meaningful production growth, significant and sustainable free cash flow, and a robust shareholder return program that's been board approved. I believe that all of these trades are going to drive substantial value for our shareholders, and I look forward to the upcoming quarters. Thank you for listening today, and with that, we'll end the call.
Thank you. Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.