Antero Resources Corporation (NYSE:AR) Q3 2023 Earnings Call Transcript

Antero Resources Corporation (NYSE:AR) Q3 2023 Earnings Call Transcript October 26, 2023

Operator: Greetings, and welcome to Antero Resources Q3 2023 Earnings Conference Call. At this time all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. [Operator Instructions] As a reminder, this conference is being recorded. I would now like to turn the conference over to your host, Brendan Krueger, Chief Financial Officer of Antero and Vice President of Finance.

Brendan Krueger: Thank you. Good morning everyone. Thank you for joining us for Antero’s third 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 and Transportation; and Justin Fowler, Senior Vice President of Natural Gas Marketing. I will now turn the call over to Paul.

Paul Rady: Thank you, Brendan. I’ll start my comments on Slide number 3, titled drilling and completion efficiencies. After a record-breaking first half of 2023 operationally, we continued to build on this momentum during the third quarter. As an example, our completion pumping hours per day increased to over 17 hours per day, up nearly 50% from a year ago. In June, we set a company record pumping on average for over 22 hours a day. This increase in pumping hours per day contributes to higher completion stages per day. Year-to-date completion stages per day have averaged 11 stages a day, a 35% improvement compared to the 2022 average, and is a nearly 90% increase from our 2019 levels. The net impact of all of our operational improvements has led to significantly shorter cycle times, as shown on the bottom of the page.

These cycle times reflects the total number of days it takes, on average, from first spudding a pad to turning that entire pad to sales. Since 2019, our cycle times have decreased by an impressive 65%, and averaged just 160 days through the first three quarters of 2023. In June, we had the fastest cycle times in our company history at 129 days, shorter cycle times means higher capital efficiency. Highlighting this point, we completed roughly 80% of our 2023 expected completion stages during the first nine months of 2023. Now let’s turn to Slide number 4. Faster cycle times and improving well performance has led to two production guidance increases in 2023. This gain in capital efficiencies is highlighted by our 9% total production growth in the third quarter compared to the year-ago period.

Our production growth was driven by an 18% liquids growth, while natural gas volumes increased 4% year-over-year. Looking at this on an annual basis, we now expect production this year to increase by 225 million cubic feet equivalent per day, or 7%, from the exit rate in 2022 to the exit rate in 2023. Importantly, these capital efficiency gains also reduce our maintenance capital budget. We continue to expect materially lower D&C capital in 2024 driven by operational efficiency gains alone. Lastly, I’d like to discuss our multi-decade inventory position. Turning to Slide number 5 titled, AR has the lowest – the largest low-cost inventory. This chart compares inventory positions across our natural gas peer group based on data from a recent third-party report.

Antero has the most sub $2.75 per Mcfe drilling inventory at 22 years. It’s important to note that this inventory comparison is after our peers spent a combined $17 billion on acquisitions over the last two years. In contrast, we remain focused on our organic leasing efforts where we’ve invested some $340 million over that same time to acquire targeted drilling locations within our development footprint. On average, we have been able to add locations for approximately $1 million per location through this program. That is less than half of the over $2 million average cost per location for the peer acquisitions. Touching on the recent flurry of M&A headlines, in our opinion, drivers for M&A usually relate to either one, limited core inventory; two, a lack of pipeline capacity to move your production out of basin; or thee, balance sheet repair.

With a peer-leading low-cost inventory position, the largest firm transportation portfolio in the E&P sector and low absolute debt and leverage, Antero can stay focused on improving operations which we believe drives ultimate shareholder value. Now to touch on the current liquids and NGL fundamentals, I’m going to turn it over to our Senior Vice President of Liquids Marketing and Transportation, Dave Cannelongo for his comments. Dave?

Dave Cannelongo: Thanks, Paul. In the second half of 2023 we have seen an uptick in crude pricing as the macroeconomic concerns in the first half of the year have eased and new geopolitical concerns in the Middle East have increased the risk premium in the market. The most recent conflict has added volatility to global energy prices, particularly crude, with market fears of war spreading further in the Middle East. Turning to propane, while absolute propane inventories are high and prices as a percent of WTI lower than usual, fundamentals are painting a better picture in recent weeks. The U.S. recently set a new weekly record high for propane exports and printed two consecutive weeks above two million barrels per day. Overall, propane export demand has been consistently strong and has averaged 1.6 million barrels per day year-to-date, shown on Slide 6, about 250,000 barrels per day or 19% above the 2022 full year average.

As we move into 2024, exports are expected to further increase causing potential tightness in U.S. Gulf Coast stock capacity. As a reminder, Antero exports over 50% of our C3+ production, skewed heavily towards propane in particular, directly out of the Marcus Hook terminal in Pennsylvania, and therefore, Antero’s export volumes are not impacted by constraints at the Gulf Coast export docks. In fact, with tight capacity in the Gulf Coast and strong international pricing, Antero will be able to take advantage of its capacity out of Marcus Hook to capture these wide arbitrage opportunities. The growing call on propane exports has kept propane days of supply in line with historical levels. As seen on Slide 7, while total propane inventories sit just above the top of the five-year range, propane days of supply is currently just one day above the five-year average.

Adding to the strong exports, seasonal demand will also start to increase in the fourth quarter as the market heads into the winter heating season. Strong heating demand this winter could quickly deplete the surplus that the mild 2022 to 2023 winter added to inventories last withdrawal season. Now let’s turn to Slide 8 titled China PDH Buildout Continues. A major driver of strong propane exports this year has been growing demand from China, which has seen stronger year-over-year petrochemical demand despite some macroeconomic headwinds there. This year through August, 120,000 barrels a day of propane dehydrogenation or PDH capacity has been added in China. Industry estimates show that another 340,000 barrels a day of capacity is expected to come online between now and the end of 2024.

Even with just one fourth of PDH capacity additions online that are expected over 2023 and 2024, the ramp in imports to China from the U.S. year-over-year has been substantial. For January through August this year, the amount of U.S. propane cargoes delivered to China increased by 44% year-over-year compared with a 19% increase year-over-year from the Middle East. This demonstrates that U.S. exports continue to make up the marginal increase required by Chinese propane demand. Meanwhile, on the U.S. supply side, rig counts continue to drop, now down 21% year-to-date as seen on Slide 9. This represents a drop of 163 rigs across both oil and gas directed rigs. Permian Basin rig counts are down 40 year-to-date and have accelerated decreases in recent weeks, falling to just above 300 total rigs, losing 20 rigs between the end of September and start of October.

Additionally, key NGL-producing basins such as the Eagle Ford and Scoop Stack have seen their rig counts declined 35% and 45% year-to-date. Overall, we believe that with supportive fundamentals domestically and positive demand signals from China, there are signs of improvement for NGLs heading into 2024 and in particular, for producers like Antero with direct access to international markets. With that, I’ll turn it over to our Senior Vice President of Natural Gas Marketing, Justin Fowler, to discuss the natural gas market.

Justin Fowler: Thanks, Dave. I will start on Slide number 10 titled Dramatic Reduction in Activity Will Limit Production Growth. Starting with the rig count chart at the top of the slide, we have seen the Appalachia plus Haynesville rig count declined by approximately 50 drilling rigs since the beginning of this year. This compares to the similar rig decline that we experienced back in 2019. As shown on the natural gas production chart at the bottom of the slide, it took over six months to materialize. However, U.S. natural gas production ultimately declined by as much as 10%. Further, it took almost two years to get back to the 2019 highs. Today, we are just about 6 months out from when rigs began to drop in a meaningful and sustained way.

An important distinction this time around, however, is that over 70% of the rig declines this cycle have come from the higher decline in Haynesville Basin. A sharp contrast to 2019 when the majority of rig drops came from the lower decline in Appalachian Basin. In summary, we believe the sharp decline in rigs and completion crews will curb production growth in 2024, helping to balance the U.S. natural gas market. As a reminder, we sell substantially all of our natural gas out of basin, including approximately 75% to the LNG corridor, as shown on Slide number 11, titled Firm Transportation to the LNG Fairway. Our firm transportation portfolio provides us with direct exposure to growing LNG demand along the Gulf Coast and importantly, into Tier 1 pricing points along the Gulf Coast.

Next, I’ll turn to Slide number 12, titled Not All Firm Transportation to the Gulf Coast is Equal. This slide illustrates the significant benefit in selling your gas at Tier 1 Gulf Coast pricing. Based on the current strip, Tier 1 prices reflect increasing premiums to NYMEX in 2024 and 2025, including the TGP 500 line, where premiums have increased to $0.29 above NYMEX in 2026. Meanwhile, some peers claim they can move their gas to the Gulf Coast, but they’re actually stuck in Tier 3, selling their gas at $0.24 back of NYMEX in both 2024 and 2025. The yellow stars on the map depict Antero sales points, which were strategically negotiated to bring our volumes directly to the LNG doorstep. As depicted in the pie chart on the top left of the slide, Antero sells 90% of its gas at Tier 1 pricing.

This compares to the average of our peers, which sell 60% – 7% of their Gulf Coast directed volume into Tier 2 and 3 pricing. Looking ahead over the next two years as LNG export capacity increases by nearly 6 Bcf, we expect Antero sales points to be priced at even higher premiums to NYMEX as these LNG facilities compete for supply. A key competitive advantage between Antero versus our peers. With that, I will turn it over to Mike Kennedy, Antero’s CFO.

Michael Kennedy: Thanks, Justin. First, I’d like to add some additional comments on how we view the outlook for natural gas. Slide number 13 examines the historical relationship between storage levels and natural gas prices. This chart illustrates the high correlation that storage and pricing have to each other. As you would expect, when storage levels are below or above the five-year average, natural gas prices are low. And when storage levels are below the five-year average, prices trend higher. Since 2020, which is essentially when the industry moved the maintenance production when storage levels are flat with the five-year level, natural gas prices averaged $4 per Mcf. Looking at 2023, storage levels rose to as high as 25% above the five-year average, resulting in negative sentiment and low gas prices.

However, during the second half of 2023, record levels of power burn drove down this storage surplus, which sits at just 5% today. With production expected to moderate in the coming months and LNG exports hitting record highs, we anticipate storage levels will balance with the five-year average in 2024, thus providing support to natural gas prices. Expanding on this point, if you have today’s exact storage level, at this same time next year, your surplus would go from almost 200 Bcf over the five-year average today to a surplus of just 50 Bcf to next year’s five-year average. Next, I’d like to go a little deeper on the capital efficiency improvements that Paul touched on in his comments. The scatter plot on Slide number 14 illustrates the year-over-year change in production on the Y axis and the year-over-year change in drilling and completion capital on the X axis for the Appalachian E&Ps. While targeting a maintenance capital program Antero’s third quarter 2023 production actually grew 9% year-over-year.

Conversely, while our peer group attempted to target a maintenance capital program, their volumes actually declined year-over-year. When you compare the production growth to the drilling and completion capital invested to deliver that growth, we have been far and away the most capital efficient operator in Appalachia. As a rule of thumb, internally, we view each $100 million change of capital to result in approximately $100 million day change in production both up and down. Exit rate 2022 to exit rate 2023, we expect production growth of $225 million per day, which implies that our capital efficiency gains and well performance have reduced true maintenance capital by roughly $225 million, all else equal. This implies a true maintenance capital budget to hold 2022 volumes of 3.2 Bcfe a day of approximately $650 million to $700 million.

Looking ahead to 2024, our improved capital efficiency and well performance provides us with significant flexibility during our upcoming budgeting process to either hold our current third and fourth quarter volumes flat at capital approximately 10% lower than our 2023 capital or to hold our previously communicated maintenance volumes of 3.35 to 3.4 Bcfe a day at an even lower capital level. Either way, this lower capital outlook combined with a higher natural gas strip is expected to lead substantial free cash flow in 2024 and beyond. With that, I will now turn the call over to the operator for questions.

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Q&A Session

Operator: Thank you. At this time, we’ll be conducting a question-and-answer session. [Operator Instructions] Our first question today comes from Bert Donnes of Truist. Please proceed with your question.

Bert Donnes: Hi, good morning, guys. On the difference between the 10% lower capital program versus the meaningfully lower capital, you just addressed some of the questions, but what spurred the change in the messaging? Is it just the efficiencies you’re seeing? Is there some sort of investor feedback or are you looking at the strip and that changed your mind? Or was this always the plan? You just laid it out a little bit simpler for us the first time.

Michael Kennedy: Another change is our production is well ahead of expectations. We didn’t anticipate to be $225 million a day over exit rate to exit rate. We’ve now raised our guidance twice throughout the year. And we expect gross well head volumes in Q4 to be higher than Q3 as well. And so just the well performance, the capital efficiency, all those assumptions underlying those have improved. And so we have to figure out in this upcoming budget process, the assumptions that we use, how we risk those, we typically have some risking. That’s why we always hit our numbers and go from there and see which levels we want to hit. We can dial in pretty much any production we want at any capital at the required capital level. So when you change those assumptions, it changes the capital. So 10% would be holding kind of the current run rate. We’d be 10% lower. But if we held the previously communicated guidance for maintenance capital, it’d be well below that 10%.

Bert Donnes: That’s great. And then my follow-up is kind of related. But say, the strip plays out, maybe we actually get a few cold winters. LNG demand doesn’t get pushed out. You see an attractive growth environment, does Antero’s kind of stable operations plan change? Or do you maybe stair step just up to a higher level and maybe hedge some of that risk away? I have a feeling some of your peers would probably try to respond to a bull and bear environment. But do you stay stable? Or with your new efficient program, maybe you could respond to the strip. That’s all, thanks.

Paul Rady: No, we’d stay stable. We’re trying to achieve maintenance capital. As we said, it just continues to improve. So ultimately, we’ll get it to a level where the maintenance capital assumptions we have are equate to actuals. And so we’ll stay at that maintenance capital program and then pay down the remainder of our debt and return capital to shareholders.

Bert Donnes: Thanks so much.

Operator: The next question comes from Umang Choudhary of Goldman Sachs. Please proceed with your question.

Umang Choudhary: Hi, good morning and thank you for taking my questions. I appreciate all the details on the propane macro. I wanted to circle back on your thoughts around upside and both downside risk to propane prices heading into next year. Like you said, you are positive on propane demand for 2024 with the build out of PDH facility, but wanted to understand if you see any downside risk there. And also on the supply side, given healthy oil prices, do you see any risk of supply exceeding EIA expectations of around 50,000 barrels per day of growth next year?

Paul Rady: Yes. Good morning, Umang. On the propane side, I would say, the biggest risks we kind of highlighted in our comments on what could happen in the Gulf Coast with Mont-Bellevue pricing. If you see those docks really hit full utilization. We even saw here in the third quarter, three of the big four facilities had extended, planned or unplanned maintenance or I guess, third quarter into fourth quarter. That has driven some lower propane export numbers despite the records that we’ve reported. So I think we would have seen higher overall export numbers here in recent months and lower inventories than where we stand today had that not happened. But it points to the fact that those facilities are becoming increasingly higher utilized and that’s really a big differentiator for Antero.