Antero Resources Q1 2023 Earnings Call Transcript

Quartr
Provided by Quartr
April 27, 2023

There are 11 speakers on the call.

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.

Operator

Brendan Krueger, CFO of Antero Midstream and VP of Finance. Thank you, Mr. Krueger. You may begin.

Speaker 1

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 and A. I would also like to direct you to the homepage of our website at www.anteroresources.com, 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.

Speaker 1

I will now turn

Speaker 2

the call over to Paul. Thank you, Brandon. 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 3, titled Drilling and Completion Performance.

Speaker 2

The chart on the left hand side of the slide highlights Our lateral footage drilled per day. During the Q1, we achieved 3 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.

Speaker 2

These completion records are referring to a single completion crew. Across the 2 crews, we have averaged 22 completion 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 Now let's turn to Slide number 4 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.

Speaker 2

Average liquids productivity has increased 87% since 2018. 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 Next, I'll discuss slide number 5 titled Low Decline Rate Leads to Lower Maintenance Capital. As we enter the 4th year of a maintenance capital program, our base decline rate continues to move lower. This analysis from a third party highlights that Antero's 1 year and 3 year decline rates are the lowest of our natural gas peer group.

Speaker 2

Touching briefly on our cost outlook, we are beginning to see service costs Rollover 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 Q1, we invested $72,000,000 On land, as previously communicated, this represents just under half of our 2023 land budget of $150,000,000 Our leasing efforts are primarily focused near our current development plan where we are achieving these excellent drilling completion Well performance results.

Speaker 2

This land investment in the Q1 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 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 Cantelongo for his comments. Dave? Thanks, Paul.

Speaker 2

Liquids prices have rebounded from recent lows in early Q1 and fundamental data is pointing to continued recovery throughout this year, especially for

Speaker 3

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 Push 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 1,600,000 barrels per day compared to 20 22's average of 1,350,000 barrels per day.

Speaker 3

Additionally, propane exports hit an all time weekly high of 1,850,000 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 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.

Speaker 3

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 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.

Speaker 3

The additional VLGCs are expected to reduce further and narrow the spread between Mont Belvieu and international pricing resulting in a tailwind for Antero C3 plus 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 plus additional crude production cuts are expected to lower LPG from the Middle East, Continuing to solidify the U.

Speaker 3

S. Incremental NGL supplier to the world. These recent OPEC plus oil cuts, If achieved could limit OPEC plus 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's supply growth in NGL production is I'll note that we believe that this U. S.

Speaker 3

Growth estimate could prove to be too high given the year to date reductions in liquids rich focused drilling rigs. We have seen 27% 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, 3rd party providers 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.

Speaker 3

While Antero certainly benefits from the 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 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 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 2 years will nearly double Chinese 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.

Speaker 3

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 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.

Speaker 4

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 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 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 Natural gas. We estimate that most Haynesville companies are not able to generate free cash flow in today's pricing environment.

Speaker 4

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.

Speaker 5

As you

Speaker 4

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 Steady and consistent progress we have made in our share repurchase program over the last year. During the Q1, we purchased 87 Since the inception of our share repurchase program at the beginning of 2022, We have now purchased over $1,000,000,000 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.

Speaker 4

In 2023, we expect 45% of We delivered during the Q1 compared to the year ago period. This liquids growth compares to a 3% Our differentiated strategy continues with the chart in the middle of the slide, Highlighting our ability to sell 100 percent 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 The chart at the bottom of the slide shows our commitment to reduce absolute debt since 2019. This commitment has resulted in $2,400,000,000 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 Martica ended on March 31, 2023, increasing our net royalty interest in wells drilled by 3.75%.

Speaker 4

This will result in lower cash flow distributions to Marvika 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 $8,000,000,000 we trade at a PDP15 valuation. So using our free cash flow to buy back our stock is an attractive option.

Speaker 4

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 the 2nd wave of LNG export facilities coming online. Looking ahead, we are well positioned with a peer leading balance product diversity with nearly half our revenue generated from liquids and significant exposure to U. S.

Speaker 4

LNG demand growth. With that, I will now turn the call over to the operator for questions.

Operator

Thank you. We will now be conducting a question and answer session. And our first question is from Subash Chandra with The Benchmark Company. Please proceed with your question.

Speaker 6

Thank you. Good morning, everyone. Congratulations on the drilling records. Just trying to think through What this might mean is, as the year goes on with 31% of the completions in the Q1, How do you think about, say, Q4? 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.

Speaker 4

Yes. No, good question, Subash. We're obviously a bit ahead of schedule on the So right now our thought is we would just have less completions in the Q4 and stick to the budget.

Speaker 6

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 you think of that impacting the base?

Speaker 6

And is there more gas coming or more rerouted gas as a consequence?

Speaker 4

On the Shell, they're still in the commissioning phase. So they're not up ramped up to the full volumes and we've completely risked that in our production guidance. Our gross wellhead volumes 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.

Speaker 4

It's just And it seems that it's been delayed past 2023. So we don't see really any impact from that.

Speaker 6

Okay. Thanks, Mike.

Operator

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

Speaker 7

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 thoughts on M and A in the basin? Is there any driver to make companies come to the table or is it really 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 get to the Gulf Coast and those that can't and maybe that forces M and A?

Speaker 2

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. 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.

Speaker 7

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.

Speaker 7

So I just want to know if you guys have any thoughts on that?

Speaker 3

Yes. For our ethane recovery volumes, about 40% to 50% depending on the quarter right now is linked to Mont Belvieu. And so 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. And we've as we've discussed previously in the calls, we bake in a premium to gas to Have a long term contract for those types of customers.

Speaker 3

But on the Veldy side, we've seen the same predictions. Obviously, recoveries of ethane In Texas have been 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 the potential, if you look historically ethane has traded more like an oil product than as a gas product prior To the shale revolution, it's really been the recent years it's traded more similarly to gas.

Speaker 3

But yes, that potential is There is 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.

Speaker 7

Got it. And then I don't want to take a real third question. This is 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.

Speaker 7

So I just didn't know if that to 24 as well. Is the maintenance program the target next year as well or is maybe there's some wiggle room?

Speaker 2

So, yes, there's always wiggle room, but no, we're really pretty determined to stick to our maintenance It's 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.

Speaker 4

And 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. And 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.

Speaker 7

That's perfect. Thanks guys.

Operator

Our next question is from Umang Choudhary with Goldman Sachs, please proceed with your question.

Speaker 8

My first question With 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 gas storage even Demand has increased. So I have a 2 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?

Speaker 4

Yes. Good question. We're Tacking the breakevens by really focusing on the highest liquids opportunities we have. And that's why you see our breakevens are so low. It's because we're drilling 1275 to 1300 B2 wells that are heavily liquid focused.

Speaker 4

So that's how we're Really thinking about lowering our breakevens on the natural gas side. So and then on building cash, we wouldn't build cash. You saw last year we would have an opportunity to that, but instead of doing that we are active in the open market repurchasing our debt, our bonds. Some of our bonds become callable too in the Q1 of 2024. So we would call those bonds instead of building cash.

Speaker 4

And if All that was not available to us. We'd be buying back our shares. So, have no plans on building cash on the balance sheet. We'll use it to Either pay down our debt or buy back shares.

Speaker 8

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

Speaker 4

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

Operator

Our next question is from Arun Jayaram with JPMorgan. Please proceed with your question.

Speaker 5

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

Speaker 3

Yes. I think it's actually for the near term, Just call it into this summer of 2023, I think levels are probably pretty in line with where we would expect them Just given the high propane inventory, absolute levels that we've seen here through March April, 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 inventory start to move Down in the 5 year range, closer to the 5 year average with the potential to be below the 5 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 improved. We continue to 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.

Speaker 3

So I think we'll On the demand side of the equation and seeing those exports start to pull down inventories.

Speaker 5

Great. And 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 is we tend to think of a good quarter is doing 8 stages. So that's a pretty impressive Number, so how does that is that influencing yet your thoughts on the CapEx budget, which I think the midpoint in terms of the D and CapEx guide is $900,000,000 And do you think this is a level of completion efficiency that can be sustained? Or did everything just go right this quarter?

Speaker 4

No. We're sticking to the 900 like you referenced, Arun. And in that in our thoughts, we've moved up our I think we are assuming 8 to 9 stages a day and we achieved 11. So now we're assuming 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.

Speaker 5

Okay. Can I sneak in one more, Mike?

Speaker 4

Sure.

Speaker 5

I just wanted to get a sense, you guys do a lot of great on the kind of the macro picture. And one question we'll 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.

Speaker 2

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

Speaker 3

Yes. 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 It's expected to come online is around $750,000 $800 a day and we're thinking that's going to be sometime in 2024, so that will just start to take more gas into the liquefaction And then they will continue to ramp up another 2 trains. And again, everything that we're hearing, they're Working to fast track that project.

Speaker 5

Thanks, Justin. Appreciate it.

Operator

Our next question is from David Deckelbaum with TD Cowen. Please proceed with your question.

Speaker 9

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 in the corporate level from 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 the decline in maintenance Spends into 2024 and then beyond that or is it really the visibility beyond 2024 is dictated by base decline Progression at this point?

Speaker 4

They all go into it and they're all tailwinds for us David. I would 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.

Speaker 9

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? Is there really no correlation between that type of market and what we're seeing on the spot screen?

Speaker 9

Yes.

Speaker 4

No, we knew that Q1 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 We had some large packages that we were able to execute on. We're going to close in January February. Right now, the pipeline is as the budget suggests, but you don't have those large packages. So it should come back into that $25,000,000 level a quarter type of pace, which is more normal for us.

Speaker 5

Thanks, Mike.

Speaker 7

Best of

Speaker 9

luck, guys.

Speaker 4

Yep.

Operator

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

Speaker 10

Hey, good morning. As it relates to service costs, can you remind us what your philosophy is on contracting term and how that might Playing to 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, it sounds like you just did. Did you say that maintenance CapEx would be down 15% next year?

Speaker 4

10%. I said 10% to 15%, but I would start with 10% and 24% and then maybe it trends to 15% in the out years after that in 2025 compared to 2023. Yes. So our contracts on the completion side, they expire. They're generally annual contracts.

Speaker 4

They expire at the end of 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 2023. The rigs, they are generally 12 to 18 months. We try to stagger them, so we don't have all the rigs coming off at once. So It's a mix of late 2023 and 1st and second quarter of 2024 for the rigs.

Speaker 10

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 Fine. And how many wells you completed in the Q1?

Speaker 4

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

Operator

Our next question is from Subash Chandra with The Benchmark Company. Please proceed with your question.

Speaker 6

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

Speaker 4

I'd say it's the latter. Right now, what we're really thinking will occur in 'twenty three is more on the raw material Slide and that would be across basins, but it's more on the tubular, it's more on sand costs, more on fuel. And that's Regardless whether it's gas, 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 Lower service costs, but right now we're not seeing it for this quarter.

Speaker 6

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 after?

Speaker 4

Yes. That 10% for next year does not assume any service costs decrease. That's

Speaker 6

Excellent. Thank you.

Operator

Yes. 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.

Speaker 1

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

Operator

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

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