Earnings Call Transcript - AR Q1 2023

Operator, Operator

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

Brendan Krueger, CFO

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, and Dave Cannelongo, Senior Vice President of Liquids Marketing & Transportation. I will now turn the call over to Paul.

Paul Rady, Chairman & CEO

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 3 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 is resulting in being pulled forward. During the quarter, we completed 31% of our 2023 budgeted completion stages. Now let's turn to Slide number 4 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. Next, I'll discuss Slide number 5 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 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 & Transportation, Dave Cannelongo for his comments.

Dave Cannelongo, Senior VP of Liquids Marketing & Transportation

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 6 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, the 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 7, we expect record deliveries of very large gas carriers, or VLGCs, which are the largest sized 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 to 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 7, 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 8. 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. to be the incremental NGL supplier to the world. These recent OPEC+ oil cuts, if achieved, could limit OPEC+ LPG supply by an additional 8% or 3 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 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 graph of Slide number 8, 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. 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 9. 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 9 shows that planned expansions over the next two years will nearly double kinase PDH capacity for 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 have 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.

Michael Kennedy, Senior VP

Thanks, Dave. Following our successful debt reduction program, Antero entered 2023 in the strongest financial position in company history, further strengthening our position as 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, this 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% of 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 0.5x. Also acting as a cash flow tailwind, our royalty agreement with Martica ended on March 31, 2023, increasing our net royalty interest and 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 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 the 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 of our revenue generated from liquids and significant exposure to U.S. LNG demand growth.

Operator, Operator

I will now turn the call over to the operator for questions.

Subhasish Chandra, Analyst

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?

Michael Kennedy, Senior VP

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

Subhasish Chandra, Analyst

Okay. 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 you think of that impacting the basin? Is there more gas coming or more rerouted gas as a consequence?

Michael Kennedy, Senior VP

On the Shell project, it is still in the commissioning phase, so it hasn't reached full production volumes yet, and we have accounted for that in our production forecast. Our wellhead volumes are exceeding expectations, but we have adjusted the ethane projections assuming that the commissioning of the Shell Cracker will extend throughout all of 2023. Regarding MVP, we do not sell any product locally, so we do not track it closely. It appears to have been delayed beyond 2023, so we do not anticipate any significant impact from that.

Bertrand Donnes, Analyst

With your mineral acquisition and the additional locations you've added, it appears you're managing your inventory more comfortably as you drill through it. However, do you have any insights on mergers and acquisitions in the basin? Is there a motivating factor for companies to engage, or is everyone likely to adopt a wait-and-see approach? As LNG demand increases, we might see a mix of companies that can access the Gulf Coast and those that cannot, potentially leading to mergers and acquisitions.

Paul Rady, Chairman & CEO

Yes, that's true. Yes, we do look inside the basin. You see our focus on adding the premium acreage to just continue to replenish our inventory. Yes, 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 distressed case on their part or not, we'll see, but we look at everything within the basin.

Bertrand Donnes, Analyst

Okay. Sounds good. And then shifting gears a little bit. You guys always got a lot of nice slide 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.

Dave Cannelongo, Senior VP of Liquids Marketing & Transportation

For our ethane recovery volumes, about 40% to 50% varies by quarter and is tied to Mont Belvieu. Many of the optimistic forecasts are focused on Mont Belvieu pricing and frac spread pricing. Most of our other volumes are linked to gas prices. As we have mentioned in past calls, we have a premium built into gas prices for long-term contracts with those customers. On the Mont Belvieu side, we have observed similar predictions. Ethane recoveries in Texas have been near maximum levels for some time, and production there is increasing. Demand for ethane is growing on both the U.S. Gulf Coast domestic market and the export market. We expect to see significant growth in ethane exports in the coming years. Historically, ethane has traded more like an oil product than as a gas product prior to the shale revolution, but recently it has traded more like gas. However, the potential remains, as the demand for ethane at these facilities is very consistent. There are new crackers being built that can only process ethane, which is the type of demand we want to see both domestically and internationally.

Bertrand Donnes, Analyst

Got it. 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? I think some of your other peers would likely choose to let their volumes go up and then others are letting their 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 leg room?

Paul Rady, Chairman & CEO

So there's always a 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.

Michael Kennedy, Senior VP

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 1%. So that you'll need less wells as well to keep at that maintenance level.

Umang Choudhary, Analyst

My first question was around optimal capital structure and your free cash breakeven. I mean we are 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 flow breakeven, 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?

Michael Kennedy, Senior VP

We are addressing our breakevens by concentrating on our most profitable liquid opportunities, which is reflected in our low breakevens. We are focusing on drilling wells with high BTU content that are rich in liquids. This is our strategy for decreasing breakevens in the natural gas segment. Regarding cash accumulation, we do not plan to build cash. Last year, we had an opportunity to do so, but instead, we have been actively repurchasing our debt in the open market. Some of our bonds will be callable in the first quarter of 2024, so we intend to call those bonds rather than accumulate cash. If that option were not available, we would buy back our shares. Therefore, we have no intention of increasing cash on the balance sheet; we plan to either reduce our debt or repurchase shares.

Umang Choudhary, Analyst

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 the case of severe your outlook?

Michael Kennedy, Senior VP

Yes. 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.

Arun Jayaram, Analyst

I want to ask Dave about C3+ pricing. The futures market is indicating a low 50% range in relation to WTI. Do you think that's a reasonable expectation for the near term? Additionally, how do you see the potential decrease in shipping costs affecting global demand for C3+, especially if it becomes cheaper and potentially improves the ratio compared to WTI in a better demand environment?

Dave Cannelongo, Senior VP of Liquids Marketing & Transportation

I believe that for the near term, particularly into this summer of 2023, levels are likely aligned with our expectations due to the high propane inventory levels we've observed through March and April. As we progress through the year, we anticipate positive developments, particularly with robust exports. This should lead to a decrease in propane inventory towards the five-year average, and potentially below that by year-end. This movement could result in an increase in propane prices relative to WTI, enhancing our C3+ barrel values. We also foresee strong demand for isobutane this summer, akin to last summer's performance, and the octane value remains promising in the market. Therefore, we expect to experience favorable conditions, but it's crucial to focus on demand and monitor how exports affect inventory levels.

Arun Jayaram, Analyst

Great. My follow-up is regarding capital efficiency. You achieved an average of 11 stages this quarter, and we consider a good quarter to be around eight stages, so that’s quite impressive. How is this affecting your thoughts on the CapEx budget, which I understand has a midpoint guidance of $900 million for drilling and completion? Do you believe this level of completion efficiency can be sustained, or was this quarter an exception where everything aligned perfectly?

Michael Kennedy, Senior VP

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

Arun Jayaram, Analyst

Okay. Can I sneak in one more, Mike?

Paul Rady, Chairman & CEO

Sure.

Arun Jayaram, Analyst

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 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? It's pretty important for the supply-demand balance to think about gas next year.

Paul Rady, Chairman & CEO

Let me pass that question to Justin Fowler, who is our Vice President of Natural Gas Marketing and Trading. So, Justin?

Justin Fowler, VP of Natural Gas Marketing and Trading

We just continue to hear on our side that Exxon and the Qataris continued to fast track Golden Pass. So the first train size that is expected to come online is around 750,000, 800,000 a day, and we're thinking that's going to be sometime in 2024. So that'll just start to take more gas into the liquefaction corridor. And then they will continue to ramp up another two trains. And again, everything that we're hearing, they're working to fast track that project.

David Deckelbaum, Analyst

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 breakeven at the corporate level from some of the Martica adjustments over time. 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 a decline in maintenance spend into '24 and then beyond that? Or is it really the visibility beyond '24 is dictated by base decline progression at this point?

Michael Kennedy, Senior VP

They all play a role, and they are all supportive factors for us, David. When considering it, we expect a year-over-year decline of about 10% to 15% from 2024 compared to 2023, which is quite substantial. This trend is expected to continue into the following years at a similar level. Maintenance capital requirements are projected to decrease slightly due to the lower decline from a diminishing base, as we maintain flat production over the years while addressing the ongoing declines.

David Deckelbaum, Analyst

If I could just follow up on the land budget, I know there was an expectation that this would be the largest quarter in terms of land spending. Have you seen more opportunities on the land side coming to you as the market has softened, or is there really no connection between that type of market and what we're observing on the spot screen?

Michael Kennedy, Senior VP

Yes. No, we knew that 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 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 come back into that $25 million level a quarter type of pace, which is more normal for us.

Kevin MacCurdy, Analyst

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 cost for the back half of this year and into next year? And I was going to ask you to provide a range of potential impact, but it sounds like you just did. Did you say that maintenance CapEx would be down 15% next year?

Michael Kennedy, Senior VP

I mentioned that we're looking at a 10% to 15% range, starting with 10% in 2024 and possibly trending towards 15% in the following years compared to 2023. Our contracts on the completion side typically expire at the end of 2023, as they are generally annual. There are adjustments based on commodity prices, and given the current low natural gas prices, we will need to see how that unfolds in 2023. The rigs usually have a duration of 12 to 18 months, and we aim to stagger their expirations to avoid all rigs coming off contract simultaneously. Therefore, we expect a mix of expirations from late 2023 and into the first and second quarters of 2024.

Dave Cannelongo, Senior VP of Liquids Marketing & Transportation

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

Subhasish Chandra, Analyst

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

Michael Kennedy, Senior VP

I'd say it's the latter. Right now, what we're really thinking will occur in '23, it's more on the raw material side. And that would be across basins, but it's more on the tubulars, it's more on sand costs, it's more on fuel. And that's regardless of whether it's gas or oil basin, 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 spot fleets becoming available, and that should eventually lead to lower service cost. But right now, we're not seeing it for this quarter.

Subhasish Chandra, Analyst

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

Michael Kennedy, Senior VP

Yes, 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.

Operator, Operator

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

Brendan Krueger, CFO

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

Operator, Operator

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