Greetings, welcome to the Antero Resources Q1 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 Krueger, CFO of Antero Midstream and VP of Finances. Thank you, Mr. Krueger. You may begin.
Thank you. Good morning, and thank you for joining us for Antero's Q1 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 Cannelongo, 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 Q1 , 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 Q1 , 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 Q1 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 Peers. 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, Antero's average cumulative equivalent production per well is 20% greater than the peer average over this time. 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. I'll discuss slide 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 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. 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 Cannelongo, 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 lack of cold weather and several PDH outages resulted in high propane inventories this winter, a resurgence in international demand has pushed more barrels into the global market in recent weeks. Slide number six highlights that U.S. propane exports have already increased 20% year-to-date at 1.6 million barrels per day, compared to 2022's average of 1.35 million barrels per day. Additionally, propane exports hit an all-time weekly high at 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. As shown on slide number seven, we expect record deliveries of very large gas carriers, or VLGCs, which are the largest size marine vessels that can carry LPG, roughly 550,000 barrels per ship. The market will also see significant increases in Chinese petrochemical demand for LPG, driven by PDH capacity additions this year and in 2024. On the shipping side, the market expects deliveries of 46 new VLGC ships during 2023, which equates to a 300,000 barrel per day 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 seven, the chart shows that 11 new VLGCs have already been placed into service year-to-date. These capacity additions have already helped reduce the Baltic rate from $94 at the beginning of 2023 to $75 today. The additional VLGCs are expected to reduce shipping rates further and narrow the spread between Mont Belvieu and international pricing, resulting in a tailwind for Antero's C3+ 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+ 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+ oil cuts, if achieved, could limit OPEC+ LPG supply by an additional 8% or three VLGCs per month from May of 2023 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% and 19% declines in liquids rich focused rigs in the Appalachian Basin and the Eagle Ford respectively since the beginning of the year.
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 eight, which is supportive for Mont Belvieu pricing. While Antero certainly benefits from the uplift in Mont Belvieu prices, the majority of Antero's NGL exports are transported through the Mariner East system, and Antero's firm capacity on that system and unique pricing flexibility give us additional opportunities to take advantage of price spreads and arbitrage opportunities. Turning to China on slide number nine, we have seen a recent recovery in utilization rates at 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 side of slide number nine shows that planned expansions over the next two years will nearly double Chinese PDH capacity from 2022 levels, resulting in over 500,000 barrels a day of potential new propane demand, or about 5% of the 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 ship tracking data.
Antero is extremely well-positioned to benefit from increasing global NGL demand over the long term, with over 50% of our NGL volumes being exported and all of our NGL volume currently unhedged. With that, I will turn it over to Mike.
Thanks, Dave. Following our successful debt reduction program, Antero entered 2023 in the strongest financial position in company history. Further strengthening our position is our low free cash flow breakeven level.
Turning to slide number 10, titled Free Cash Flow Breakeven. 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. 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. 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 $0.50 to over $1 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. Acting as a cash flow tailwind, our royalty agreement with Martica ended on March 31, 2023, increasing our net royalty interest in wells drilled by 3.75%. This will result in lower cash flow distributions to Martica each quarter going forward, assuming the current strip. We anticipate the majority of that cash flow to revert back to Antero 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 trade at 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 in 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 US 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 one on your telephone keypad. A confirmation tone will indicate that your line is in the question queue. You may press star two 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. Our first question is from Subash Chandra with The Benchmark Company. Please proceed with your question.
Thank you. Good morning, everyone. Congratulations on the, you know, the drilling records. Just trying to think through, you know, 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? You know, 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, Subash. We're obviously a bit ahead of schedule on the completions pace. Right now our thought is we would just have less completions in the fourth quarter and stick to the budget.
Okay. Thank you. A follow-up, I guess is, you know, a couple of basin questions. You know, if there's a update on the Shell cracker, you know, is it fully functioning at this point? MVP, how you think of that, impacting the basin? Is there, you know, more gas coming or more rerouted gas as a consequence?
On the Shell, they're still in the commissioning phase, so they're not up, 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 Shell cracker 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 seems that it's been delayed past 2023, so we don't see really any impact from that.
Okay. Thanks, Mike.
Thank you. Our next question is from Bertrand Donnes with Truist Securities. Please proceed with your question.
Morning, guys. With your mineral acquisition and the 50 locations that you tacked on, it seems like you're more comfortable just kinda replacing your inventory as you drill through it. Do you have any, you know, thoughts on M&A in the basin? Is there any driver to, you know, make companies come to the table, or is it really, you know, everybody's gonna kinda 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. Whether that results in a distressed case on their part or not, we'll see. We look at everything within the basin.
Okay. Sounds good. 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 kinda depressed right now, but some of your peers have gotten kinda bullish, maybe towards the end of this year or next year, as some of the debottlenecking happens, maybe some exports pick up. I just wanna know if you guys any thoughts on that?
Yeah. You know, for our ethane recovery volumes, about 40%-50%, depending on the quarter right now is linked to Mont Belvieu. I think some of those bullish outlooks are really around Mont Belvieu pricing and frac spread pricing. Most of our other volume, it's not Mont Belvieu linked, it's gas linked. 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. On the Belvieu side, we've, you know, 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, not just, you know, in the US 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. Certainly the potential, if you look historically, ethane is traded more like an oil product than as a gas product prior to the shale revolution. It's really been the recent years, it was traded more similarly to gas. Yes, that potential's there as the demand for ethane at those types of facilities is very sticky. They're building crackers that can only consume ethane. That's the kind of demand you wanna have both domestically and internationally.
Got it. Got it. I don't wanna 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. I just didn't know if that applied to 2024 as well. Is the maintenance program the target next year as well, or is maybe there's some wiggle room?
Yeah, well, there's always wiggle room, but no, we're really pretty determined to stick to our maintenance cap for 2024 as well. 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.
I would also add on the 2024 maintenance capital level, it's at a lower level than the 2023 capital. Because of these efficiencies, those really drive lower costs. Plus, we are seeing a rollover in the service costs and raw materials. As each year that we are at maintenance capital, our decline rate lowers by about 1%, 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 Choudhary 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 flow breakeven. I mean, we are likely gonna be in a volatile gas price environment as we haven't really built gas storage even as demand has increased. 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 flow breakeven, especially given your plans to be unhedged going forward. 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?
Good, good question. We're attacking the breakevens by really focusing on the highest liquids opportunities we have. That's why you see our breakevens are so low. It's because we're drilling, you know, 1,275 to 1,300 BTU wells that are heavily liquid focused. That's how we're really thinking about lowering our breakevens on the natural gas side. Then on building cash, we wouldn't build cash. You saw last year we would've 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 2024. We would call those bonds instead of building cash. If all that was not available to us, we'd be buying back our shares.
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 repurchase, or would you prefer the credit facility remains low to preserve liquidity in a case of severe to your outlook?
No, we wouldn't lever up to buy back shares. We're very steadfast in our debt reduction goals and wanna get as low as possible. 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 Arun Jayaram with JP Morgan. Please proceed with your question.
Good morning. I wanna maybe ask Dave, in terms of C3+ pricing in the futures market is kinda 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? How does this potential reduction in shipping costs, how do you think about that influencing, you know, demand globally for C3+ just making it cheaper, and perhaps the ratio relative to WTI, if we get into a better demand environment?
Yeah, I think it's 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 upside, as 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. That's where you could really see that propane price start to appreciate in the percentage of WTI for our C3+ barrel improve.
You know, we continue to, you know, expect some strong values for isobutane this summer, similar to what we saw last summer. The value for octane appears to be there again in the market. I think we'll continue to see some tailwinds from that as well. Really with C3 making up, you know, over 50% of our C3+ barrel, the focus is really gonna 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, you know, an average of 11 stages this quarter, which, you know, for us is, you know, we tend to think of a good quarter as doing eight stages. That's a pretty impressive number. How does that influencing yet your thoughts on the CapEx budget, which I think the midpoint in terms of the D&C CapEx guide is $900 million? 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. In that, in our thoughts, we've moved up our assumptions. I think we were assuming, you know, 8-9 stages a day, and we achieved 11. Now we're assuming around 10 stages a day. 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. Could 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. One question we've been getting from investors and just perhaps thoughts on the timing of Golden Pass in 2024. I know you don't operate that. That's an ExxonMobil project. Do you have any intel or thoughts on the timing of that project? 'Cause 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 Trading. Justin?
Good morning, Arun Jayaram. We just continue to hear on our side that, you know, Exxon and the Qataris continue to fast-track Golden Pass. The first train size that is expected to come online is around, you know, 750,000-800,000 a day, and we're thinking that's gonna be sometime in 2024. That'll just, you know, start to take more gas, you know, into the liquefaction corridor, and then they will continue to ramp up another two trains. 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 Cowen. 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 2024 and then 2025. 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, how do you think about like percentage-wise the decline in maintenance spend into 2024 then beyond that? You know, is it really the visibility beyond 2024 is dictated by base decline progression at this point?
They all go into and they're all tailwinds for us, David. You know, when you think about it in the kind of 10%-15% range, year-over-year decline, 2024 versus 2023. That's pretty significant. That continues, you know, 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 declining base as you continue to, you know, put year after year of flat production in the, in the wedges, that continues to decline from there.
Thanks, Mike.
Yeah.
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 that Q1 was gonna be a large one because a lot of these deals that you land take 60 days to close. 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, is that you don't have those large packages, so it should, you know, come back into that $25 million level a quarter type of pace, which is more normal for us.
Thanks, Mike. Best of luck, guys.
Yep. Thank you.
Thank you. Our next question is from Kevin MacCurdy 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? I was gonna 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?
About 10%. I said 10 to 15, but I would start with 10 in 2024, and then maybe it trends to 15 in the out years after that in 2025 compared to 2023. Our contracts on the completion side, they expire. They're generally annual contracts. They expire at the end of 2023. There are openers in them based on commodity prices, and we are, obviously with the low natural gas price below those commodity price kinda openers. We'll just have to see how that goes in 2023. 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. It's a mix of late 2023 and first and Q2 of 2024 for the rigs.
Great. I appreciate that detail. Apologies if I missed this in your presentation or your release, can you let us know how many wells you turned in line and how many wells you completed in the Q1 ?
Well, it's about 80 for the year. I think it was probably about even on the well turn lines, maybe low 20s.
Great. Thank you.
Thank you. Our next question is from Subash Chandra with The Benchmark Company. Please proceed with your question.
Yeah, Mike, just to 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 is just across all services and materials?
I'd say it's the latter. Right now, what we're really thinking will occur in 2023 is more on the raw material side, and that'd be across basins, but it's more on the tubulars, more on sand costs, more on fuel. That's, you know, regardless whether it's gas or oil basin, you know, you're going to capture some of those cost decreases. On the service costs, what we are now seeing some, you know, decline in rig counts and completion crews being used in our basin. There's some spot fleets becoming available, and that should eventually lead to the lower service costs. Right now we're not, we're not seeing it for this quarter.
Right. Got it. That 10%-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.