Q2 2023 Antero Resources Corp Earnings Call
Greetings and welcome to the Antero resources second quarter 2023 earnings Conference call. At this time all participants are in a listen only mode. A brief question and answer session will follow the formal presentation. If anyone should require operator assistance. During the conference. Please press star zero on your telephone keypad.
And as a reminder, this conference is being recorded.
It is now my pleasure to introduce to you Brendan Kruger VP of finance. Thank you Brendan you may begin.
Thank you.
Good morning, Thank you for joining us for Antero <unk> second quarter 2023, Investor Conference call, we'll spend a few minutes going through the financial and operating highlights and then we'll open it up for Q&A.
I would also like to direct you to the homepage of our website at Www Dot Antero resources Dot Com, where we have provided a separate earnings call presentation that will be reviewed during today's call.
Today's call may contain certain non-GAAP financial measures. Please refer to our earnings press release for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures.
Joining me on the call today are Paul Rady, Chairman and CEO and President.
Michael Kennedy CFO .
<unk> long ago, Senior Vice President of liquids marketing and transportation and Justin dollar Senior Vice President of natural gas marketing I will now turn the call over to Paul.
Thank you Brandon.
I'll start my comments on slide number three titled drilling and completion efficiencies.
After a record breaking first quarter operationally strong momentum continued in the second quarter completions.
Completion stages averaged more than 11 per day in the second quarter, a 40% improvement compared to the 2022 average and over a 90% increase from 2019 levels drill.
Drill outs, which are the process of drilling out the plugs in each stage of the horizontal portion of the well exhibited the same success during the quarter.
Drill outs averaged over 4000 feet per day during the second quarter up 9% from the 'twenty to 'twenty, two average and over 50% increase from the 2019th levels.
Faster drill outs and completion times have resulted in significantly shorter cycle times as shown on the bottom of the page since 2019, our cycle times have decreased by 65% and averaged just 151 days in the second quarter.
In June we had the fastest cycle times in our company history at 129 days each.
These cycle times reflect the total number of days. It takes on average from first spud on a pad to turning the entire pad to sales.
As a reminder, we averaged six wells per visit per pad.
Shorter cycle times mean higher capital efficiency.
Highlighting this point, we completed roughly 60% of our 2023 budgeted completion stages Derrick.
First six months of 2023.
Now, let's turn to slide number four titled Antero Wells continue to outperform peers.
In addition to the drilling and completion records, we continue to see increases in well productivity.
The chart on this slide highlights well productivity trends versus our peers since 2020.
As illustrated on the page Antero has averaged cumulative equivalent production per well is 20% higher than the peer average over this time.
This differentiates <unk> from its peers with many companies having already drilled their best acreage our long core inventory life continues to deliver stronger results results each year.
Now, let's turn to slide number five.
Faster cycle times, and improving well performance led to the increase in our 2023 production guidance.
This gain in capital efficiencies as highlighted by our 5% total production growth in the second quarter compared to the year ago period.
Our production growth was driven by 16% liquids growth, while natural gas was essentially flat year over year.
These capital efficiency gains also reduced our maintenance capital budget.
As illustrated in the chart on the right hand side of the page. We currently expect 10% lower D&C capital in 2024, driven by operational efficiency gains although to be clear the lower capital outlook for 'twenty 'twenty four assumes we maintain our <unk>.
Kris 2023 production level the potential for a rollover in service costs suggest that there could be further reductions in next year's capital budget, but it's too early to assume that those service costs will come to fruition today.
Now to touch on the current liquids and NGL fundamentals I'll turn it over to our senior Vice President of liquids marketing and transportation, Dave Campbell long ago for his comments.
Thanks, Paul.
While <unk> plus prices as a percent of WT I are currently low it is important to remember that the second quarter is historically weaker NGL prices move.
Moving into the second half of 2023 and further into 2024, we see tailwind emerging from normal seasonal demand drivers.
Side in the Chinese petrochemical market and supply moderation due to rig reductions in liquids rich basins.
Starting with propane, although absolute propane inventory levels have remained elevated throughout the first half of 2023 days of supply has generally been trending within the five year range during the same period.
This indicates that the current higher stock levels are to a large degree necessary to support the substantial growth that the U S market has experienced primarily in exports, but also domestic petrochemical demand.
Turning to propane exports, which are highlighted on slide number six we have seen consistent strength throughout 2023 with total U S. Propane exports, averaging one 6 million barrels per day year to date.
This is 300000 barrels per day or approximately 25% higher than the same period last year.
Propane exports also reached a new record high in the second quarter of one 9 million barrels per day in late June According to weekly EIA data.
And the domestic.
Stick market propane demand should improve in the coming months from a new propane dehydrogenation or PTH facility that is starting up in the Gulf coast, followed by seasonal crop drying and heating demand as we move through the remainder of 2023 into 2024.
Turning to the Chinese market, although there have been various headwinds economic recovery post Covid, we have seen some recent data point showing improvement in the petrochemical sector there.
Chinese integrated propylene polypropylene margins from beauty H units have shown dramatic improvements year to date, increasing from outright negative levels in February almost $300 per metric ton in may.
Unsurprisingly utilization rates in Chinese PTH units have been closely correlated with this margin improvement.
Operating rates have improved from low seen during the first quarter as shown on slide number seven reaching eight year to date high of 69% in June 2023, which was the highest rate observed in over a year on the back of higher overall PTH capacity from new facility commissioning during that timeframe.
We believe the rapid uptake observed in PTH utilization in recent months in response to margin improvement highlights the value of having spare petrochemical capacity already in place when demand recovery occurs.
This is something that we have talked about in previous quarters, as well and as a bullish factor over the long term as the property sector improves in China and worldwide.
Turning to supply there has been a lot of attention on our rig reductions in gas focused basins, but we also want to highlight the rig reductions we have seen this year and liquids focused regions.
Slide number eight titled rig counts dropping in key liquids basins shows the rig count changes since the beginning of 2023 for the total U S and there are several key liquids rich basins.
We are showing both the outright rig decrease and the reduction on a percentage basis to illustrate the magnitude of the impact in each region.
There have been substantially year to date rate declines in the Eagle Ford, which is down 26% the scoop stack, which is down 30% in the Bakken, which has dropped 20%.
So while the U S C III plus supply is still growing overall, which we believe is ultimately needed to supply the global market. The rate of growth has been tempered by the drilling slowdown.
This trend presents upside for Ctrip plus pricing as we look ahead in 2024 and beyond as the effect of the rig count reductions play out.
With that I will turn it over to Justin Fowler Senior Vice President of natural gas marketing.
Thanks, Dan.
I will start with comments on the natural gas macro.
Turning to slide number nine titled purely exposure to premium markets.
As a reminder, we sell substantially all of our natural gas out of basin, including approximately 75% to the LNG corridor.
<unk> transportation portfolio provides us with direct exposure to the growing LNG demand along the Gulf coast.
This slide illustrates average basis differentials for 2024 through 2027.
The premiums to Nymex Henry hub that we realized through our firm transportation have improved since the beginning of the year.
In particular, you can see <unk> 500 pricing relative to Henry hub has increased by 15 year to date.
This increase reflects the anticipation startup the plaquemines LNG facility in 2024, which TGT feeds directly into.
Antero has significant exposure to this premium market with nearly 600 Mcf a day of capacity on that pipeline.
Meanwhile, local basis, where the majority of our peers have significant exposure remains at a steep discount to Nymex Henry hub through 2027, despite the recent approval of the MVP pipeline.
Next let's discuss the industry response to lower natural gas prices.
Slide number 10 depicts the historical relationship between Nymex natural gas prices and the rig count in the Haynesville.
We discussed this slide on our fourth quarter 2022 conference call back in February .
At that time, the Haynesville rig count was 73 rigs.
Based on the historical response by producers in that basin, when Nymex prices fell below $3, we communicated an expectation that rigs will fall by at least 25% to 30 rigs.
As it stands today, the Haynesville rig count has declined by 38% or 25 rigs from peak levels.
At this point is driven home further when looking at the reduction in completion crews in the Haynesville, which is shown on slide 11.
Since the beginning of the year. The completion crew count has declined by 36% from 28 to 18 cruise while the decrease in drilling rigs will have a downward impact on 2024 supply. This reduction in completion crews will have a more immediate impact on supply this year.
The sharp decline in drilling rigs and completion crews combined with the basin steep decline profile is expected to help balance the U S natural gas market and provide support to gas prices.
In addition to a moderated supply outlook demand demand trends continue to shift toward natural gas.
Let's turn to slide number 12 titled Power burn demand growth.
This chart shows that natural gas powered burn demand has increased every year for 10 consecutive years.
2023, it looks likely to set new record highs.
Despite the warmer than usual winter led to softer demand to start the year off.
2023 power burn is averaging three three bcf, a day or 14% higher than the five year average.
This July as forecasted the average over 46 Bcf per day, which will set a new monthly record.
In fact, just yesterday, we hit a new daily power burn record of over 51 Bcf.
With that I will turn it over to Mike Kennedy Antero CFO .
Thanks, Justin.
Be brief in my comments today.
But I want to reemphasize the points that Paul made earlier on Interros peer leading capital efficiency.
Slide number 13 highlights the results of our peer group.
Under each company's maintenance capital program.
By definition higher capital efficiency must drive either higher production volumes for the same capital or lower capital with the same production volume.
While attempting to target a maintenance capital program and <unk> volumes actually grew 5% compared to the year ago period.
Conversely, when our peer group attempted to target a maintenance capital program their volumes actually declined by 4% year over year.
This is shown in the chart at the top of the slide.
The chart at the bottom of this slide compares the peer group's capital required per Mcf of production.
As a rule of thumb internally, we view each 100 million dollar change of capital to result in approximately a 100 million a day change in production, both up and down.
Over the last year, we grew nearly 175 million a day, which implies that our capital efficiency gains have reduced true maintenance capital by roughly $175 million all else equal.
Adjusted for this volume growth and Taro would have the lowest capex per Mcf D of its peer group at just 66 cents per Mcf.
Against the peer group averages and Taro is capital program is significantly more efficient, 40% below our natural gas peers.
Looking ahead, we expect to maintain 2024 production at our raised production guidance levels on our capital program.
That we expect to be at least 10% lower than 2023 with.
With all of the lower capital amount due to our capital efficiency.
This raised production guidance also continues to assume a more conservative ethane outlook as we risk the timing of the shell ethane crackers start up.
Lower capital combined with the higher natural gas strip leads to substantial free cash flow in 2024 and beyond.
At the same time, we remain committed to our return of capital policy, which targets returning 50% of our free cash flow to shareholders.
With that I will now turn the call over to the operator for questions.
Thank you Sir at this time, we will be conducting a question and answer session. If you would like to ask a question. Please press star one on your telephone keypad, a confirmation tone will indicate that your line is in the question queue. You May press star two if he would like to remove your question from the queue for participants using speaker equipment.
Please.
Please pickup your handset before pressing the star keys.
One moment, please can we poll for questions.
Yeah.
And our first question comes from the line of Arun Jairam with J P. Morgan. Please proceed with your question.
Yeah. My first question is for Dave Dave you highlighted just the bullish export trends.
Propane.
And I was wondering if you could give us some thoughts on what what do you think has been driving.
The higher inventory levels, and just thoughts on how you see inventories.
Inventories potentially normalizing on the propane side as we move into winter.
Well I think the main thing was really the the mild winter. We had I think we've talked about that maybe on a prior call that that coupled with some petrochemical maintenance during the wintertime added roughly 20 to 21 million barrels to do.
So the absolute inventory levels. So if you strip that out.
We're down in you know close to the middle of the five year range, obviously, even though a lower level on a days of supply basis.
The main driver, but I would say.
Playing a role there and then the other.
Piece on the exports I think we just continue to see strong buying demand the odds are open.
We're using a lot of the shifts that are coming online, but there's still roughly.
Roughly 26 vessels yet to come online this year.
Through the remainder so that'll continue to drive for a cost down.
Even though we have this much higher export stack consistent tailwind there for us as well.
Great and then my follow up maybe for Mike is I wanted to get your thoughts on hedging strategy.
It seems like my core and in an environment where.
The market is quite constructive on 2025 gas prices just given the LNG.
Incremental export demand and maybe investors are appreciating or if some of the gas producers can add some insurance in 2024.
Just to get you know call. It a floor on you know your cash flows for 24, so want to get thoughts on hedging strategy and you know could we see inter looking to add some hedges just given the improvement and strip pricing over the last few weeks.
Yeah, Thanks, Arun Paul here well.
You know as you are saying are we too are positive on the natural gas market.
Positive momentum as you know in the futures prices Cal 'twenty four is about $3 50, 25, and 26 are approaching $4 so pretty healthy.
The other factors, we see that give us a little bit of a tailwind is that.
As we've covered here rig counts completion crew counts are declining and obviously that lower supply.
Ah we're all following we as an industry are following LNG.
Build outs increased demand people signing up for a more and more LNG facilities and that is happening right now where more and more facilities ago S. I D.
And then we touched on just the extra days record, our burn, but but they're systematically we're seeing higher power Burns setting new records, such as yesterday's 51 Bcf so.
As Youre aware Antero is in good shape have a strong balance sheet, our leverage is less than one times. So we're being patient and are watching the market and its tail winds and.
We hedged of course.
Years ago and had success at it.
We watch pretty carefully but bide our time, so that's where we are.
Thanks, Paul.
And the next question comes from the line of Bertrand Donna's with Truest. Please proceed with your question.
Hey, good morning, guys I'm on the capital program. The 2020 for comments in the prepared remarks, you noted that you could see additional drops if maybe service costs come down from here.
Could you maybe just touch on what the 10% drop includes does it use kind of a full year 23 average and then applied to 'twenty four is it maybe what youre expecting for the end of the year and then dragging that Ford and then you know.
Just wanted to give you a chance one of your peers as you're starting to talk about 25. So is there anything that would prevent you from maybe holding that you know that 10% drop into twenty-five or or what it looks like out there.
Yes, so it just holding today's call us in the 'twenty four flat no service cost her reductions are incorporated in that its because of our capital efficiency and the well productivity.
We grew 5% year over year, it's actually maintain that you need about 100000 less lateral feet and so when you do the math on that that's the 10% reduction just at today's cost.
So 24 is down that 10% without any service cost help twenty-five it's actually lower than 24, because as we continue to be at maintenance capital or declines not our natural declines continue to.
Decline as well as you add more and more base and get a little less steep production unless wedge. So 25 was below 24 right now so.
Extremely capital efficient program continues to improve and you can see that in our production growth at the same capital and you'll see it in 'twenty four 'twenty five is lower capital amount.
That's great and then just the second one is.
Maybe you could talk about your your potential LNG strategy does it does a tolling agreement makes sense for antero or are you seeing anything any other structures that maybe would work best for your approach to maybe capture some of the international pricing.
Yeah.
We have 75% of our production that goes to the LNG corridor. So we have so much exposure to that pricing down there are such a large market player and in order to attract our guests just even on a spot basis really it's going to be a lot of competition and really going to result in a.
Pretty significant premium, but we think the pricing so that's our exposure.
Turning to ease we of course evaluate all agreements, but you're talking really small volumes and really big commitments.
That 1 million tons is about $2 billion commitment over.
The timeframe and that's for like 100 million a day. So we don't have to make those commitments. We already have all the transport and all of the production that gets down to the Gulf. So we'll get exposure just sort of spot pricing and then having compete the biogas.
Sounds good thanks, guys.
And our next question comes from the line of David Decal Baum with TD Cowen. Please proceed with your question.
Thanks for your time, guys and the answers today.
Mike I think that's the first one is for you I just wanted to dig in a little bit on just the capex progression and the 24 I think we all understand youre not including cost deflation, but can you characterize a bit maybe you know obviously you were employing a maintenance program, but you grew 5% this year.
Some of those benefits I guess helps in 'twenty four but can you kind of put some bookends around how many wells you have to do in 24 versus 23, and how you think about sort of the well productivity gains for antero itself and twenty-three versus 'twenty two.
Yes.
David had mentioned, it's lateral feet really because wells are wells continue to lengthen laterals. So.
We'll have a bit longer than 24 than we did in 'twenty three pretty much every year. They go a tad longer so that's why I mentioned or referenced 100000.
Feet so.
Well have to do 100000 feet less.
And then when we did this year to maintain that three point for around the 3.4 Bcf a day level and so when you just do our well costs on that 100000 feet. That's how you get to the 90 million less of.
Capital required to maintain its maintaining the same productivity, although our wells.
To be more productive right now, we're just elevating the shape of the curve in the front end and have not increased the EU ours, but.
That could come later as well.
Well productivity performance continues to be ahead of our expectations.
Is that front ends being influenced by choke management changes or completion designs or is that just G. I.
I think we're being conservative in art and not applying that throughout the curve in the life of the well and just trying to wait and take a wait and see approach and see that if that continues throughout time.
I appreciate that.
And just a follow up on you talked about free cash flow generation asbestos excuse me, especially in 'twenty four is the curve and flex higher but I think the last update we all had from you around cash taxes. We had you kind of paying some cash taxes. This year and in that number going higher can you give us an update on what you think your.
Cash tax burden is going to be over the next several years with this this recent downdraft in commodity pricing.
Yeah, we don't foresee any cash taxes.
<unk> through 'twenty, five and nine any material really in 26, so not for the next three years to four years and with prices in 'twenty three that's kept us out of really any exposure to and.
<unk> as well so we don't see any cash taxes for at least the next three years.
Thanks, Mike.
And the next question comes from the line of Moms Schneider with Goldman Sachs. Please proceed with your question.
Hi, Good morning, guys. Thank you for taking my questions.
My first question was a couple of follow ups on the capital spending.
But you need.
Can you give us any color around.
Patients for cost inflation heading into next year.
I don't know what land spending.
And then you made a point that spending would be lower in 2025 as the decline rates.
Shallow any color you can provide that would be great. Thank you.
Yeah.
Yeah on.
The completions I think you know we have of course, our service contracts around drilling and completions really have been locked in in 'twenty. Three that's why you don't see it there, but I think we've.
We've seen recent deals.
5% to 10% lower.
Then where our current con.
Contracts are so I think that's a good starting point for 24 on the potential savings there and then looking at the past 24, it's another 5% to 10% lower capital than that 10%, we talked about for 24 versus 23. So it just continues to shout and continues to go lower as hard.
Declines shallow.
Great.
With me on the LPG side of the equation it sounds like you.
You would think with the lower supply from the U S. The current risk reduction and <unk>.
To maintain demand from.
China, we should expect an inflection in pricing any color you can provide it themselves when do you think pricing.
Could inflect that it's kind of a challenging macro to make predictions, but any.
Do you feel like it's it's a kind of a big bet.
They weren't as demand picked up Oh, so from heating, Michigan drive that inflection in pricing.
Yeah, Mark I would say yes.
As we head into the fourth quarter, a couple of things it won't be happening and why was it Justin mentioned his comments on the gas side as you see rig counts dropped there is still it takes some time to see the effect of that on the supply side, maybe were starting to see that here recently, just with some of the weaker EIA.
<unk> saw over the last several weeks with a propane bills have underwhelmed AR versus expectations after the polar side for us but.
Other things if you look at how propane is pricing right now relative to naphtha, it's doing its normal seasonal summer time.
Yeah, Roger spread that encourages propane to continue to be economic and a steam cracker as we head into the winter time, because we saw this last winter and every winter before that that.
The couples and pro panel price at higher percentages of naphtha throughout the winter time and then we also if you look at just how naphtha as pricing globally.
Granted it's been different since the start of.
The war in the Ukraine.
But even right now on the forward curve naphtha is discounted relative to where it was this past winter I mean, obviously the war with full still occurring that we think there's some upside and that upside the propane. This winter that's not reflected in the forward curve and that as I mentioned earlier in my remarks already to Ryan's question.
Freight rates are anticipated to come down this winter as well so.
Multiple factors that that should cause a propane.
Quite a bit of upside relative to what the forward curve is showing today in the low to.
Mid seventies.
Very helpful. Thank you.
And the next question comes from the line of Sue Boss Shandra with the benchmark Company. Please proceed with your question.
Hey, Mike just to confirm are.
Your response to the cost question so.
The 10% as you've stated multiple times purely.
Capital efficiency.
And another five to 10 as expected could occur in 'twenty four.
From materials and service cost deflation.
There's that potential I wouldnt say on Paul's remarks, like I talked about it may be too early to forecast that that's why we're not including that but it seems that's where the market's trending with a lower rig count in lower completion crews working in the basin.
Okay got it.
Second question. This is you know equally complicated macro question, but.
You mentioned the polypropylene margins.
Here's the naphtha relationship there is supply demand.
How far do you think the conditions the macro conditions are from maybe getting back to the prices.
We saw in the first quarter.
Do you think weather is a winter weather is absolutely necessary to get get there or do you think some.
Some of these other non weather variables, Kent can get us there.
Yeah, I mean I think.
You can get there just on the supply reductions in the liquids rich basins that we talked about you can get there China starts to ramp up their their property sector activity. There's as we've talked to you mentioned them.
So much excess PTH capacity, that's available to ramp up that could certainly get you there without.
But a normal winter so.
We'll continue to watch those things obviously, you don't expect to have a mild.
Mild winter a year after year after year. So there's certainly the potential there as well offer some help from the mother nature, but you don't don't have to rely on that.
Ultimately as we move through into 2024, a thought if the demand starts to pick up as we anticipated.
Yeah Okay.
A final one for me.
When you look at sort of the growth in liquids processing capacity, you know Marcellus other liquids rich basins. What's your thoughts there you know do you think there it's running maybe running ahead or running behind.
We think.
Oh.
Required production or expected production will be.
Sorry, you're asking about processing capacity in the Appalachian Basin, and what we're seeing there just with some of the additional plants or a plant that's been.
Yeah, Yeah that surprised you to the upside or or has it been expected.
Not really I mean, I think when we look at what's actually being produced in the basin.
Theres been a little bit of growth this year.
Antero has been the primary driver of that so.
On processing capacity not all of them just because you have maybe spare capacity in one location doesn't mean that a certain producer who is maybe drilling a more rich acreage is able to utilize it.
Sometimes you have to build a plant somewhere else at the well in other.
Plant in another part of the basin sits out maybe more idle. So we don't we haven't seen.
Growth in the region outside of our own growth.
And I don't know that we would expect to really see much.
Much beyond the one plant that's talked about are coming online.
Don't know when it's all they were gonna see additional processing plants getting built in the region just given the activity.
Got it thank you.
Thanks Sebastian.
And the next question comes from the line of Nicotine Kumar with Mizuho Securities. Please. Please proceed with your question.
And thanks for taking my questions.
Not to keep beating a dead horse on the service cost side, but just you mentioned the 5% to 10% I appreciate it's too early but in terms of the different components.
What are you seeing in terms of.
Price weakness or price trends right now are you seeing movement on the big ticket items like the Dayrates are frac crew.
Yes.
Yeah, that's really where the 5% to 10% is coming from and Thats compared to our current level. So that's where we see recent deals being done.
A bit lower than we're at right now that we're locked in through 'twenty three that's how we come up with 5% to 10%.
And can you remind us what is your current contracting for services are you running through 2023 or even.
Even into 'twenty four.
Completions is through 'twenty three rigs are intermittent expertise throughout 2024, but first quarter kind of third quarter and then at the end of 'twenty four.
Got it and then if I can sneak one more in I don't know if you answered that question, but you had I think a $150 million of land spend this year.
We expect that similar kind of level in putting four and 25 are you seeing enough opportunity for that kind of inventory replenishment or should we expect that to drop next year.
Any thoughts on that that spending.
Yeah.
Probably will drop next year and beyond but if we had the same level of success that we've had this year and the opportunities. We will act on them because we are adding the most.
Efficient possible inventory locations is there just right next to our current development plan and consolidating our acreage position, but you.
You know it is finite amount of those opportunities. So we will project.
Probably much lower and more than a typical <unk>.
<unk> $75 million to $100 million range.
Great. Thanks for answering my questions.
And the next question comes from the line of Gregg Brody with Bank of America. Please proceed with your question.
Hey, good morning, guys.
This may be a difficult question to answer today, but just curious what your thoughts are power.
Our mountain Valley pipeline and the progress there with potentially coming online. This year, how do you think about that impacting your production.
And the ability to grow over time.
I appreciate your.
Your maintenance mode today, and looking for a better macro, but just love to hear your thoughts on that.
Yeah, Greg It was interesting we did a study of the Friday of the kind of basis prices on the Friday before that surprise MVP announcement.
Versus Monday, and it actually just.
Took the costs down kind of in the northeast because that MVP volumes really cannot get down to the southeast or to the more demand centers without some further expansions pipeline. So it really didn't affect the nymex pricing our pricing outside of northeast basis.
And as you know we have all of the transport we need to get outside the basin. So I don't think it really has an impact on our ability to grow.
I guess it would unlock a little bit of local growth. If we chose to pursue that but were really attracted by nymex prices not the local pricing as Justin highlighted on this slide local basis, it's still a dollar off through 2027, so that's not attractive to us so.
We still continue to fill our transport focus on our liquids acreage focus on being as capital efficient as we are in and being at maintenance capital.
Thanks for the perspective I appreciate it.
Okay.
And the next question comes from the line of Kevin Mccarthy with Pickering Energy Partners. Please proceed with your question.
Hey, good morning, guys a couple of questions on the free cash flow comments in the press release just to clarify.
Are you now expecting the full year 2023 to be free cash flow positive and is that a result of the better production or is that comment just kind of looking at the back half of the year.
The full year, we are a bit positive on today's strip.
Great and then just a follow up.
Can you maybe comment on the strategy on buyback timing.
I'm surprised to see you guys bought back some shares this quarter and they're certainly looks to be an opportunity with your stock now I guess the question is how comfortable are you buying back shares ahead of forecasted free cash flow.
We're not comfortable in that we the buyback that occurred in the second quarter. We just chose incentive issue those shares from a tax perspective on the equity vesting. We chose this time to buy it back with our cash instead.
But typically if we don't have free cash flow generation in the quarter, we're not going to be buying back any shares.
Gotcha. Thank you for the clarity.
Yeah.
And our next question is a follow up from David Dunkel Bomber T D. Cowen. Please proceed.
Hey, guys. So I just wanted to sneak one more in here, just commenting back or coming around against the balance sheet.
And just curious like if internally you have explicit goals of moving towards investment grade at this point how.
Critical you think of it as moving forward, especially as you think about LNG, counterparties and things like that and.
How do you think some of the the draws on the facility or how you're sourcing operations right now is informing some of the rating agencies.
Yes, we're one upgrade away from being investment grade.
We are investment grade from one of the three and one of the others were on double B plus positive watch so I would assume that if there's commodity price deck comes to realization, meaning you know $3 50 in 'twenty four and beyond that we will be investment grade sometime next year.
So it's kind of an outcome of just where our balance sheet is and how efficient we are in our size and scale and how low our development costs are so high.
It should come if the commodity prices are hanging in there and then it will be positive for future.
Transactions, but it's not something that's required to.
To realize our financial goals and to realize our results.
Thanks for fitting me back in there.
Mhm.
And the next question is a follow up from Sue by Shandra with the benchmark company. Please proceed.
Yes, the land budget.
Any color you can give us I think you had a strong.
What are the quarter before.
The guidance didn't change very much I did have another strong quarter now are these you know.
Really you know sort of last minute opportunities or how do you think of the balance of the year and then it's 24 completely unpredictable at this point.
First of all talk about 'twenty three I think we had $75 million in the first quarter $35 million in the second.
Our guidance is $1 50, so that would suggest $20 million a.
Quarter, and we're on that pace.
We saw a lot of opportunities last year that we acted on lot of those closed in the first quarter, there was a little bit of.
Momentum behind that as well that that leaked into the second quarter, but right now. It's just your typical run rate of more like $20 million a quarter.
That's how we talk about next year and following years, we generally expect $20 million to $25 million a quarter and that's that 75 to 100 million typical land budget that we have.
That's helpful color. Thank you.
At this time there are no further questions and I'd like to turn the floor back over to Brendan for any closing comments.
Yes. Thank you for joining us for today's call. Please reach out with any further questions.
Good day.
Ladies and gentlemen that concludes today's conference you may disconnect. Your lines at this time. Thank you for your participation and have a great day.
Hum.
Hum.
Hum.
Hum.
[music].
Mhm.
Hum.
Hmm.
Hmm mm.
[music].