Antero Resources Corporation

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 Krueger, VP of Finance. Thank you, Brendan. You may begin.

Thank you. Good morning. Thank you for joining us for Antero's 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.anteroresources.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, CEO, and President, Michael Kennedy, CFO, Dave Cantalongo, Senior Vice President of Liquids Marketing and Transportation, and Justin Fowler, Senior Vice President of Natural Gas Marketing. I will now turn the call over to Paul.

Thank you, Brendan. I'll start my comments on slide number three, titled Drilling and Completion Efficiencies. After a record-breaking first quarter operationally, the strong momentum continued in the second quarter. 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-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 4,000 feet per day during the second quarter, up 9% from the 2022 average, and over 50% increase from the 2019 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. 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 average 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 during the 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, Andero's average cumulative equivalent production per well is 20% higher than the peer average over this time. This differentiates Andero from its peers. With many companies having already drilled their best acreage, our long core inventory life continues to deliver stronger 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 is 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 reduce 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 alone. To be clear, the lower capital outlook for 2024 assumes we maintain our increased 2023 production level. The potential for a rollover in service costs suggests 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 Canalongo, for his comments.

Thanks, Paul. While C3 plus prices as a percent of WTI are currently low, it is important to remember that the second quarter is historically weak for NGL prices. Moving into the second half of 2023 and further into 2024, we see tailwinds emerging from normal seasonal demand drivers, upside 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, total U.S. propane exports averaging 1.6 million barrels per day year-to-date. This is 300,000 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 1.9 million barrels per day in late June, according to weekly EIA data. In the domestic market, propane demand should improve in the coming months, from a new propane dehydrogenation or PDH 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 to economic recovery post-COVID, we have seen some recent data points showing improvement in the petrochemical sector there. Chinese integrated polypropylene margins from PDH units date, increasing from outright negative levels in February to almost $300 per metric ton in May. Unsurprisingly, utilization rates in Chinese PDH units have been closely correlated with this margin improvement. Operating rates have improved from lows seen during the first quarter, as shown on slide number seven. during that time frame. We believe the rapid uptick observed in PDH 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 is a bullish factor over the long term as the property sector improves in China and worldwide. Regarding the supply, there has been a lot of attention on rig reductions in gas-focused basins, but we also wanted to highlight the rig reductions we have seen this year in liquids-focused regions. Supply 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 for several key liquids-rich basins. We are showing both the outright rig decrease impact in each region. There have been substantial year-to-date rate declines in the Eagle Firth, which is down 26%, the Scoop Stack, which is down 30%, and the Bakken, which has dropped 20%. So while the U.S. C3-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 this drilling slowdown. With that, I will turn it over to Justin Fowler, Senior Vice President of Natural Gas Marketing.

Thanks, Dave. I will start with comments on the natural gas macro. Turning to slide number nine, titled Peer Leading 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. Our firm 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. 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 TGP increased by 15 cents year-to-date. This increase reflects the anticipation startup of the Plaquemine LNG facility in 2024, which TGP feeds directly into. Antero has significant exposure to this premium market with the nearly 600 MMCF a day of capacity on that pipeline. Meanwhile, local phases where the majority Slide number 10 depicts the historical relationship between NYMEX natural gas prices and the rig count in the Hainesville. We discussed this slide on our fourth quarter 2022 conference call back in February. At that time, the Hainesville rig count was 73 rigs. Based on the historical response by producers least 25 to 30 rigs. As it stands today, the Haynesville rig count has declined by 38%, or 25 rigs from peak levels. 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 crews. 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's steep decline profile is expected to help balance the US natural gas market and provide support to gas prices. In addition to a moderated supply outlook, 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 power burn demand has increased every year for 10 consecutive years. 2023 looks likely to set new record highs. Despite the warmer than usual winter that led to softer demand to start the year off, 2023 power burn is averaging 3.3 BCF a day, or 14% higher than the five-year average. This July is forecasted to average over 46 BCF per day, which would 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, Ontario CFO.

Thanks, Justin. I'll be brief in my comments today. But I want to reemphasize the points that Paul made earlier on Intero's 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 volumes. While attempting to target a maintenance capital program, Antero's 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 the slide compares the peer groups capital required per MCFE of production. As a rule of thumb, internally, we view each $100 million change of capital to result in approximately $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, Intero would have the lowest CapEx per MCFE of its peer group at just 66 cents per MCFE. Against the peer group averages, Intero's 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 a capital program that we expect to be at least 10% lower than 2023 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 cracker startup. Lower capital combined with a 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 1 on your telephone keypad. A confirmation tone will indicate that your line is in the question queue. You may press star 2 if you would like to remove your question from the queue. For participants using speaker equipment, please pick up your handset before pressing the star keys. One moment, please, while we poll for questions. And our first question comes from the line of Arun Jayaram with JP Morgan. Please proceed with your question.

Yeah, my first question is for Dave. Dave, you highlighted just the bullish export trends on propane. And I was wondering if you could give us some thoughts on what do you think has been driving the higher inventory levels and just thoughts on how you see inventories potentially normalizing on the propane side as we move into winter?

Well, I think the main thing was really the mild winter we had. I think we talked about that maybe on a prior call, that that coupled with some petrochemical maintenance during the wintertime added roughly 20, 21 million barrels to the absolute inventory level. So if you strip that out, we're down in close to the middle of the five-year range, obviously even a lower level on a that I would say, you know, play a role there. And then the other piece on the exports, I think, you know, we just continue to see strong buying demand. The arts are open. We're using a lot of the ships that are coming online, but there's still roughly 26 vessels yet to come online this year for the remainder. So that'll continue to drive freight costs down, even though we have this much higher export stack. And so some tailwinds there for us as well.

Great, and my follow-up, maybe for Mike, is I wanted to get your thoughts on hedging strategy. It seems like, Mike, we're in an environment where the market's quite constructive on 2025 gas prices, just given the LNG, incremental export demand, and maybe investors are appreciating 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 I want to get thoughts on hedging strategy and, you know, could we see Interra looking to add some hedges just given the improvement in strip pricing over the last few weeks?

Yeah, thanks, Arun. Paul here. Well, you know, as you're saying, we too are positive on the natural gas market. There's positive momentum, as you know, in the futures prices. Cal 24 is above 350. 25 and 26 are approaching $4, so pretty healthy. But the other factors we see that give us a little bit of tailwind is that, as we've covered here, rig counts, completion crew counts are declining, and obviously that lowers supply. We're all following. We as an industry are following LNG. the build-outs, the increased demand, people signing up for more and more LNG facilities. And that's happening right now, where more and more facilities will go FID. And then we touched on just yesterday's record power burn, but they're – systematically, we're seeing higher power burns setting new records, such as yesterday's 51 VCF. As you're aware, Antero is in good shape, have a strong balance sheet. Our leverage is less than one times. So we're being patient and watching the market and its tailwinds. And, you know, we hedged, of course, years ago and had success at it. But we watched pretty carefully but bide our time. So that's where we are.

Thanks, Paul.

And the next question comes from the line of Bertrand Donis with Truist. Please proceed with your question.

Hey, morning, guys. On the capital program, on the 2024 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, you know, applies to 24? Is it maybe what you're expecting for the end of the year? and then dragging that forward. And then, you know, just want to give you a chance, one of your peers is starting to talk about 25. So is there anything that would prevent you from maybe holding that, you know, that 10% drop into 25 or what it looks like out there?

Yeah, so just holding today's costs in the 24 flat, no service costs or reductions are incorporated in that. Because of our capital efficiency and the well productivity, And, you know, we grew 5% year over year. To actually maintain that, you need about 100,000 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. 25 is actually lower than 24 because as we continue to be at maintenance capital, our natural declines continue to increase. decline as well as you add more and more base and get a little less steep production and less wedge so 25 is 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 24 and 25 with lower capital amounts that's great and then just second one is

Maybe talk about your potential LNG strategy. Does a tolling agreement make sense for Intero, 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, and they're such a large market player in But in order to attract our gas, 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, we think, to pricing. So that's our exposure. You know, entering into these – we, of course, evaluate all agreements, but you're talking really small volumes and really big commitments. You know, I think that one million tons is about a $2 billion commitment over – the timeframe, and that's for, you know, like 100 million a day. So we don't have to make those commitments. We already have all the transport and all the production that gets down to the Gulf, so we'll get exposure just through the spot pricing and then having it compete to buy our gas.

Sounds good. Thanks, guys.

And our next question comes from the line of David Deckelbaum with TD Cowen. Please proceed with your question.

Thanks for the time, guys, and the answers today. Mike, I think this first one's for you. I just wanted to dig in a little bit on just the CapEx progression in the 24. I think we all understand you're 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, help in 24, 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 in 23 versus 22?

Yeah, so David, I mentioned it's lateral feet really because our wells continue to lengthen in laterals. So we'll have a bit longer in 24 than we did in 23 pretty much every year to go a tad longer. So that's why I mentioned or referenced 100,000 feet. So we'll have to do 100,000 feet less than we did this year to maintain that 3.4 – around the 3.4 VCFE level. And so, when you just do our well costs on that 100,000 feet, that's how you get the 90 million less of capital required to maintain. It's maintaining the same productivity, although our wells continue to be more productive. Right now, we're just elevating the shape of the curve in the front end and have not increased the EURs. That could come later as the 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 geology?

I think we're being conservative in not applying that throughout the curve in the life of the well and just trying to take a wait-and-see approach and see that that continues throughout time.

I appreciate that. And just a follow-up on, you talked about free cash flow generation, excuse me, especially in 24 as the curve inflects 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 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 recent downdraft in commodity pricing?

Yeah, we don't foresee any cash taxes through 25 and not any material really in 26, so not for the next three or four years. And with prices in 23, that's kept us out of really any exposure to AMT qualification as well. So we don't see any cash taxes for at least the next three years.

Thanks, Mike. Thanks.

And the next question comes from the line of Umang Sudari with Goldman Sachs. Please proceed with your question.

Hi, good morning, and thank you for taking my question. My first question was a couple of follow-ups on the capital spending commentary which you made. Can you give us any color around your expectations for cost inflation heading into next year? and on lower land spending. And then you made a point that spending would be lower in 2025 as the decline rates raise further shallow. Any color you can provide there would be great as well. Thank you.

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 23. That's why you don't see it there. But I think We've seen recent deals, you know, 5% to 10% lower than where our current contracts are. So I think that's a good starting point for 24 on the potential savings there. And then looking at 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 go lower as our declines shallow.

Great. Quickly on the LPG side of the equation, it sounds like you think with lower supply from the U.S., the current rate reduction and improvement in demand from China, we should expect an inflection in pricing. Any color you can provide in terms of when do you think the pricing could inflect? It's kind of a challenging macro to make predictions here, but... Do you feel like it's kind of a winter event as demand starts to pick up also from heating, which can drive that inflection in pricing?

Yeah, I would say yes. As we head into the fourth quarter, a couple of things that will be happening. One, as Justin mentioned, his comments on the gas side, as you see rig counts drop, it still takes some time to see the effect of that on the supply side. Maybe we're starting to see that here recently just with some of the weaker EIA projects reports over the last several weeks where the propane bills have underwhelmed versus expectations to the bullish side for us. But other things, if you look at how propane is pricing right now relative to NAFTA, it's doing its normal seasonal summertime spread that encourages propane to continue to be economic and a steam cracker. As we head into the wintertime, as we saw this last winter and every winter before that, decouples and propanel price at higher percentages of NAFTA throughout the wintertime. And then we also, if you look at just how NAFTA is pricing globally, and granted it's been different since the start of the war in the Ukraine, but even right now on the forward curve, NAFTA is discounted relative to where it was this past winter. And obviously the war was still occurring then. We think there's some upside to NAFTA and upside to propane. And I mentioned earlier in my remarks, or maybe to Arun's question, the freight rates are anticipated to come down this winter as well. So multiple factors that should cause propane to have quite a bit of upside relative to what the forward curve is showing today in the low to mid-70s.

Very helpful. Thank you.

And the next question comes from the line of Subha Chandra with the Benchmark Company. Please proceed with your question.

Hey, Mike, just to confirm your response to the cost question. So, the 10%, as you, you know, stated multiple times, purely capital efficiency. And another 5 to 10 is expected, could occur in 24. from materials and service costs deflation?

There's that potential. I wouldn't say, you know, in Paul's remarks, like he talked about it, maybe too early to forecast that. That's why we're not including that. But it seems that's where the market's trending with the lower rig count, 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. There's the NAFTA relationship. There's supply-demand, but how far do you think the macro conditions are from maybe getting back to the prices we saw in the first quarter? Do you think winter weather is absolutely necessary to get there, or do you think some of these other non-weather variables can get us there.

Yeah, I mean, I think certainly you can get there just on the supply reductions and the liquids-rich basins that we talked about. You can get there if China starts to ramp up their you know, having a normal winter. So, you know, we'll continue to watch those things. Obviously, you don't expect to have a, you know, mild winter year after year after year. So there's certainly the potential there as well for some help from the mother nature. But you don't have to rely on that ultimately as we move through into 2024 if the demand starts to pick up as we anticipate it will. Yeah.

Okay. Just 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 it's running, maybe running ahead or running behind what you think, you know, required production or expected production will be?

Sorry, you're asking about processing capacity in the Appalachian Basin, what we're seeing there, just with some of the additional plants or plant that's been... Correct.

Yeah. Yeah. Has that surprised you, you know, to the upside or has it been, you know, expected?

Not really. I mean, I think when we look at what's actually being produced in the basin, you know, I think there's been a little bit of growth this year and Antero's been the primary driver of that. So... on processing capacity, just because you have maybe spare capacity in one location doesn't mean that a certain producer who's maybe drilling more rich acreage is able to utilize it. So you sometimes have to build a plant somewhere else while another plant in another part of the basin sits maybe more idle. So we haven't seen substantial growth in the region outside of our own growth and don't know that We would expect to really see, you know, much beyond the one plant that's talked about or coming online. Don't think we're going to see additional processing plants getting built in the region, just given the activity.

Got it. Thank you.

Thanks, Subash.

And the next question comes from the line of Nateen Kumar with Mizuho Securities. Please proceed with your question.

And thanks for taking my questions. Not to keep being a dead horse on the service cost side, but just you mentioned the 5% to 10%, and 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 day rates or FACRU prices?

Yeah, that's really where the 5% to 10% is coming from, and that's compared to our current level. So that's where we see recent deals being done, you know, a bit lower than we're at right now that we're locked in through 23. 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 into 24?

Completions is through 23. Rigs are... intermittent expiries throughout 2024, but first quarter, kind of third quarter, and then the end of 2024.

And if I can sneak one more in, I don't know if you answered that question, but you had, I think, $150 million of land spent this year. Could we expect a similar kind of level in 2024 and 2025? Are you seeing enough opportunity for that kind of inventory replenishment or should we expect that to drop next year? Any thoughts on that spending?

Yeah, it probably will drop next year and beyond, but if we have 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 as they're just right next to our current development plan and consolidating our acreage position. It is finite, the amount of those opportunities, so we will project probably much lower and more in the typical $75 to $100 million range.

Great. Thanks for answering my questions.

And the next question comes from the line of Greg Brody with Bank of America. Please proceed with your question.

Hey, good morning, guys. I know this may be a difficult question to answer today, but just curious what your thoughts are how Mountain Valley Pipeline, the progress there with potentially coming online at the end of this year, how you think about that impacting your production and the ability to grow over time. I appreciate you're in 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 cost 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 of pipelines. So it really didn't affect the NYMEX pricing or pricing outside of northeast basis. And as you know, we have all 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 mean, I guess it would unlock a little bit of local growth if we chose to pursue that. But we're really attracted by NYMEX prices and not the local pricing, as Justin highlighted on this slide. Local basis is still $1 off through 2027. So that's not attractive to us. We still continue to fill our transport, focus on our liquids acreage, focus on being as capital efficient as we are and being at maintenance capital.

Thanks for the perspective, guys. I appreciate it.

Great. And the next question comes from the line of Kevin McCurdy 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?

No, full year, we are a bit positive on today's trip.

Great. And then as a follow up, can you maybe comment on the strategy On buyback timing, you know, I was surprised to see you guys bought back some shares this quarter. And there 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. The buyback that occurred in the second quarter, we just chose instead of issuing 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.

And our next question is a follow-up from David Deckelbaum with TD Cowen. Please proceed.

Hey, guys. I just wanted to sneak one more in here, just commenting back or coming around again to 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 this moving forward, especially as you think about LNG counterparties and things like that, and how you think some of the draws on the facility or how you're sourcing operations right now is informing some of the rating agencies?

Yeah, 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 this commodity price deck comes to realization, meaning, you know, 350 and 24 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 It should come if the commodity prices hang in there. And then it would be positive for future transactions, but it's not something that's required to realize our financial goals and to realize our results.

Thanks for putting me back in there.

And the next question is a follow-up from Subha Chandra with the Benchmark Company. Please proceed.

Yeah, the land budget, any color you can give us, I think, you know, you had a strong quarter, the quarter before. The guidance didn't change very much. I didn't have another strong quarter now. Are these, you know, really sort of last-minute opportunities, or how do you think of the balance of the year, and then is 24 completely unpredictable at this point?

First, I'll talk about 23. I think we had 75 million in the first quarter, 35 million in the second. Our guidance is 150, so that would suggest 20 million a quarter, and we're on that pace. I think we saw a lot of opportunities last year that we acted on. A lot of those closed in the first quarter. There was a little bit of momentum behind that as well that leaked into the second quarter, but right now it's just your typical run rate of more like 20 million a quarter. And that's how we talk about next year and the following years. We generally expect 20 to 25 million a quarter, and that's that 75 to 100 million typical land budget that we have.

That's helpful, Colin. Thank you.

At this time, there are no further questions, and I'll 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. Have a 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.