Antero Resources Corporation

Greetings, and welcome to the Intero Resources First 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. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Mr. Brendan Kruger, CFO of Antero Midstream and VP of Finances. Thank you, Mr. Kruger. You may begin.

Thank you. Good morning, and thank you for joining us for Antero's first 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, and Dave Cantalongo, Senior Vice President of Liquids Marketing and Transportation. I will now turn the call over to Paul.

Thank you, Brendan. I'd like to focus my comments today on our company's operational performance during the quarter. During the first quarter, we set a number of new company and industry drilling and completions records, which highlights our exceptional team and high-quality asset base. Let's begin on slide number three, titled Drilling and Completion Performance. The chart on the left-hand side of the slide highlights our lateral footage drilled per day. During the first quarter, we achieved three of the top 10 lateral feet drilled in a 24-hour period. This included a world record of 12,340 lateral feet drilled in a 24-hour period. The chart on the right hand side of the page illustrates our completion stages per day. We set a new quarterly record at almost 11 stages per day, including a single day record of 16 stages per day. These completion records are referring to a single completion crew. Across the two crews, we have averaged 22 completion stages per day. These are extraordinary achievements from both our drilling and completion teams who continuously look for ways to improve our operations. I will note that the increase in efficiency during the first quarter results in activity being pulled forward. During the quarter, we completed 31% of our 2023 budgeted completion stages. Now, Let's turn to slide number four, titled Antero Well Performance versus Pierce. In addition to the drilling and completion records, we continue to be very encouraged by the well productivity we are seeing. The chart on the left-hand side of this slide shows that Antero's liquids productivity continues to get better and better each year. average liquids productivity has increased 87% since 2018. The chart on the right-hand side of the page highlights well productivity trends versus our peers since 2020. As illustrated on the page, Nantero's average cumulative equivalent production per well is 20% greater than the peer average over this time. This is in a This is an important distinction for Antero. With many companies having already drilled their best acreage, our long core inventory life continues to deliver stronger results each year. Next, I'll discuss slide number five titled, Low Decline Rate Leads to Lower Maintenance Capital. As we enter the fourth year of a maintenance capital program, our base decline rate continues to move lower. This analysis from a third party highlights that Antero's one-year and three-year decline rates are the lowest of our natural gas peer group. Touching briefly on our cost outlook, we are beginning to see service costs roll over for rigs and completion crews. We're also seeing a decline in costs for raw materials such as tubulars, fuel, and sand. The combination of cost deflation, drilling and completion efficiency gains, and a lower decline rate is expected to result in lower overall maintenance capital requirements in 2024. Lastly, I would like to comment on our organic leasing efforts. During the quarter, the first quarter, we invested $72 million on land. As previously communicated, this represents just under half of our 2023 land budget of $150 million. Our leasing efforts are primarily focused near our current development plan, where we are achieving these excellent drilling completion and well-performance results. This land investment in the first quarter adds the equivalent of over 50 incremental drilling locations, mostly in the liquids-rich core of the Marcellus. We say equivalent locations as the organic leasing investment adds both absolute locations as well as lengthening our current locations. For example... Our 2023 wells drilled are expected to average 14,500 feet in the lateral, a 7% increase from the average in 2022. Now, to touch on the current liquids and NGL fundamentals, I will turn it over to our Senior Vice President of Liquids Marketing and Transportation, Dave Cantalongo, for his comments. Dave?

Thanks, Paul. Liquids prices have rebounded from recent lows in early Q1, and fundamental data is pointing to continued recovery throughout this year, especially for the propane barrel. While a lack of cold weather and several PDH outages resulted in high propane inventories this winter, a resurgence in international demand has Additionally, propane exports hit an all-time weekly high of 1.85 million barrels per day in April, according to EIA data. The increase this year is the result of the post-COVID recoveries in demand and the Chinese economy reopening. Looking at the macro infrastructure picture, this year is expected to be a pivotal one for the LPG market, which stands for liquefied petroleum gas, namely propane and butane. year and in 2024. On the shipping side, the market expects deliveries to 46 new VLGC ships during 2023, which equates to a 300,000-barrel-per-date increase in shipping capacity based on average round-trip voyages from the U.S. Gulf Coast to China. On the left-hand side of slide number 7, the chart shows that 11 new VLGCs have already been placed into service year-to-date. for Antero's C3 Plus realizations. Turning to slide number eight, the U.S. is still expected to be the incremental global supplier of NGLs to meet increasing international demand. Recently announced OPEC Plus additional crude production cuts are expected to lower LPG from the Middle East, continuing to solidify the U.S. as the incremental NGL supplier to the world. These recent OPEC Plus oil cuts to December of 2023. The chart on the left-hand side of the slide shows that while the rest of the world's supply growth in NGL production is expected to be roughly flat from 2022 to 2024, the U.S. is expected to grow 11% during that period. I'll note that we believe that this U.S. growth estimate could prove to be too high given the year-to-date reductions in liquids-rich focused drilling rigs. We have seen 27% Even with U.S. supply growth, third-party providers show that there is expected to be unconstrained LPG export capacity through the end of 2026 based on existing dock capacity and recently announced expansions, as shown on the right-hand sub-graph of slide number 8, which is supportive for Montbelvi pricing. While Antero certainly benefits from the uplift in Montbelvi prices, the majority of Antero's NGL exports are transported through the marinery advantage of price spreads and arbitrage opportunities. Turning to China on slide number nine, we have seen a recent recovery in utilization rates on existing PDH units and continued plans to add more capacity in 2023 and 2024 to meet post-pandemic demand growth. A PDH is a propane dehydrogenation facility that takes a feedstock of propane and converts it into propylene, a key building block in the plastics industry. The chart on the left-hand overall global propane demand. With limited supply growth coming from the Middle East and other areas, as we just discussed, China will increasingly depend on U.S. LPG imports to serve these plants. This trend is already evident with 50% of total Chinese LPG imports coming from the U.S. in March of 2023, according to third-party shift tracking data. Ontario is extremely well positioned to benefit from increasing global NGL demand. With that, I will turn it over to Mike. Thanks, Dave.

Following our successful debt reduction program, Intero entered 2023 in the strongest financial position in company history. Further strengthening our position is our low free cash flow break-even level. Turning to slide number 10, titled Free Cash Flow Break-Even, we thought it was important to revisit this slide, as it is critical to our natural gas macro views. As a reminder, the slide provides a look at the natural gas peer group and the required NYMEX Henry Hub price for each of the peers to achieve an unhedged free cash flow breakeven position in 2023. As illustrated on this page, as a result of higher maintenance capital costs, limited liquids revenue uplift, and widening basis differentials on natural gas, We estimate that most Haynesville companies are not able to generate free cash flow in today's pricing environment. We've already begun to see a moderation of activity from these producers through the gas-directed rig declines in recent weeks. We expect this downward trend in rig counts to continue through 2023. As you can see on the left-hand side of this slide, Antero's free cash flow breakeven price benefits from a significant liquids uplift, and the premium natural gas pricing we receive by selling our gas out of basin. Turning to capital returns, slide number 11 illustrates the steady and consistent progress we have made in our share repurchase program over the last year. During the first quarter, we purchased $87 million of our stock. Since the inception of our share repurchase program at the beginning of 2022, we have now purchased over $1 billion of our stock or approximately 10% of our shares outstanding. Now let's turn to slide number 12, titled Antero's Differentiated Strategy. As I just discussed, our focus on liquids development provides significant benefits to our free cash flow breakeven. In 2023, we expect 45% of our total revenue to come from liquids. This focus on liquids is further highlighted through the 17% liquids production growth we delivered during the first quarter compared to the year-ago period. This liquids growth compares to a 3% decline in natural gas volumes during that time. Our differentiated strategy continues with the chart in the middle of the slide, highlighting our ability to sell 100% of our natural gas out of basin, including 75% to the LNG corridor. With no exposure to local markets that often trade 50 cents to over a dollar back of NYMEX, we are able to capture premium prices to NYMEX. The chart at the bottom of the slide shows our commitment to reduce absolute debt since 2019. This commitment has resulted in $2.4 billion in debt reduction during that time and a leverage profile of just 0.5 times. Also acting as a cash flow tailwind, our royalty agreement with Marduk ended on March 31st, 2023, increasing our net royalty interest in wells drilled by 3.75%. This will result in lower cash flow distributions to Marlake each quarter going forward, assuming the current strip. We anticipate the majority of that cash flow to revert back to Intero in 2025 based on today's commodity prices. We are committed to our return of capital policy. which targets returning 50% of free cash flow to shareholders. Based on current strip prices and our current enterprise value of approximately $8 billion, we traded a PDP-15 valuation. So using our free cash flow to buy back our stock is an attractive option. In closing, the successful execution of Antero's differentiated business strategy positions us to excel across many commodity price cycles. Increasing NGL demand through the reopening of China provides a bullish backdrop to NGL prices as we move through the year. On the gas macro, we continue to expect moderated activity from producers and basins that are outspending cash flow at today's prices. We expect this moderated activity to lead to significant volatility in pricing as natural gas demand grows materially in 2024 and beyond, with a second wave of LNG export facilities coming online. Looking ahead, we are well positioned with a peer-leading balance sheet, product diversity with nearly half our revenue generated from liquids, and significant exposure to U.S. LNG demand growth. With that, I will now turn the call over to the operator for questions.

Thank you. We will now 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, it may be necessary to pick up your handset before pressing the star keys. One moment please while we pull for questions. Thank you. And our first question is from Subhash Chandra with the Benchmark Company. Please proceed with your question.

Thank you. Good morning, everyone. Congratulations on the drilling records. Just trying to think through what this might mean as the year goes on with 31% of the completions in the first quarter. How do you think about, say, fourth quarter? If you're running such a strong pace, do you sort of stay within budget, within the wells guided, or do you sort of take advantage of the efficiencies and drill through them as we close out the year?

Yeah, no, good question, Subhash. We're obviously a bit ahead of schedule on the completions pace, so right now our thought is we would just have less completions in the fourth quarter and stick to the budget.

Okay, thank you. And a follow-up, I guess, is a couple of basin questions. If there's an update on the shell cracker, is it fully functioning at this point? And then MVP, how do you think of that impacting the basin? Is there more gas coming or more rerouted gas as a consequence?

On the shell, they're still in the commissioning phase, so they're not ramped up to full volumes, and we've completely risked that in our Production guidance, our gross wellhead volumes are obviously ahead of expectations, but we have risked the ethane volumes as if that commissioning of the shellcracker continues throughout all of 2023. On MVP, we don't sell any locally, as you recall, so we don't follow it that closely. It just seems that it's been delayed past 2023, so we don't see really any impact from that.

Thanks, Mark.

Thank you. Our next question is from Bertrand Jones with Truist Securities. Please proceed with your question.

Good morning, guys. With your mineral acquisition and the 50 locations that you tacked on, it seems like you're more comfortable just kind of replacing your inventory as you drill through it. But do you have any, you know, thoughts on M&A in the basin? Is Is there any driver to, you know, make companies come to the table, or is it really, you know, everybody's going to kind of wait and see, and then as LNG demand comes on, we might have a mix of people that can, you know, get to the Gulf Coast and those that can't, and maybe that forces M&A.

Yeah, that's true. Yeah, we do look inside the basin. You see our focus on adding the premium acreage. to just continue to replenish our inventory. Yeah, there are a number of competitors in the basin that are somewhat trapped that they are selling at the local index and can't go to the premium market. So whether that results in a distress case on their part or not, we'll see. But we look at everything within the basin.

Okay, sounds good. And then shifting gears a little bit, You guys always put out a lot of nice slides on propane and butane and what the markets look like. But I was wondering if you could expand on maybe ethane. I know prices are kind of depressed right now, but some of your peers have gotten kind of bullish maybe towards the end of this year or next year. Some of the debottlenecking happens, maybe some exports pick up. So I just want to know if you guys have any thoughts on that.

Yeah, for our, I think, recovery volumes, about 40% to 50%, depending on the quarter right now, is linked to Mount Bellevue. And so I think some of those bullish outlooks are really around Mount Bellevue pricing and frack spread pricing. Most of our other volume, it's not Mount Bellevue linked, it's gas linked. And as we've discussed previously in calls, we bake in a premium to gas to have a long-term contract for those types of customers. But on the Bellevue side, we've seen the same predictions. Obviously, recoveries of ethane in Texas have been, you know, near max for quite some time. Production is growing down there, but so is demand for ethane in the U.S. Gulf Coast. Domestic side, as well as on the export side, we do believe there'll be quite a bit of ethane export growth here in the coming years. So, certainly that the And it's really been the recent years it's traded more similarly to gas. But, yes, that potential is there. The demand for ethane at those types of facilities is very sticky. They're building crackers that can only consume ethane. So that's the kind of demand you want to have both domestically and internationally.

Got it. And then I don't want to take a real third question. This is just kind of a follow-up. The comment about maybe just letting – the number of completions be that and not going over your CapEx, even if you have kind of efficiencies. Was that comment also applicable to next year? You know, I think some of your other peers would likely choose to let their volumes go up, and then others are letting their, you know, production volumes fall year over year. So I just didn't know if that applied to 24 as well. Is the maintenance program the target next year as well, or is maybe there's some wiggle room?

There's always wiggle room, but no, we're really pretty determined to stick to our maintenance cap for 2024 as well. So it may turn out the way it does in 2023 that we move through our completions more quickly, but we'll still stay under the budget constraints.

And I would also add on the 2024 maintenance capital level, it's at a lower level than the 23 capital because of these efficiencies. Those really drive lower costs. Plus, we are seeing a rollover in the service costs and raw materials. And as each year that we are at maintenance capital, our decline rate lowers by about a percent. So you'll need less wells as well to keep at that maintenance level. That's perfect. Thanks, guys. Thank you.

Thank you. Our next question is from Umang Chaudhary with Goldman Sachs. Please proceed with your question.

Hi, good morning, and thank you for taking my questions. My first question was around optimal capital structure and your free cash or break-even situation. I mean, we're likely going to be in a volatile gas price environment as we haven't really built to gas storage, even as demand has increased. So I have a two-part question for you. First, would love your thoughts around any actions you can take to further lower your free cash or break-even, especially given your plans to be unhedged going forward. And second, any thoughts on building cash on the balance sheet and on optimal leverage ratios, which can allow you to be more opportunistic in a low commodity price environment?

Yeah, good question. We're attacking the break-evens by really focusing on the highest liquids opportunities we have. And that's why you see our break-evens are so low. It's because we're drilling, you know, 1,275 to 1,300 B2 wells that are heavily liquid-focused. So that's how we're really thinking about lowering our break-evens on the natural gas side. And then on building cash, we wouldn't build cash. You saw last year, we would have had an opportunity to that, but instead of doing that, we were active in the open market repurchasing our debt, our bonds. Some of our bonds become callable, too, in the first quarter of 24. So we would call those bonds instead of building cash. And if all that was not available to us, we'd be buying back our shares. So I have no plans on building cash on the balance sheet. We'll use it to either pay down our debt or buy back shares.

Quick follow-up there then. Would you be willing to use a credit facility to do share purchase or would you prefer the credit facility remains low to preserve liquidity in a case of severe outlook?

Yeah, no, we wouldn't lever up to buy back shares. We're... very steadfast in our debt reduction goals and want to get as low as possible. So we would not use our credit facility to buy back shares. We'd rather keep it low.

Thank you.

Thank you.

Thank you. Our next question is from our room, Joe Ryan with JP Morgan. Please proceed with your question.

Yeah, good morning. I want to maybe ask Dave, In terms of C3 Plus pricing, the futures market is kind of embedding, call it a low 50% range in terms of WTI, in terms of a ratio relative to WTI. Do you think that's a fair outlook for the near term? And how does this potential reduction in shipping cost, how do you think about that influencing demand globally for C3 Plus to make it cheaper? and perhaps the ratio relative to WTI if we get into a better demand environment.

Yeah, I think it's actually for the near term, let's just call it, you know, into this summer of 2023, I think levels are probably pretty in line with where we would expect them to be just given the high propane inventory absolute levels that we've seen here through March and April. You know, I'd say as we move through the year, that's where we see the upsides. We expect exports to continue to be quite robust, and that's where you'll see propane inventories start to move down in the five-year range, you know, closer to the five-year average with the potential to be below the five-year average by the end of the year. And that's where you can really see that propane price start to appreciate in the percentage of WTI for our C3 plus barrel improve. You know, we continue to, you know, expect The focus is really going to be on the demand side of the equation and seeing those exports start to pull down inventories.

Great. Just my follow-up would be just on the capital efficiency front. You guys did an average of 11 stages this quarter, which for us, we tend to think of a good quarter as doing eight stages, so that's a pretty impressive increase. So how does that, is that influencing yet your thoughts on the CapEx budget, which I think the midpoint in terms of the DNC CapEx guys, 900 million. And do you think this is a level of completion efficiency that can be sustained or did everything just go right this quarter?

No, you know, we're sticking to the 900 like you referenced Arun and in that, in our thoughts, we've moved up our assumptions. I think we were assuming you know, eight to nine stages a day. And we achieved 11. So now we're assuming around 10 stages a day. So we're not assuming the 11 continues, but we are assuming better performance and increased performance. And I think that will occur throughout the year.

Okay. Can I sneak in one more, Mike?

Sure.

I just wanted to get a sense, you guys do a lot of great work on the kind of the macro picture. And one question we'd be getting from investors and just perhaps some thoughts on the timing of Golden Pass in 2024. I know you don't operate that. That's an ExxonMobil project. But do you have any intel or thoughts on the timing of that project? Because it's pretty important for the supply-demand balance to think about gas next year.

Let me pass that question to Justin Fowler, who is our vice president of natural gas marketing and trading.

So, Justin. Yeah, good morning, Arun. We just continue to hear on our side that Exxon and the Qataris continue to fast-track Golden Pass. So the first train size that is expected to come online is around $750, $800 a day, and we're thinking that's going to be And, again, everything that we're hearing, they're working to fast-track that project.

Thanks, Justin. Appreciate it.

Thank you. Our next question is from David Deckelbaum with TD Cowan. Please proceed with your question.

Hey, guys. Thanks for taking the questions this morning.

No problem.

I was hoping maybe you could quantify a bit or talk directionally about the maintenance capital progression to 24 and then 25. And I suppose there's also, I guess, a theoretical impact of lower free cash break even in the corporate level from some of the MARTICA adjustments over time. You know, I guess as we sit today, given some of the efficiencies that are happening and then it seems like there's some pressure on costs coming down in the field and how do you think about like percentage-wise the decline in maintenance spends into 24 and then beyond that? Or, you know, is it really the visibility beyond 24 is dictated by base decline progression at this point?

They all go into it and they're all tailwind for us, David. I would, you know, when you think about it in the kind of 10 to 15% range year over year decline, 24 versus 23. So, That's pretty significant, and then that continues to be about the level that you need in the out years. It continues to trend a bit down as maintenance capital needed for a lower declining base as you continue to put year after year of flat production in the wedges. That continues to decline from there.

Thanks, Mike. If I could just follow up on the land budget, I know there was the expectation that obviously this would be the largest quarter in terms of land spend, but I guess have you seen more opportunities on just some of the land side coming to you as the market has been softer, or is there really no correlation between that type of market and what we're seeing on the spot screen?

Yeah, no, we knew the first quarter was going to be a large one because a lot of these deals that you land – take 60 days to close. So, you know, we knew in November and December we had some large packages that we were able to execute on. We're going to close in January and February. Right now the pipeline is, as the budget suggests, that you don't have those large packages, so it should, you know, come back into that $25 million level, a quarter type of page, which is more normal for us.

Thanks, Mike. Best of luck, guys.

Yep.

Thank you. Our next question is from Kevin McCurdy with Pickering. Please proceed with your question.

Hey, good morning. As it relates to service costs, can you remind us what your philosophy is on contracting term and how that might play into lower well costs for the back half of this year and into next year? And I was going to ask you to provide a range of potential impacts, but it sounds like you just did. Did you say that maintenance capex would be down 15% next year?

At 10%. I said 10 to 15, but I would start with 10 and 24, and then maybe it trends to 15 in the years after that, and 25 compared to 23. Yeah, so our contracts on the completion side, they expire. They're generally annual contracts. They expire at the end of 23. There are openers in them based on commodity prices, and we are obviously with the low natural gas price below those commodity price kind of openers. So we'll just have to see how that goes in 23. The rigs, they are generally 12 to 18 months. We try to stagger them so we don't have all the rigs, you know, coming off at once. So it's a mix of late 23 and first and second quarter of 24 for the rigs.

Great. I appreciate that detail. And then apologies if I missed this in your presentation or your release, but can you let us know how many wells you turned in line and how many wells you completed in the first quarter?

Well, it's about 80 for the year. I think it's probably about even on the well turn lines, maybe low 20s.

Great. Thank you.

Thank you. Our next question is from Subhash Chandra with The Benchmark Company. Please proceed with your question.

Yeah, Mike, just a follow-up on the inflation or the deflation question. How much do you think you attribute to, you know, being in a gas basin and seeing some perhaps, you know, excess deflationary tailwinds there? Or how much do you think this is just across all services and materials?

I'd say it's the latter. Right now, what we're really thinking will occur in 23 is more on the raw materials side, and that'd be across basins, but it's more on the tubulars, more on sand costs, more on fuel. And that's, you know, regardless of whether it's gas or oil basin, you know, you're going to capture some of those cost decreases. On the service costs, we are now seeing some decline in rig counts and completion crews being used in our basin. So there's some slot fleets becoming available, and that should eventually lead to lower service costs. But right now, we're not seeing it for this quarter.

Right. Got it. That 10% to 15% number, if you had to weight, you know, how much of that was raw material dependent versus service dependent, is there a number you can throw out there?

Yeah, that 10% for next year does not assume any service cost decrease. That's really more just looking at the raw material costs and then looking at lower well counts because our decline rates go down.

Excellent. Thank you.

Yep.

Thank you. There are no further questions at this time. I would like to turn the floor back over to Mr. Brendan Krueger for closing comments.

Thank you for joining us on today's call. Please reach out with any further questions. We are available. Thank you.

This concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation.