ANTERO RESOURCES Corp Q2 FY2023 Earnings Call

Greetings and welcome to the Antero Resources Second Quarter 2023 Earnings Conference Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. This conference is being recorded. It is now my pleasure to introduce Mr. Brendan Krueger, VP of Finance. Thank you, Mr. Brendan, you may begin.

Thank you. Good morning, and thank you for joining us for Antero's second quarter 2023 investor conference call. We'll spend a few minutes going through the financial and operating highlights, and then we'll open it up for Q&A. I would also like to direct you to the homepage of our website at www.anteroresources.com, where we have provided a separate earnings call presentation that will be reviewed during today's call. Today's call may contain certain non-GAAP financial measures. Please refer to our earnings press release for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. Joining me on the call today are Paul Rady, Chairman, CEO and President; Michael Kennedy, CFO; Dave Cannelongo, Senior Vice President of Liquids Marketing & Transportation; and Justin Fowler, Senior Vice President of Natural Gas Marketing. I will now turn the call over to Paul.

Thank you, Brendan. I'll start my comments on slide number three titled, Drilling and Completion Efficiencies. After a record-breaking first quarter operationally, the strong momentum continued in the second quarter. Completion stages averaged more than 11 per day in the second quarter, a 40% improvement compared to the 2022 average and over a 90% increase from 2019 levels. Drill outs, which are the process of drilling out the plugs in each stage of the horizontal portion of the well, exhibited the same success during the quarter. Drill-outs averaged over 4,000 feet per day during the second quarter, up 9% from the 2022 average and over 50% increase from the 2019 levels. Faster drill outs and completion times have resulted in significantly shorter cycle times as shown on the bottom of the page. Since 2019, our cycle times have decreased by 65% and averaged just 151 days in the second quarter. In June, we had the fastest cycle times in our company history at 129 days. These cycle times reflect the total number of days it takes on average from first spud on a pad to turning the entire pad to sales. As a reminder, we averaged six wells per visit per pad. Shorter cycle times mean higher capital efficiency. Highlighting this point, we completed roughly 60% of our 2023 budgeted completion stages during the first six months of 2023. Now, let's turn to slide number four, titled Antero Wells continue to outperform peers. In addition to the drilling and completion records, we continue to see increases in well productivity. Chart on this slide highlights well productivity trends versus our peers since 2020. As illustrated on the page, Antero's average cumulative equivalent production per well is 20% higher than the peer average over this time. This differentiates Antero from its peers, with many companies having already drilled their best acreage. Our long core inventory life continues to deliver stronger results each year. Now let's turn to slide number 5. Faster cycle times and improving well performance led to the increase in our 2023 production guidance. This gain in capital efficiencies is highlighted by our 5% total production growth in the second quarter compared to the year-ago period. Our production growth was driven by 16% liquids growth while natural gas was essentially flat year-over-year. These capital efficiency gains also reduce our maintenance capital budget as illustrated in the chart on the right-hand side of the page. We currently expect 10% lower D&C capital in 2024 driven by operational efficiency gains alone. To be clear, the lower capital outlook for 2024 assumes we maintain our increased 2023 production level. The potential for a rollover in service costs suggests that there could be further reductions in next year's capital budget, but it's too early to assume that those service costs will come to fruition today. Now, to touch on the current liquids and NGL fundamentals, I'll turn it over to our Senior Vice President of Liquids Marketing and Transportation; Dave Cannelongo for his comments.

Thanks, Paul. While C3+ prices as a percent of WTI are currently low, it is important to remember that the second quarter is historically weak for NGL prices. Moving into the second half of 2023 and further into 2024, we see tailwinds emerging from normal seasonal demand drivers, upside in the Chinese petrochemical market, and supply moderation due to rig reductions in liquids-rich basins. Starting with propane, although absolute propane inventory levels have remained elevated throughout the first half of 2023, days of supply have generally been trending within the 5-year range during the same period. This indicates that the current higher stock levels are to a large degree necessary to support the substantial growth that the US market has experienced primarily in exports but also domestic petrochemical demand. Turning to propane exports, which are highlighted on slide number 6, we have seen consistent strength throughout 2023 with total US propane exports averaging 1.6 million barrels per day year-to-date. This is 300,000 barrels per day or approximately 25% higher than the same period last year. Propane exports also reached a new record high in the second quarter of 1.9 million barrels per day in late June according to weekly EIA data. In the domestic market, propane demand should improve in the coming months from a new propane dehydrogenation or PDH facility that is starting up in the Gulf Coast, followed by seasonal crop drying and heating demand as we move through the remainder of 2023 into 2024. Turning to the Chinese market, although there have been various headwinds to economic recovery post-COVID, we have seen some recent data points showing improvement in the petrochemical sector there. Chinese integrated polypropylene margins from PDH units have shown dramatic improvements year-to-date increasing from outright negative levels in February to almost $300 per metric ton in May. Unsurprisingly, utilization rates in Chinese PDH units have been closely correlated with this margin improvement. Operating rates have improved from lowest during the first quarter as shown on slide number 7 reaching a year-to-date high of 69% in June 2023, which was the highest rate observed in over a year on the back of higher overall PDH capacity from new facility commissioning during that time frame. We believe the rapid uptick observed in PDH utilization in recent months in response to margin improvement highlights the value of having spare petrochemical capacity already in place when demand recovery occurs. This is a bullish factor over the long-term as the property sector improves in China and worldwide. Turning to supply, there has been a lot of attention on the rig reductions in gas-focused basins, but also wanted to highlight the rig reductions we have seen this year in liquids-focused regions. Slide number 8 titled Rig Counts Dropping in Key Liquids Basins shows the rig count changes since the beginning of 2023 for the total US and several key liquids-rich basins. We are showing both the outright rig decrease and the reduction on a percentage basis to illustrate the magnitude of the impact in each region. There have been substantial year-to-date rate declines in the Eagle Ford, which is down 26%, the SCOOP/STACK, which is down 30%, and the Bakken, which has dropped 20%. So while the US C3+ supply is still growing overall, which we believe is ultimately needed to supply the global market, the rate of growth has been tempered by this drilling slowdown. This trend presents upside for C3+ pricing as we look ahead in 2024 and beyond as the effect of the rig count reductions play out. With that, I will turn it over to Justin Fowler, Senior Vice President of Natural Gas Marketing.

Thanks, Dave. I'll start with comments on the natural gas macro. Turning to slide number 9 titled Peer-Leading Exposure to Premium Markets. As a reminder, we sell substantially all of our natural gas out of basin, including approximately 75% to the LNG corridor. Our firm transportation portfolio provides us with direct exposure to the growing LNG demand along the Gulf Coast. This slide illustrates average basis differentials for 2024 through 2027. Premiums to NYMEX Henry Hub that we realized from our firm transportation have improved since the beginning of the year. In particular, you can see TGP-500 pricing relative to Henry Hub has increased by $0.15 year-to-date. This increase reflects the anticipated startup of the Plaquemine LNG facility in 2024, which TGP feeds directly into. Antero has significant exposure to this premium market with nearly 600 MMcf a day of capacity on that pipeline. Meanwhile, on a local basis, where the majority of our peers have significant exposure, remains at a steep discount to NYMEX Henry Hub through 2027 despite the recent approval of the MVP pipeline. Next, let's discuss the industry response to lower natural gas prices. Slide number 10 depicts the historical relationship between NYMEX natural gas prices and the rig count in the Haynesville. We discussed this slide on our fourth quarter 2022 conference call back in February. At that time the Haynesville rig count was 73 rigs. Based on the historical response by producers in that basin when NYMEX prices fell below $3, we communicated an expectation that rigs would fall by at least 25 to 30 rigs. As it stands today, the Haynesville rig count has declined by 38% or 25 rigs from peak levels. This point is driven home further when looking at the reduction in completion crews in the Haynesville, which is shown on slide 11. Since the beginning of the year, the completion crew count has declined by 36% from 28 to 18 crews. While the decrease in drilling rigs will have a downward impact on 2024 supply, this reduction in completion crews will have a more immediate impact on supply this year. The sharp decline in drilling rigs and completion crews combined with the basin's steep decline profile is expected to help balance the US natural gas market and provide support to gas prices. In addition to a moderated supply outlook, demand trends continue to shift toward natural gas. Let's turn to slide number 12 titled Power Burn Demand growth. This chart shows that natural gas power burn demand has increased every year for 10 consecutive years. 2023 looks likely to set new record highs. Despite the warmer than usual winter that led to softer demand at the start of the year, power burn is averaging 3.3 Bcf a day or 14% higher than the five-year average. This July is forecasted to average over 46 Bcf per day, which sets a new monthly record. In fact, just yesterday we hit a new daily power burn record of over 51 Bcf. With that I will turn it over to Mike Kennedy, Antero's CFO.

Thanks, Justin. I'll be brief in my comments today. But I want to re-emphasize the points that Paul made earlier on Antero's peer-leading capital efficiency. Slide number 13 highlights the results of our peer group under each company's maintenance capital program. By definition, higher capital efficiency must drive either higher production volumes for the same capital, or lower capital with the same production volume while attempting to target a maintenance capital program. Antero's volumes actually grew 5% compared to the year-ago period. Conversely, when our peer group attempted to target a maintenance capital program, their volumes actually declined by 4% year-over-year. This is shown in the chart at the top of the slide. The chart at the bottom of the slide compares the peer group's capital required per Mcfe of production. As a rule of thumb internally, we view each $100 million change in capital to result in approximately 100 million a day change in production, both up and down. Over the last year we grew nearly 175 million a day, which implies that our capital efficiency gains have reduced true maintenance capital by roughly $175 million all else equal. Adjusted for this volume growth, Antero would have the lowest CapEx per Mcfe of its peer group at just $0.66 per Mcfe. Against the peer group averages, Antero's capital program is significantly more efficient, 40% below our natural gas peers. Looking ahead, we expect to maintain 2024 production at our raised production guidance levels on a capital program that we expect to be at least 10% lower than 2023, with all of the lower capital amount due to our capital efficiency. This raised production guidance also continues to assume a more conservative ethane outlook as we assess the timing of the Shell Ethane Cracker startup. Lower capital combined with the higher natural gas strip leads to substantial free cash flow in 2024 and beyond. At the same time, we remain committed to our return of capital policy, which targets returning 50% of our free cash flow to shareholders. With that, I will now turn the call over to the operator for questions.

Thank you, sir. Our first question comes from Arun Jayaram with JPMorgan. Please go ahead with your question.

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

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

Great. I have a follow-up question for Mike regarding the hedging strategy. Considering the positive outlook for gas prices in 2025 due to increased LNG export demand, it seems that investors might appreciate it if gas producers could secure some insurance for 2024 to establish a baseline for cash flows in that year. What are your thoughts on the hedging strategy? Is Antero considering adding some hedges, especially given the recent improvements in strip pricing?

Yes, we're optimistic about the natural gas market. The futures prices for 2024 are above $3.50, and 2025 and 2026 are nearing $4, which is quite healthy. Additionally, we are seeing declining rig counts and completion crew counts, which reduces supply. As an industry, we're observing the build-out of LNG facilities, with increasing demand and more facilities reaching a final investment decision. We also noted a record power burn recently, with significant power burns setting new records, like yesterday’s 51 Bcf. Antero is in a strong position with a solid balance sheet and leverage under 1x. We're being patient, monitoring the market's positive trends, and have successfully hedged in the past while being careful about our timing. That's our current situation.

Thanks, Paul. And the next question comes from the line of Bertrand Donnes with Truist. Please proceed with your question.

Morning, guys. On the capital program on the 2024 comments in the prepared remarks, you noted that you could see additional drops if maybe service costs come down from here. Could you maybe just touch on what the 10% drop includes? Does it use kind of a full year '23 average and then applies it to '24? Is it maybe, what you're expecting for the end of the year and then dragging that forward? And then just want to give you a chance, one of your peers is starting to talk about '25. So is there anything that would prevent you from maybe holding that 10% drop into '25 or what it looks like out there?

Yes. So just holding today's cost in the '24 flat, no service cost or reductions are incorporated in that. It's because of our capital efficiency and the well productivity, and we grew 5% year-over-year. It’s actually maintained that you need about 100,000 less lateral feet. And so when you do the math on that, that's the 10% reduction just at today's costs. So '24 is down that 10% without any service cost help. '25 is actually lower than '24 because as we continue to be at maintenance capital, our declines, our natural declines continue to decline as well as you add more and more base and get a little less steep production. Unless lat. So '25 was below '24 right now. So extremely capital-efficient program continues to improve. And you can see that in our production growth at the same capital, and you'll see it in '24 and '25 with lower capital amounts.

That's great. And then just second one is maybe to talk about your potential LNG strategy. Does a tolling agreement make sense for Antero? Or are you seeing any other structures that maybe would work best for your approach to maybe capture some of the international pricing?

We have 75% of our production directed towards the LNG corridor, which gives us considerable exposure to pricing in that market. Given the competition among large market players for our gas, even on a spot basis, we anticipate a significant premium. While we review all agreements, we are discussing relatively small volumes in relation to substantial commitments. For instance, a commitment of one million tons represents around a $2 billion investment over the course of the agreement, equating to about 100 million a day. Fortunately, we don't need to make these commitments as we already have the transportation and production resources to get our gas to the Gulf, allowing us to benefit from spot pricing without needing to compete for our gas.

Sounds good. Thanks, guys.

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

Thanks for the time guys and the answers today. Mike, I think this first one is for you. I just wanted to dig in a little bit on just the CapEx progression into 2024. I think we all understand you're not including cost deflation. But, can you characterize a bit maybe obviously, you were employing a maintenance program, but you grew 5% this year. Some of those benefits I guess help in 2024. But can you kind of put some bookends around how many wells you have to do in 2024 versus 2023 and how you think about sort of the well productivity gains for Antero itself in 2023 versus 2022?

Yes, David, I mentioned that we are looking at lateral feet because our wells continue to have longer laterals. In 2024, we'll have a longer average compared to 2023. That's why I talked about the 100,000 feet. We will need to complete 100,000 feet less than this year to maintain our production around the 3.4 Bcfe level. When you factor in our well costs for that 100,000 feet, that's how we arrived at needing $90 million less in capital to sustain that level. We're keeping the same productivity, although our wells are becoming more efficient. Currently, we’re improving the curve and its front end without increasing the estimated ultimate recoveries just yet, but that could happen later as our well performance continues to exceed our expectations.

Is that front ends being influenced by choke management changes or completion designs? Or is that just geology?

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

Thank you. Following up on your comments about free cash flow generation, particularly in 2024 as expectations improve, I recall your last update indicated that you would incur some cash taxes this year, which would increase. Could you provide an update on your expected cash tax burden over the next few years, especially given the recent decline in commodity prices?

Yes. We don't foresee any cash taxes through 2025 and any material really in 2026. So not for the next three to four years. And with the prices in 2023, that's kept us out of really any exposure to AMT qualification as well. So, we don't see any cash taxes for at least the next three years.

Thanks, Mike.

The next question comes from the line of Umang Choudhary with Goldman Sachs. Please proceed with your question.

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

Yes. On the completions, I think we have of course our service contracts around drilling and completions really have been locked in 2023. That's why you don't see it there. But I think we’ve seen recent deals 5% to 10% lower than where our current contracts are. So I think that's a good starting point for 2024 on potential savings there. And then looking at past 2024, it's another 5% to 10% lower capital than that 10% we talked about for 2024 versus 2023. So it just continues to shallow and continues to go lower as our decline shallow.

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

Yes, Umang, I would say yes. It's as we head into the fourth quarter. A couple of things that will be happening along. As Justin mentioned in his comments on the gas side, as you see rig counts that are out there, it takes some time to see the effect of that on the supply side. Maybe we’re starting to see that here recently just with some of the weaker EIA reports over the last several weeks, where the propane builds have underwhelmed versus expectations to the bullish side for us. But the other things if you look at how propane is pricing right now relative to naphtha, it's doing its normal seasonal summertime spread that encourages propane to continue to be economic and a steam cracker as we head into the winter. As we saw this last winter and every winter before that, that decouples propane pricing at higher percentages of naphtha throughout the wintertime. And then we also if you look at just how naphtha is pricing globally, I think winter has been different since the start of the war in Ukraine. But even right now on the forward curve, naphtha is discounted relative to where it was this past winter and obviously the war was still ongoing. We think there's some upside to naphtha outside the propane this winter. That's not reflected in the forward curve. And then as I mentioned earlier in my remarks maybe to Arun's question, the freight rates are anticipated to come down this winter as well. So multiple factors that should cause propane to have quite a bit of upside relative to what the forward curve is showing today in the low- to mid-70s.

Very helpful. Thank you.

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

Hey, Mike, just to confirm your response to the cost question. So – the 10% as you've stated multiple times is purely capital efficiency and another 5% to 10% is expected could occur in 2024 from materials and service cost deflation?

There's that potential. I wouldn't say – in Paul's remarks, he talked about it maybe too early to forecast that. That's why we're not including that. But it seems that's where the market is trending with the lower rig count and lower completion crews working in the basins.

Okay. Got it. Second question this is equally complicated macro question but – you mentioned the polypropylene margins. There's a naphtha relationship. There's supply and demand. But – how far do you think the conditions – the macro conditions are from maybe getting back to prices we saw in the first quarter? Do you think weather – winter weather is absolutely necessary to get there? Or do you think some of these other non-weather variables can get us there?

I believe you can achieve that just through the supply reductions in the liquids-rich basins we discussed. As China begins to increase their property sector activity, there is substantial excess PDH capacity available that could help us reach those levels without a typical winter. We will continue to monitor these factors. It's important to note that we cannot expect mild winters year after year; however, there is potential for weather to provide some assistance. Ultimately, we do not need to depend solely on weather as we approach 2024, especially if demand starts to rise as we expect it will.

Got it. Okay. And just one last question for me. When you consider the growth in liquids processing capacity in the Marcellus and other liquids-rich basins, what are your thoughts on that? Do you believe it's ahead of or behind what you expect for production levels?

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

Correct, yeah. Has that surprised you to the upside or has it been expected?

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

Got it. Thank you.

Thanks, Subhasish.

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

Thanks for taking my question. Not to keep beating a dead horse on the service cost side. But just you mentioned the 5% to 10% and I appreciate it's too early. But in terms of the different components, what are you seeing in terms of price weakness or price trends right now? Are you seeing movement on the big ticket items like day rates or crew prices?

Yeah, that's really where the 5% to 10% is coming from and that's compared to our current levels. So that's where we see recent deals being done a bit lower than we're at right now that we're locked in through 2023. That's how we come up with 5% to 10%.

And can you remind us what is your current contracting for services? Are you running through 2023 or even into 2024?

Completions of 2023 rigs are intermittent expiries throughout 2024, but first quarter kind of third quarter and then the end of 2024.

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

Yeah, probably will drop next year and beyond. But if we have the same level of success that we've had this year and the opportunities, we will act on them because we are adding the most efficient possible inventory locations as they're just right next to our current development plan and consolidating our acreage position. But it is finite the amount of those opportunities. So we will project probably much looking at lower and more in the typical $75 million to $100 million range.

Hey good morning guys. A couple of questions on the free cash flow comments in the press release. Just to clarify, are you now expecting the full year 2023 to be free cash flow positive? And is that a result of the better production? Or is that comment just looking at the back half of the year?

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

Great. And then as a follow-up, can you maybe comment on the strategy on buyback timing? I was surprised to see you guys bought back some shares this quarter. And there certainly looks to be an opportunity with your stock now. I guess the question is how comfortable are you buying back shares ahead of forecasted free cash flow?

We're not comfortable with that. Regarding the buyback that took place in the second quarter, we opted to use our cash to repurchase shares instead of issuing them from a tax perspective on the equity vesting. Typically, if we don't generate free cash flow in a quarter, we will not be buying back any shares.

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

Hey, guys. I just wanted to sneak one more in here. Just commenting back or coming around again to the balance sheet. And just curious like if internally you have explicit goals of moving towards investment grade at this point how critical you think of this moving forward especially as you think about LNG counterparties and things like that? And how you think some of the draws on the facility or how you're sourcing operations right now is informing some of the rating agencies?

Yes. We're one upgrade away from being investment grade. We are investment grade from one of the three and one of the others were on BB+ positive watch. So and I would assume that if this commodity price deck comes to realization meaning $3.50 in 2024 and beyond that we will be investment grade sometime next year. So it's kind of an outcome of just where our balance sheet is and how efficient we are in our size and scale and how low our development costs are. So it should come if the commodity prices hang in there. And then it would be positive for future transactions but it's not something that's required to realize our financial goals and to realize our results.

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

Yes. Can you provide any details about the land budget? I believe you had a strong quarter prior. The guidance has not changed much, but I didn't see another strong quarter now. Are these opportunities arising at the last minute? How do you view the balance of the year? And is 2024 entirely uncertain at this moment?

First, I'll talk about 2023. I think we had $75 million in the first quarter, $35 million in the second. Our guidance is $150 million. So that would suggest $20 million a quarter, and we're on that pace. I think we saw a lot of opportunities last year that we acted on. A lot of those closed in the first quarter. There was a little bit of momentum behind that as well that leaked into the second quarter. But right now it's just your typical run rate of more like $20 million a quarter. And that's how we talk about next year and the following years we generally expect $20 million to $25 million a quarter and that's that $75 million to $100 million typical land budget that we have.

That's helpful color. Thank you.

Yes. Thank you for joining us for today's call. Please reach out with any further questions. Have a good day.

Ladies and gentlemen that concludes today's conference. You may disconnect your lines at this time. Thank you for your participation and have a great day.