Q2 2021 Centennial Resource Development Inc Earnings Call
Second quarter 'twenty 'twenty 1.
Today's call is being reported I would you play of the call will be accessible until August 11, 2021 by dialing 855859.
<unk> 056, and entering the conference IGN number 5 zero.
1685 or by visiting Centennial's website.
Total U W had thought.
D E P I N C dot com.
This time I will turn the call over to Heath neatly Centennial's director of Investor Relations for some opening remarks. Please go ahead.
Thanks, Marcia Reed and.
And thank you all for joining us from the company's second quarter earnings call.
Presenting on the call today are Sean Smith, our Chief Executive Officer.
George Glimpses, our Chief Financial Officer.
And Matt garrison, our Chief operating officer, Yes.
Yesterday August 3rd we filed a form 8-K with an earnings release reporting first quarter earnings results as well as the uppers operational results for the company.
We also posted an earnings presentation to our website that we will reference during today's call.
Can find the presentation on our website homepage or.
Or under presentations at Www Dot Sidoti Inc. Dotcom.
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 this.
Securities and Exchange Commission.
Included in <unk>, including our quarterly report on form 10-Q for the quarter ended June 30th 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.
Thank you <unk> 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 <unk>.
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.
Thank you Sean.
From a financial perspective, this was a very strong quarter for the company.
We delivered record free cash flow.
Lowered low G P in tea and cash G&A unit costs by approximately 20% in aggregate quarter over quarter.
And significantly de Levered, 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 31900 barrels per day.
Average net equivalent production totaled approximately 61650 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.
Gas revenues declined from the unusually high Q1 levels, but continued to see the benefits of relatively strong wahhab pricing during Q2.
NGL revenues were up 23%, mainly due to higher production and strong realizations equal to approximately 46% of W. P.
Turning to costs.
We saw very strong metrics in our Q2 cost structure after the distressed disruption from winter storm Yuri in Q1.
In General unit cost benefited from continued cost discipline.
As well as higher production levels.
LOE per barrel decreased by approximately 23% to $4.10 per barrel from 530 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 a $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 across all aspects of our business.
G. P. M. 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 $13.9 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. It was primarily utilized to reduce borrowings under our credit facility.
The combined effect of increasing cash flow and declining overall that led to significant deleveraging during the quarter 5.
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 12 completions compared to 9 wells spud and 11 completions during Q1 <unk>.
Notably, while our drilling 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 summarize our capital structure and liquidity position at June 30th.
As we discussed on our 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 'twenty 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 30th 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 1.3 times from 4.3 to 3 times.
Importantly, we expect this dynamic to continue which is supported by our 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 2 times.
Finally for calendar year 2022, we have hedged approximately 7850 barrels per day at an average fixed price of 64.
And <unk> 22 per barrel W. T. I. Additionally, we recently topped up our hedge position for the second half of 2021.
We entered into 2500 barrels per day of incremental oil swaps excuse me evenly split between W. T I and Brent.
At fixed prices of $64.77, and $69.76, respectively.
We also added 2200.50 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.
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.
Over quarter, our lateral lengths have increased 16% from around 8100 feet in Q1 to around 9400 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 and just 8.6 days from spud to total depth of 22500 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 spud 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 geo steering 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 1 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 $800000 per well.
This reduction can be attributed to the fact that we had been building multi well facilities that can easily be expanded to accommodate additional wells.
Shifting now to ESG.
For the first half of 2020.1.
Centennial achieved a gas capture rate of 98, 6%.
This number while impressive includes the impact of winter storm Yuri 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 is 1 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 per completed wells during the second quarter consisted of reused water first.
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 that Chorizo State Com 501, 5 O 2.5 or 3 were drilled as a 3 well development targeting the upper and lower second bone spring sand.
Drilled at approximately 950 foot spacing. These 9800 foot laterals delivered an average IP 30 of almost 2300 Boe per day or approximately 1900 barrels per day of oil.
Furthermore, these wells continue to demonstrate a strong production profile posting 60 day Ips over 1600 barrels of oil per day on average.
Not only with our production results solid.
But the chorizo 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 Jimmy Chagas State Com 6 O..2 age was drilled in the third bone spring sand interval.
Also with a 9800 foot lateral.
And delivered excellent results. This well reported an IP 30 of approximately 2700 Boe per day.
With an 82% oil cut.
And achieved 227 barrels per day of oil.
Per 1000 foot of lateral.
Notably the Jimmy Choo has produced an IP 60 of almost 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 Donuts state see 13, and <unk> 15 H wells.
Came online in our Miramar block.
Drilled is approximately 9000 foot laterals, the powdered donuts would directly stack and the third bone spring sand and Wolfcamp C intervals.
These wells delivered an average IP 30 of over 2500 Boe per day with a 43% oil cut for approximately 1100 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 G. O R 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 1100 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.
In a sub $5 per Boe, finding and development cost.
Secondly.
The most recent results 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.
The initial tests of the Wolfcamp C had 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 flow back.
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.
And we can do that by remaining laser focused on our operational cost 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.
Thanks, Matt as you can tell from Georgia match 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 Hasnt 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 pre.
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 1 times 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, we will continue to be free cash flow generation and further organic deleveraging in our current program delivers exactly that.
Thus, we will 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 1 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 were 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 overtime. Ultimately we believe these attributes will create additional long term value for Centennial Andy.
Stakeholders, Thanks for listening and now we'll go to Q&A.
The question and answer session will be conducted electronically if you would.
Like to ask a question please do so.
Great question as far as the number 1 from your telephone keypad.
Questions are limited to 1 question and 1 follow up question. If you would like to withdraw your question press the pound key.
Our first question comes from the line of Brian Johnson from Citigroup.
Sir your line.
Hey, good morning, Thanks for taking my questions, maybe I'll start from slide 6 in your prepared remarks, its 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.
On capital spending cadence given your cost efficiencies, but seems like youre spotting more wells per quarter.
Yes, I appreciate that question, it's a it's a great problem to have and that we're getting better what we do and 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 you know 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 in the first quarter call.
We are drilling more wells than we originally anticipated so that will put a little bit of 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.
We're drilling and completing these wells.
Great and then maybe 1 on the hedging front and you outlined the incremental hedges added from the second half of this year and into 2022, and how you expect to end the year sub 2 times 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.
Organic deleveraging to lock in versus retaining commodity price exposure.
Yeah, maybe I'll, let George take that who leads our hedging team.
Yes, I think.
We're obviously very mindful to have a balanced approach to hedging we feel very good about our 2022 book at this point with.
Hedges at $64 in 2.
<unk> give or take and so we're pretty happy about that.
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.
So.
You can you can help underpin kind of steady rig activity and completion activity.
And.
We're going to continue to look at that.
The curve and there's obviously been a lot of volatility, but we think.
At the levels, we have today for Cal 'twenty, 2 we're very comfortable with where we are we expect that in the coming quarters, we will probably add to that but.
But I think the.
As I mentioned before balance is the key.
Key attribute here in terms of in terms of how we're we're locking in those prices.
It bears reminding even though we've de levered very significantly in this quarter and expect that to continue.
Still at 3 times Levered company and no 1 can fully predict oil prices and so we think it is prudent to layer on that protection.
Again.
Maintaining some balance.
And I'll just follow up on that George you know, it's I'm excited that we are going to eat in the year likely below 2 times I think that's fantastic. What we've said in the past is that we'd like to be below 1 and a half times by year end next year, I think with the prices, where they are and with our hedging program. Our thoughts are that will be as I mentioned in the prepared remarks.
Works much closer to 1 times 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.
Great I appreciate the comments.
It's Brian.
Your next question comes from the line of Leo Mariani from Keybanc.
Hey, guys wanted to ask a couple about production trajectory here I think you guys had stated earlier in the year that the production mix was supposed to get oil here as the year progressed. It looks like there was kind of a slight downtick in your oil cut in the second quarter. I know you had some some wells that you brought on how they're producing.
More gas clearly gas price outlooks, a lot better than it was you know we start the year or so.
To get a sense of what we can expect in terms of how that oil cut evolves for the rest of the year.
Thanks for the question I think you know, we did brag a little bit about our 1 of our pads the powdered donut and our Miramar area, which does have a lower oil cut or a higher G. O R. The economics are outstanding with the gas prices and NGL prices were receiving on top of it delivering 1100 barrels of oil today.
So that area is great for us obviously that impacts your 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.
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 yes, it should be slightly higher than what we have realized to date. Okay. And then just on your unit costs you guys highlighted this but very low cost here in.
In the second quarter, just wanted to get a sense I mean, it is sustainable in terms of how low they were reserves somewhat of a anomalistic situation, yeah or should these be flattish from here as we get into the second half where you think they tick up just any color you had any unit costs would be great.
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 LNG costs, where we're very strong there was a tad bit of kind of 1 off credits that occurred in Q2, So I would 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 from what we saw in Q2, but we feel very good about our guidance range of impacts kind of trending towards the lower half of that range.
As we move into 2 year round. So overall a very good result.
We feel very good about our low cost.
Okay, and I guess, how about any other costs like T. G N P or anything like that or G&A any kind of color on this.
Yes in terms of G&A I mean, as I mentioned in my portion of the script, we were down on a notional basis.
$1.81 per barrel was very strong.
<unk>.
I would say on that 1 too.
Kind of tracking through year end, and 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.
Kind of turning over every rock in terms of.
How we can save money from a corporate standpoint and otherwise so.
Good results there as well.
Thank you.
Thanks Lou.
Your next question comes from the line of Neal Dingmann from J P.
Yes.
Good morning, John My first question is for you you point on the inventory depth I think this will take and you guys have done a great job. There I'm just wondering could you talk on you know I guess my question around that is when you look at the sort of multi formations that that youre continuing to tackle you know are you continuing to be optimistic that youll.
Continue to actually add locations as you've done.
Over the course of the last several quarters. I mean is there is there more potential for more did you keep doing some of these multi formation pads and all.
Yeah, Great Wonder 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 stop start talking about shareholder returns.
And the sustainability of those shareholder returns youre going to need quality inventory to maintain those returns over a long period of time and so I think 1 of the things. We're most proud about is our inventory depth. It 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 quest.
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 and different units and pushing the limits of what we knew the new previously.
And the powdered Donuts is a great example, it's not our only 1 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 al mentioned 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, when we add a bunch more I would say that the most of where we think its 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 in how we are counting those locations in our total inventory.
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 force with the banks on on some of the things you'd have 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 to the balance sheet has gone in the right direction leverage to go in the right direction once you get leverage down to EBITDA.
Level Youre, even more comfortable with what you would think about hedges there.
Yes, I think the.
First thing.
Frankly, the banks.
Have not force supposed to hedge that's been something that we've certainly encouraged if theres nothing in our credit agreements it forces us to hedge.
So those have been voluntary but we've been very very pleased particularly with with where we sit at the back half of this year.
For Cal 'twenty 2 on the hedges and if you look at our Cal 'twenty 2 book.
Frontloaded it where.
The volumes are more heavily weighted to the first half of the year. If you look at the aggregate hedges for 2020 to about 65 per cent of those are in Q1 and Q2.
As we continue to Delever.
<unk>.
Our posture towards the amount of hedging will do will probably evolve a bit.
Thank you.
You need to figure out where the balance sheet is at the point in time, when we make decisions to hedge less but I think historically the industry.
Has been to lever and headset companies who've had too much debt, which is force them to have a pretty robust hedge book and.
I would expect that over time.
Those balance sheets improve in 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 big TBD, but I do expect for us.
We will try to manage that pretty carefully and make sure that we're I think balance is the key word here.
Being prudent in terms of protecting our downside, but also giving our stakeholders upside in the commodity price.
Great definitely liked that balanced thanks, guys. Thanks.
Thanks Neil.
The next question comes from the line of Chris <unk> from RBC capital markets.
Hi, yes. Thank you I guess just kind of following up here on Leo's question in regards to a pretty inexpensive it looks like.
Some of those liability rewards that settle in cash could could've vast here in September and I know I guess, it's not kind of incorporated in your 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.
Sure I think the first comment I'd make is.
When we talk publicly about G&A, we tend to focus more on cash G&A, which are the numbers I was rattling.
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.
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 prices performed very well.
Year to date I think is driving a lot of that noncash charges that you see on the income statement. So it's not not something that we can control and it's frankly difficult cost so.
With respect to the to the Q3 liabilities.
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 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.
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 and frankly not.
<unk>.
In terms of the scheme of things, it's not a massive number that's very manageable.
Kind of baked that into our thoughts as we think about free cash flow and debt repayment through the balance of the year, but it's not hugely material amount.
Got it okay. Thank you and I guess, just kind of a shift.
Shifting shifting gears here.
On activity levels thinking about next year, obviously, you guys haven't provided guidance yet but.
You know I guess is it safe to assume that you know under a 2 rig program activity levels will be I guess a bit higher than this year and that would kind of lead towards some incremental I guess the oil production growth and then I guess.
You know any any color around like what youre thinking about right now in terms of capital spending.
I appreciate the question, obviously, we can't give too much from a forward looking guidance perspective with that being said you know I think you can expect us to be in this 2 rig scenario maintenance capital is what we assigned to a 2 rig a world, but as you 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 a high single low double digit growth next year on that same 2 rig program somewhere in that that line and so that is to be expected.
You know, 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 are correct Chris.
Great. Thank you.
Thanks for the questions.
Your last question comes from the line of Jack Paar Ham from Jpmorgan.
Hey, guys. Thanks for taking my question.
Your D&C costs ticked up a little higher this quarter $800 per foot from 17.95 last quarter. Despite your lateral links extended by about 16% I'm.
I'm sure you're starting to see some cost inflation in the field just given oil prices do.
Can you talk just give us a little color maybe on what youre seeing in the field cost inflation and maybe how you see that trending in the back half of the year into 2022.
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 has primarily been focused.
A couple of areas.
With regard to things like tubular is 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 an average longer laterals as I alluded to in.
In the call.
And we've been trying to do things like that to combat some of those those rising inflationary pressures we are actually very proud.
The fact that you know here, we are sitting halfway through the year.
And for 2 quarters have been able to hold the line on the mid point of our of our capital guidance range frankly on our costs and so so I think you know given 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 were kind of doing to lock in those costs are.
To kind of 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 tubular and wireline, we've we've tried to fix those costs.
So as to not necessarily see increasing pressure in those particular categories.
But you know 1 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 little bit less in terms of the rig moebs and moving them around particularly between states.
Moving 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 and 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.
We are optimistic of our of our full year guidance.
Tapping out.
Between 750, and <unk> hundred 50, a foot, but given the fact that you know 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.
The end of the year.
Thanks for that.
Great color I guess, just 1 follow up this morning, we saw a transaction announced by another Delaware basin peer kind of right in your neighborhood that follows the June deal.
But from 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.
Sure Yeah I appreciate you pointing 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 theyre. 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.
Net increasing.
The size and scale of particular companies to lower corporate cost overall is a good thing whether that's our company or others. So I I applaud the effort I think that those 2 transactions that you mentioned.
Shai in 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 are some some recognition there that people want to move into that area. So so I think that that's a positive from our perspective, we continue to be active we there's very few things out there that we haven't considered.
But we've got a pretty high threshold internally that we need to meet I mentioned to 15 years of inventory already so I'm, 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 to clear before we think it's accretive.
To our stakeholders and needs to lower unit costs.
Inventories that does come in has to compete immediately for capital and so our bars 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 will continue to be active in that market, but what I'm not going to do is is lever up the company just to get bigger it has to be bigger and better as the only way I think to gain value for the shareholders.
Got it thanks, guys. That's all from me exact I appreciate it.
There are no further questions at this time this cash.
Includes today's conference call. Thank you everyone for participating you may now disconnect have a great day.
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