Permian Resources Corp

NYSE:PR

Earnings Call Transcript 2021-Q2

[Operator]

Good morning and welcome to Centennial Resource Development's conference call to discuss its second quarter 2021 earnings. Today's call is being recorded. A replay of the call will be accessible until August 11, 2021, by dialing [phone] and entering the conference ID number 5061685 or by visiting Centennial's website at www.cdevinc.com.

At this time, I will turn the call over to Hays Mabry, Centennial's Director of Investor Relations, for some opening remarks. Please go ahead.

[Hays Mabry, executive]

Thanks, Marjorie, and thank you all for joining us on the company's second quarter 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, August 3, we filed a Form 8-K with an earnings release reporting first (sic) [ second ] quarter earnings 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 risks 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 forward-looking statements sections of our filings with the Securities and Exchange Commission, including our quarterly report on Form 10-Q for the quarter ended June 30, 2021, 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.

[Sean Smith, executive]

Thank you, Hays. Good morning, and welcome to Centennial's second quarter earnings call. On today's call, George will first discuss our quarterly financial results. Matt will then provide an operational update, including recent efficiency improvements and well results. And then I'll follow with our updated financial targets, inventory depth and provide a high-level outlook for the remainder of 2021.

With that said, I'll turn the call over to George to review our financial results.

[George Glyphis, executive]

Thank you, Sean. From a financial perspective, this was a very strong quarter for the company. We delivered record free cash flow; lowered LOE, GP&T and cash G&A unit costs by approximately 20% in aggregate quarter-over-quarter; and significantly delevered the balance sheet, all while building the production base off of the Q1 low point.

Turning more specifically to our financials on Slide 13 of the earnings presentation. Net oil production for the second quarter rebounded by 13% from Q1 to approximately 31,900 barrels per day. Average net equivalent production totaled approximately 61,650 barrels per day, which was a 14% increase. Total revenues increased by 21% quarter-over-quarter to $232.6 million as a result of higher production levels as well as higher oil prices. Realized oil prices of approximately $61 per barrel were $8 higher than Q1, which drove a 32% increase in oil revenues.

Natural gas revenues declined from the unusually high Q1 levels, but continued to see the benefits of relatively strong WAHA pricing during Q2. NGL revenues were up 23%, mainly due to higher production and strong realizations equal to approximately 46% of WTI.

Turning to costs. We saw very strong metrics in our Q2 cost structure after the disruption from winter storm Uri in Q1. In general, unit costs benefited from continued cost discipline as well as higher production levels. LOE per barrel decreased by approximately 23% to $4.10 per barrel from $5.30 in Q1. Matt will discuss our cost initiatives in more detail later in the call, but this reduction is a product of the continued operational improvements realized year-to-date.

Cash G&A on a notional basis was down approximately 5% to $10.1 million, resulting in $1.81 per barrel for the quarter, which represents a 17% decline from Q1. We are pleased with these results and are continuing to focus on costs across all aspects of our business.

GP&T was $3.47 per barrel, down from Q1 on lower realized natural gas prices related to our percent of proceeds contracts. DD&A was $13.09 per barrel during the quarter, and we are pleased that for both Q1 and Q2, this metric is tracking towards the low end of our guidance range, which is a testament to the ongoing efficiencies and structural cost improvements that continue to be realized on both our drilling and completion processes.

Adjusted EBITDAX totaled approximately $127 million, up from $100 million in Q1, due primarily to higher production, higher oil prices and lower cash costs. Additionally, we generated approximately $34 million in free cash flow during the quarter, which was a record amount for the company and was primarily utilized to reduce borrowings under our credit facility. The combined effect of increasing cash flow and declining overall debt led to significant deleveraging during the quarter. Finally, we recorded a GAAP net loss attributable to our common stock of $25 million.

Shifting to CapEx. Centennial incurred approximately $83 million of total capital expenditures during the second quarter compared to $73 million in Q1. We ran 2 rigs and 1 completion crew, which drove 14 wells spud and 12 completions compared to 9 wells spud and 11 completions during Q1. Notably, while our drilling activity increased 56% on a well spud basis, and we completed approximately 26% more lateral feet than in the prior quarter, our CapEx only increased by 14% quarter-over-quarter. Approximately 98% of capital incurred was related to drilling, completions and facilities. Infrastructure and land capital totaled less than $1 million for the quarter.

On Slide 9, we summarized our capital structure and liquidity position at June 30. As we discussed on the previous earnings call, in April, we redeemed at par the 8% second lien note, which had been our earliest note maturity and highest coupon debt instrument in the capital structure. Now our first maturity will not be until early 2026. Liquidity during the first half of the year increased by over $100 million despite a flat $700 million of elected bank commitments. As of June 30, total liquidity was approximately $440 million based upon $255 million of credit facility borrowings, $4.7 million of cash on hand and $4 million of outstanding letters of credit.

As previously mentioned, the second quarter was a period of significant balance sheet deleveraging as our total debt-to-LTM EBITDAX declined by 1.3x from 4.3 to 3x. Importantly, we expect this dynamic to continue, which is supported by a hedging program that protects a portion of our cash flow in both the second half of 2021 and during 2022. By year-end, assuming current strip prices, we expect that our total debt-to-LTM EBITDAX metric will fall below 2x.

Finally, for calendar year 2022, we have hedged approximately 7,850 barrels per day at an average fixed price of $64.22 per barrel WTI. Additionally, we recently topped up our hedge position for the second half of 2021. We entered into 2,500 barrels per day of incremental oil swaps evenly split between WTI and Brent at fixed prices of $64.77 and $69.76, respectively. We also added 2,250 barrels per day of collars at attractive levels, which you can review in more detail on Slide 14 of the earnings presentation.

With that, I will turn the call over to Matt to review operations.

[Matt Garrison, executive]

Thank you, George. Q2 was an exciting quarter for the operations group. Turning to Slide 6. You can see that we continue to show improvement across several key areas. To start with, I'd like to discuss our improvements in cycle times. Quarter over quarter, our lateral lengths have increased 16% from around 8,100 feet in Q1 to around 9,400 feet in the second quarter. Despite longer laterals, our average spud to rig release decreased by 18% from 17.3 days on average in Q1 to 14.2 days in Q2.

We also set a new milestone for ourselves in New Mexico, where we drilled a 2-mile lateral in the Third Bone Spring Sand in just 8.6 days from spud to a total depth of 22,500 feet. This is a new Centennial record, and we are fairly certain it also ranks among the industry best in Lea County for extended reach laterals. This improved speed of operations has driven the total number of spudded wells in Q2 up approximately 56% from Q1.

As a geoscientist myself, it is important to note that we have not sacrificed the importance of geosteering for the sake of speed. We continue to execute at a very high level, drilling in the prescribed geologic target window for 97% of the time in Q2.

Our drilling department isn't the only one where we've seen continued improvements in both costs and cycle times. As I mentioned in the Q1 call, our facilities group has continued to focus on new designs that reduce costs on a per well basis while maintaining our high environmental performance. Compared to last year, facilities costs year-to-date have dropped 20% to around $800,000 per well. This reduction can be attributed to the fact that we have been building multi-well facilities that can easily be expanded to accommodate additional wells.

Shifting now to ESG. For the first half of 2021, Centennial achieved a gas capture rate of 98.6%. This number, while impressive, includes the impact of winter storm Uri during Q1. With continued efforts, we are still confident that we can achieve our full year goal of 99% gas capture and are appreciative of the efforts our employees and contractors have taken to keep gas capture as one of our top corporate initiatives.

Centennial also recently introduced its water recycling program in our Texas assets, following successful implementation in New Mexico during 2019. As a result, nearly half of the water used for completed wells during the second quarter consisted of reused water, further reducing capital and LOE costs, while also lowering our overall impact on the environment. Centennial is committed to water recycling wherever possible, and we anticipate further expansion in years to come.

Now turning to the recent well results on Slide 7. In New Mexico, the Chorizo State Com 501, 502 and 503 were drilled as a 3-well development, targeting the upper and lower Second Bone Spring Sand. Drilled at approximately 950-foot spacing, these 9,800-foot laterals delivered an average IP-30 of almost 2,300 BOE per day or approximately 1,900 barrels per day of oil. Furthermore, these wells continue to demonstrate a strong production profile, posting 60-day IPs over 1,600 barrels of oil per day on average.

Not only were the production results solid, but the Chorizos were drilled, completed, equipped and flowed back for an average cost of approximately $675 per lateral foot, which represents a material 45% reduction from our 2019 and 2020 development in the underlying Third Bone Spring Sand. This is tangible evidence of our structurally lower well costs and is a testament to the hard work of our operations team. Perhaps equally important is the fact that we saw no demonstrable evidence of well interference despite developing an overlying formation 1 to 2 years after initial production began in the Third Bone Spring Sand.

Staying in New Mexico, the Chimichangas State Com 602H was drilled in the Third Bone Spring Sand interval, also with a 9,800-foot lateral and delivered excellent results. This well reported an IP-30 of approximately 2,700 BOE per day with an 82% oil cut and achieved 227 barrels per day of oil per 1,000-foot of lateral. Notably, the Chimichangas produced an IP-60 of almost 1,800 barrels of oil per day, which we estimate ranks in the top 15% of wells drilled since 2018 in Central and Northern Lea County.

In Reeves County, Texas, the Powdered Donut State C13 and T15H wells came online in our Miramar block. Drilled as approximately 9,000-foot laterals, the Powdered Donuts were directly stacked in the Third Bone Spring Sand and Wolfcamp C intervals. These wells delivered an average IP-30 of over 2,500 BOE per day with a 43% oil cut or approximately 1,100 barrels of oil per day.

And there are 2 key items I'd like to point out on this pad. First, these wells were completed in the higher GOR northwest portion of our Reeves County position. Given the constructive market for gas and NGLs as of late, you can see why we're excited to have it in our portfolio. While an average IP-30 of roughly 1,100 barrels of oil per day is a solid result, when you include the incremental natural gas and NGL streams at current prices, the economics are robust. For this package of wells, we model well north of 100% rate of return at strip pricing and a sub-$5 per BOE finding and development cost.

Secondly, the most recent result is very encouraging as we have been conducting several tests in 2021 that co-develop Third Bone Spring Sand and Wolfcamp C intervals in Reeves County. A number of these tests have also been drilled in and around existing Wolfcamp A development areas. The initial tests of the Wolfcamp C have been positive and have demonstrated little, if any, interaction with preexisting development units despite developing both above and below our existing producing wells in the Wolfcamp A. The recent infill tests of both the Third Bone Spring and the Wolfcamp C bolster our confidence in our remaining inventory across the Texas acreage position and gives us a foundation from which to build future infill development scenarios.

We were able to deliver these solid well results in both our operating areas while demonstrating cost control, as higher operational efficiencies helped to offset increased oilfield service costs during the quarter. Overall, our average gross well cost during the quarter remained flat at approximately $800 per lateral foot, which includes facilities and flowback. Despite concerns of inflationary pressure in the back half of 2021, we still feel that our initial guidance range of $750 to $850 per lateral foot is an adequate assumption for well costs during the year. The improvements in our well costs and in the broader commodity markets have significantly enhanced the economic returns of our drilling program and our remaining inventory.

We remain focused on delivering meaningful free cash flow in future years. And we can do that by remaining laser-focused on our operational costs and efficiencies as well as properly executing our development plans. With that in mind, for the first half of 2021, we forecast the average payout of our development program to be less than 1 year at current strip pricing. This not only highlights the quality of our asset base, but also our employees, and I'm very appreciative of their hard work.

I know that I speak for the entire team when I say that we look forward to building upon this momentum during the remainder of the year.

And with that, I'll turn it over to Sean for closing remarks.

[Sean Smith, executive]

Thanks, Matt. As you can tell from George and Matt's remarks, our team continues to execute at a high level. I'm very pleased with our recent production results and continued cost control, which drove strong financial results for the quarter.

Turning to Slide 5 of the earnings presentation. I'd like to provide a status update on some of the goals we laid out earlier in the year. In February, we announced a 2-rig drilling program focused on free cash flow generation and organic deleveraging. And while that game plan hasn't changed, it has gotten considerably better since the start of the year. As a result of our lower cost structure, solid well results as well as higher commodity prices, we are significantly increasing our full year free cash flow estimate and decreasing our year-end leverage target. Previously, we forecasted roughly $65 million of free cash flow in 2021. When, in fact, through the first 2 quarters of the year, we've already generated $45 million in cumulative free cash flow and now expect to achieve between $140 million to $170 million of free cash flow by year-end.

Similarly, on the leverage side, we now expect to end the year below 2 turns and have a high degree of confidence of greater free cash flow and additional leverage reduction in 2022 with line of sight close to 1x leverage by year-end 2022, assuming strip prices.

Turning to our game plan for the remainder of the year. Despite the increase in commodity prices, we remain committed to our 2-rig drilling program and delivering upon a plan presented earlier in the year. As previously stated, our primary goals will continue to be free cash flow generation and further organic deleveraging, and our current program delivers exactly that. Thus, we'll continue the efficient development of our high-quality asset base through the co-development of multi-well pads with extended laterals, which is now underpinned by a significantly lower cost structure.

Prior to wrapping up, I'd like to touch on one more very important item. For several years now, inventory depth and quality have been given much less emphasis by the investment community. But I can assure you this will not be the case forever. Ultimately, the companies who thrive in this industry over the long term will be those who have long-dated inventory that generate strong returns even in a lower commodity price environment. That is why since our inception, Centennial has always focused on building and maintaining high-quality inventory depth.

With continued efficiencies and structural cost improvements, our well economics and inventory count keep getting better. As a result, Centennial sits in a very enviable position, in my opinion. Assuming our current 2-rig drilling program and $45 oil, which, obviously, we're well above today, we have over 15 years of economic inventory that will generate very solid returns over the long term.

In closing, on Slide 11, Centennial enjoyed a strong first half of the year and is well positioned for the remainder of 2021 and beyond. We continue to have high-quality assets located in the premier U.S. oil basin, along with the technical and operations team with a proven track record of driving costs down further. Over the past 4 quarters, we have demonstrated our enduring transition to generating sustainable free cash flow as a result of our expanded operating margins and expect our rapid pace of organic deleveraging to continue over time.

Ultimately, we believe these attributes will create additional long-term value for Centennial and its stakeholders.

Thanks for listening, and now we'll go to Q&A.

[Operator]

[Operator Instructions] Our first question comes from the line of Brian Downey from Citigroup.

[Brian Downey, analyst]

Maybe I'll start from Slide 6 in your prepared remarks. It's very apparent that you continue to push forward on the efficiencies front with your 2-rig program continuing to get more efficient. How should we think about that impacting go-forward production growth along with the puts and takes on capital spending cadence given your cost efficiencies? It seems like you're spudding more wells per quarter.

[Sean Smith, executive]

Yes, I appreciate that question. It's a great problem to have and that we're getting better in what we do, in that our spud to rig release times continue to come down, which is allowing us to drill more wells per year than originally anticipated, which is a great thing from an efficiency point of view. It also helps from a production point of view as we think about the back half of the year. I still think we're comfortable with the guidance range that we provided on production, although the back half of the year will be stronger than the first half of the year based on the wells that we're going to bring online.

The capital is similar to that, though, right? As I mentioned, I think, on the first quarter call, we are drilling more wells than we originally anticipated. So that will put a little bit pressure on the upside of our capital guidance. So I would steer you towards that. That being said, the efficiency we're seeing in the dollars per foot is still well within our guidance range and feel very comfortable on a per foot basis how we're drilling and completing these wells.

[Brian Downey, analyst]

Great. And then maybe one on the hedging front. You outlined the incremental hedges added for the second half of this year and into 2022 and how you expect to end the year sub-2x leverage. Could you give us any updated thoughts from your recent hedging team discussions on how the team is thinking about next year? How much cash flow and organic deleveraging to lock in versus retaining commodity price exposure?

[Sean Smith, executive]

Yes. Maybe I'll let George take that who leads our hedging team.

[George Glyphis, executive]

Yes. I think we're, obviously, very mindful to have a balanced approach to hedging. We feel, number one, very good about our 2022 book at this point with hedges at $64.20, give or take. And so we're pretty happy about that. And as Sean mentioned, we're on a deleveraging path that, that hedge program will help support. We do think that balance is important. We like hedges because they protect our operational activity to some degree. And so you can help underpin kind of steady rig activity and completion activity. And we're going to continue to look at the curve, and there's obviously been a lot of volatility.

But we think at the levels we have today for cal '22, we're very comfortable with where we are. We expect that in the coming quarters, we will probably add to that. But I think that, as I mentioned before, balance is the key attribute here in terms of how we're locking in those prices. It bears reminding, even though we've delevered very significantly in this quarter and expect that to continue, we're still a 3x levered company, and no one can fully predict oil prices. And so we think it is prudent to layer on that protection while again maintaining some balance.

[Sean Smith, executive]

And I'll just follow up on that, George. It's -- I'm excited that we are going to end the year likely below 2x. I think that's fantastic. What we've said in the past is that we'd like to be below 1.5x by year-end next year. I think with the prices where they are and with our hedging program, our thoughts are that we'll be, as I mentioned in the prepared remarks, much closer to 1x by year-end next year. And that's just an outstanding progress towards our leverage goals, and I think it puts us in a very good position going forward.

[Operator]

Your next question comes from the line of Leo Mariani from KeyBanc.

[Leo Mariani, analyst]

I wanted to ask a little bit about production trajectory here. I think you guys had stated earlier in the year that the production mix was supposed to get oilier as the year progressed. Looks like there was kind of a slight downtick in your oil cut in the second quarter. I know you had some wells that you brought on that are producing more gas. Clearly, gas price outlook is a lot better than it was at start of the year. So just want to get a sense of what we can expect in terms of how that oil cut evolves for the rest of the year.

[Sean Smith, executive]

Yes, Leo, thanks for the question. I think we did brag a little bit about one of our pads, the Powdered Donut, in our Miramar area, which does have a lower oil cut or a higher GOR. The economics are outstanding with the gas prices and NGL prices we're receiving, on top of it, delivering 1,100 barrels of oil a day. So that area is great for us. Obviously, that impacts your percent oil a bit. Overall, though, I think that we are still within the range that we provided early in the year. I think we're still going to focus 70% of our capital for the year in New Mexico, which tends to be a bit more oily than our Texas assets. So I think the range that we provided for the year is still appropriate.

[Leo Mariani, analyst]

Okay. So it sounds like you would expect oil cut to maybe improve a little bit in the second half? Just wanted to confirm that.

[Sean Smith, executive]

Yes, it should be slightly higher than what we have realized to date.

[Leo Mariani, analyst]

Okay. And then just on your unit costs, you guys highlighted this, but very low cost here in the second quarter. Just wanted to get a sense, I mean, are these sustainable in terms of how low they were? Or is there somewhat of an anomalistic situation? Should these be flattish from here as we get into the second half? Or do you think they tick up? Just any color you have on the unit costs would be great.

[George Glyphis, executive]

Sure. Leo, it's George. First of all, we're very, very happy with how Q2 came in. And obviously, the production increase was helpful. But our notional LOE costs were very strong. There was a tad bit of kind of one-off credits that occurred in Q2. So I'd say that for the year, that's probably the low point from a dollar per BOE standpoint. And I'd say Q1 is the high point. I think as we look at the second half of the year, you'll see an uptick slightly from what we saw in Q2, but we feel very good about our guidance range and, in fact, kind of trending towards the lower half of that range as we move into year-end. So overall, a very good result, and we feel very good about our LOE cost.

[Leo Mariani, analyst]

Okay. And I guess, how about any of the other costs like TG&P or anything like that or G&A? Any kind of color on those?

[George Glyphis, executive]

Yes. In terms of G&A, I mean, as I mentioned in my portion of the script, we were down on a notional basis and $1.81 per barrel was very strong. I'd say on that one, too, kind of tracking through year-end, we feel pretty good about being towards the lower half of our guidance, I'd say. And we'll just see how production shakes out. But we're spending a lot of time focusing on our G&A costs and kind of turning over every rock in terms of how we can save money from a corporate standpoint, otherwise. So a good result there as well.

[Operator]

Your next question comes from the line of Neal Dingmann from Truist Securities.

[Neal Dingmann, analyst]

Sean, my first question's for you. Your point on the inventory depth, I think, is well taken. You guys have done a great job there. I'm just wondering, could you talk on -- I guess my question around that is when you look at the sort of multi-formations that you're continuing to tackle, are you continuing to be optimistic that you'll continue to actually add locations as you've done over the course of the last several quarters? I mean, is there more potential for more as you keep doing some of these multi-formation pads and all?

[Sean Smith, executive]

Yes. Great. Neal, first of all, I think we're really excited about where we're at from an inventory position. I do think it's important for not just us, but the industry to really focus on, particularly as people start talking about shareholder returns and the sustainability of those shareholder returns, you're going to need quality inventory to maintain those returns over a long period of time. And so I think one of the things we're most proud about is our inventory depth that generates very solid returns, as I mentioned, in a much lower commodity price environment that we're seeing today. So feel good about that.

To your question about count, I think we've done a good job delineating a fair amount of our productive zones, both in New Mexico and in Texas. We have recently been on more of a lower Wolfcamp campaign, if you will, testing out certain spacing in different units and pushing the limits of what we knew previously. And the Powdered Donut is a great example. It's not our only one. We've done several tests now where we are combining both a Third Bone Spring Sand test with a Wolfcamp C test, which brackets in, I'll mention the Wolfcamp A that has been previously developed, and we're seeing some very promising results both in the Third Bone Spring as well as the Wolfcamp C.

So from a count perspective, will we add a bunch more? I would say that most of where we think it's productive today has been -- is in that 15-year count. There's always room for some additional locations to be added as we push the limits of what we have mapped as productive today. But I think right now, I feel very good about the zones that we've delineated and how we are counting those locations in our total inventory.

[Neal Dingmann, analyst]

Great, great details. And then my follow-up just for George, for you on hedges. I know in the past, you've been kind of forced with the banks on some of the things you've had to put in. And now I look at your position, I think it's nice. You've got nice baseline hedges, but yet some upside room. Could you talk about, I guess, sort of going forward your philosophy now and then also going forward, once you even get the -- obviously, the balance sheet is going in the right direction, leverage is going in the right direction. Once you get leverage down to even a level you're even more comfortable with, what you would think about hedges there?

[George Glyphis, executive]

Yes. I think the first thing, frankly, the banks have not forced us to hedge. That's been something that we've certainly encouraged it, but there's nothing in our credit agreement that forces us to hedge. So those have been voluntary, but we've been very, very pleased, particularly with where we sit in the back half of this year for cal '22 on the hedges. And if you look at our cal '22 book, we've kind of front-loaded it where the volumes are more heavily weighted to the first half of the year.

If you look at the aggregate hedges for 2022, about 65% of those are in Q1 and Q2. As we continue to delever, our cost here towards the amount of hedging we'll do will probably evolve a bit. I think you need to figure out where the balance sheet is at the point in time we make decisions to hedge less. But I think, historically, the industry has been too levered and has -- companies have had too much debt, which has forced them to have a pretty robust hedge book.

And I would expect that over time, as balance sheets improve and credit quality improves, I think the industry as a whole will have a little bit more flexibility relative to hedge requirements and hopefully, that translates through to the requirements of the financial community and the lenders. So that's a big TBD, but I do expect for us that we will try to manage that pretty carefully and make sure that we're -- I think balance is the key word here that we're being prudent in terms of protecting our downside, but also giving our stakeholders upside in the commodity price.

[Neal Dingmann, analyst]

Agree. Definitely like that balance.

[Sean Smith, executive]

Thanks, Neal.

[Operator]

Your next question comes from the line of Chris Dendrinos from RBC Capital Markets.

[Christopher Dendrinos, analyst]

I guess just kind of following up here on Leo's question in regards to per unit expenses. It looks like some of those liability rewards that settling cash could invest here in September. And I know, I guess, it's not kind of incorporated in your G&A cost guidance. So could you kind of comment on what the expectation is for any, I guess, potential cash payments related to those would be?

[George Glyphis, executive]

Sure. I think the first comment I'd make is we - when we talk publicly about G&A, we tend to focus more on cash G&A, which are the numbers I was rattling off earlier in the call in terms of $1.81 for the quarter and kind of notional cash G&A going down 5% from Q1 to Q2. So that's our point of focus.

On the stock compensation, there is a portion of that, that is subject to a fair value calculation at the end of each quarter that causes those expenses to swing. And it's all driven by our share price and the fact that our share price has performed very well year-to-date, I think, is driving a lot of that noncash charges that you see on the income statement. And so it's not something that we can control, and it's frankly difficult to forecast.

So with respect to the Q3 liability awards, there is very likely to be a cash payment associated with those awards, which, frankly, is terrific for our employees, having seen an increase in our share price and a lot of what we pay from an LTI, long-term incentive compensation standpoint is tied to the stock price. And so we think there's good alignment there between our employee base and how the company is doing overall. And so you will see a cash payment in Q3. It's frankly not -- in terms of the scheme of things, it's not a massive number. It's very manageable. And we kind of bake that into our thoughts as we think about free cash flow and debt repayment through the balance of the year, but it's not a hugely material amount.

[Christopher Dendrinos, analyst]

Got it. Okay. And I guess just kind of shifting gears here on the activity levels. Thinking about next year, obviously, you guys haven't provided guidance yet, but I guess is it safe to assume that under a 2-rig program, activity levels would be, I guess, a bit higher than this year and that would kind of lead towards some incremental, I guess, oil production growth? And then, I guess, any color around like what you're thinking about right now in terms of capital spending?

[Sean Smith, executive]

Yes, I appreciate the question. Obviously, we can't give too much from a forward-looking guidance perspective. But that being said, I think you can expect us to be in this 2-rig scenario. Maintenance capital is what we assign to a 2-rig world. But as you've said, with the increase in efficiencies, we're drilling more wells, which is causing more production to come online. So I do expect to see high single, low double-digit growth next year on that same 2-rig program, somewhere in that line. And so that is to be expected. We will drill and complete slightly more wells than what we did this year because we have gotten better throughout the year. So I think your assumptions are correct, Chris.

[Operator]

Your last question comes from the line of Zach Parham from JPMorgan.

[Zachary Parham, analyst]

Your D&C costs ticked a little higher this quarter, $800 per foot from $795 last quarter, despite your lateral lengths extended by about 16%. I'm sure you're starting to see some cost inflation in the field, just given oil prices. Can you talk -- just give us a little color maybe on what you're seeing in the field on cost inflation and maybe how you see that trending in the back half of the year into 2022?

[Matt Garrison, executive]

Sure. Yes. This is Matt. Yes, we have realized and seen inflation in the first half of the year, much like pretty much everyone else in the business. It's primarily been focused in a couple of areas with regard to things like tubulars, sand and labor and such. Yes, we are feeling the impacts of that. But we -- in Q2, we did some things to kind of pivot, and we drilled on average longer laterals, as I alluded to in the call. And we've been trying to do things like that to combat some of those rising inflationary pressures.

We are actually very proud of the fact that here we are sitting halfway through the year, and for 2 quarters have been able to hold the line on the midpoint of our capital guidance range, frankly, on our costs. And so I think given kind of the bottom-out point in Q1 and given what we've started to see in Q2, we've got ourselves in a pretty good spot to be able to further combat those kinds of things in the back half of the year.

Some of the things that we're kind of doing to lock in those costs are -- and to kind of to try to hold the line, if you will, on those things, are locking in certain portions of our cost buckets, namely things like rigs; rig costs, we've been able to secure through year-end; sand costs; tubulars and wireline. We've tried to fix those costs so as to not necessarily see increasing pressure in those particular categories.

But one of the other things we're doing is we're going to focus more in the back half of the year on larger pad developments. So a little bit less in terms of the rig moves and moving them around, particularly between states. We're going to focus more in New Mexico in the back half of the year. That's going to kind of bring up -- to hit those numbers, Sean alluded to earlier, we're roughly 70% or so of our total production for the year and our activity will come from New Mexico. I would expect the back half of the year to be largely focused in field in New Mexico, which will allow a lot more efficiencies with regard to just kind of the mobilization costs and things like that.

But we still are optimistic of our full year guidance, tapping out somewhere between $750 and $850 a foot. But given the fact that here we are halfway through the year kind of at the midpoint, I would expect in the back half of the year, somewhere between the midpoint and the high end is where we're going to end up probably for the end of the year.

[Zachary Parham, analyst]

That's great color. I guess just one follow-up. This morning, we saw a transaction announced by another Delaware Basin peer kind of right in your neighborhood. That follows a June deal by some private operators, also in Reeves County. You've talked about trying to gain scale and potentially participating in M&A. Maybe can you just give us your updated thoughts on M&A in light of the deals we've seen recently?

[Sean Smith, executive]

Sure. Yes. I appreciate you point that out. It's -- obviously, that announcement came out maybe late last night or this morning. And kudos to those guys for getting a deal done in this environment. Anytime you can get either of those deals that you're referring to done, they're both large transformative deals for those companies. So kudos for them and their team for getting that done. We continue to think that consolidation is a good thing that increasing the size and scale of particular companies to lower corporate costs overall is a good thing, whether that's our company or others. So I applaud the effort.

I think that those 2 transactions that you mentioned shine a positive light on the Southern Delaware that there are areas where you can generate very attractive returns, which we've known for quite some time. And I think there's some recognition there that people want to move into that area. So I think that's a positive.

From our perspective, we continue to be active. We -- there's very few things out there that we haven't at least considered, but we've got a pretty high threshold internally that we need to meet. I mentioned 15 years of inventory already. So making an acquisition just for inventory doesn't make a lot of sense for me or for the company. So we've got certain metrics that we need to clear before we think it's accretive to our stakeholders. It needs to lower unit costs. The inventory that does come in has to compete immediately for capital. And so our bar's set very high relative to any assets or companies that we would think about bringing into our fold.

That being said, I am a believer in size and scale, and so we'll continue to be active in that market. But what I'm not going to do is lever up the company just to get bigger. It has to be bigger and better. It's the only way, I think, to gain value for the shareholders.

[Operator]

There are no further questions at this time. This concludes today's conference call. Thank you, everyone, for participating. You may now disconnect. Have a great day.