ANTERO RESOURCES Corp Q1 FY2024 Earnings Call

Greetings, and welcome to the Antero Resources First Quarter 2024 Earnings Call. As a reminder, this conference is being recorded.

Good morning. Thank you for joining us for Antero's First Quarter 2024 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.

Thank you, Brendan. Good morning, everyone. I'll start my comments on Slide #3 titled, 'Drilling and Completion Efficiencies.' As I started my comments off last quarter, the year 2023 was a transformational year for Antero regarding operational efficiency gains. This year, 2024, continues that trend. Starting with the chart on the top left-hand side of the slide, days per 10,000 lateral feet drilled averaged 5.4 days during the first quarter, down from 5.5 days in 2023. On the completion side, we averaged a quarterly record of 11.3 stages per day during the first quarter, an increase from the pace in 2023 of just under 11 stages per day. These operational improvements result in shorter cycle times, as shown on the bottom of the page. Our year-to-date cycle time per pad is currently trending ahead of last year's 2023 average. There are many inputs that lead to these operational improvements as every single line item gets examined by our team. However, the most impactful change in 2024 has been improved efficiency in zipper swaps that allows us to move from well to well on a pad without having any true downtime. We estimate that this new completion technology will save more than an hour of pumping time each day and will result in further increases in completion times. Our operations also benefit from Antero Midstream's water infrastructure, providing industry-leading water deliverability rates for our completions. Avoiding the use of water trucks significantly reduces pad site congestion that we would otherwise get from water and sand trucks accessing the pad, something that many of our peers have to contend with. Now let's look at how these improvements led to our peer-leading capital efficiency.

Thanks, Paul. The start of 2024 demonstrated improved fundamentals for liquids. Ongoing geopolitical tension, particularly in the Middle East, has increased the risk premium on crude pricing in 2024 year-to-date. Internationally, the canal-related challenges seen last year have diminished, but global geopolitical tensions remain high. On the domestic front, record propane demand occurred simultaneously with significant January freeze-offs drawing down storage and resulting in upward pressure on propane prices. Propane as a percentage of WTI has averaged 44% since the start of this year compared with 36% in the fourth quarter of 2023. Exports have remained a driving force in the propane market and are showing strong year-over-year growth driven by growing global demand. This year, China's PDH build-out continues to progress with three new facilities placed in service in the first quarter and another three expected to start up in the second quarter totaling nearly 170,000 barrels per day of capacity additions in the first half of 2024. At the same time, propane exports have averaged 1.8 million barrels per day in 2024 year-to-date, an increase of 14% over the average in 2023. Notably, propane exports reported an all-time record high this week at over 2.3 million barrels per day. This export growth is depicted on Slide 5. The chart illustrates that the U.S. remains the most important source of waterborne export LPG to meet fast-growing global demand. As a reminder, Antero exports over 50% of our C3+ production skewed heavily towards propane directly out of the Marcus Hook terminal in Pennsylvania. This year, we have elected to sell a greater portion of our waterborne barrels against international indices as well as in the spot market instead of entering into longer Mont Belvieu linked term deals. In the event that Mont Belvieu propane prices disconnect from European and Asian pricing due to dock constraints or rising domestic storage levels, Antero is well positioned to avoid additional Mont Belvieu exposure. The strength in international pricing has allowed us to increase our guidance for full year 2024 C3+ differentials to a premium to Mont Belvieu pricing. As Paul just touched on, our first quarter results benefited from our significant exposure to liquids prices. Slide #6 illustrates the approximately 125,000 barrels per day of C3+ NGLs plus condensate that we produce. You can see the breakout of those products in the barrel on the left. The barrel on the right-hand side of the slide separates the approximately 40,000 barrels per day of liquids that are closely linked to WTI oil prices.

Thanks, Dave. I'd like to open it up by turning to Slide #7 titled, 'Not all Transport to the U.S. Gulf Coast is Equal.' 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 growing LNG demand along the Gulf Coast and importantly, in the Tier 1 pricing points in the vicinity of the major LNG facilities. With several new LNG facilities starting up over the next year, we expect to see a widening spread between sales points near Henry Hub and sales points outside of this premium market. The blue call-out box highlights a recent quote from a research commodity team that emphasizes this view. They believe sales points within 100 miles of Henry Hub can see prices comfortably above $5 per MMBtu, while sales points outside of that range could price at $3 to $4 per MMBtu. Looking closely at this map, the yellow stars highlight Antero sales points and are located well within this 100-mile range to Henry Hub. These sales points were strategically selected beginning over 10 years ago in order to access the feeder lines at the doorstep of the LNG fairway. The chart on the top left-hand side of this slide highlights that Antero sells 75% of our gas at Henry Hub linked prices while our peers, on average, sell less than 15% of their natural gas into this premium market.

Thanks, Justin. I'd like to start with Slide #10 and our continued focus on reducing absolute debt. We plan to allocate future free cash flow to paying down the remainder of the credit facility balance and the higher coupon near-term notes we have outstanding. We will then be in a position to return to our 50-50 strategy of 50% of free cash flow going to debt reduction and 50% going towards our share repurchase program. Turning to Slide #11. This slide compares 2024 free cash flow breakeven levels. We highlighted our peer-leading breakeven price shown on this slide during our last conference call. Our $2.27 breakeven level compares to the average NYMEX natural gas price of $2.24 in the first quarter. Despite the low price, Antero generated an unhedged $10 million of free cash flow during the first quarter.

Maybe one for Justin. Justin, given the strong demand growth potential for gas to the end of the decade, I was wondering maybe if you could comment a little bit more on what you see as kind of advantaged molecules from a margin perspective in this kind of environment. Obviously, historically, Appalachia has garnered a discount just given the lack of takeaway capacity in some of the gas-on-gas competition. But would rising demand in that area for data centers, et cetera, could that start to narrow some of the discounts that we've seen for Appalachia gas?

Arun, it's Justin. Yes. So when we look at just the FT 2 Bcf down to the LNG corridor, we see those premiums continuing to gain value versus Henry Hub in the outer years. So we think that our delivery points in our Southeast head station, CGT onshore, TGP 500L will continue to be very strong in terms of Appalachia versus AI data centers, et cetera, and the basis compressing and gaining value back towards Henry. Antero will have that ability to sell local production volumes as well if those prices increase seasonally or in different months of the year because we do, again, have a transport position of 75% to the Gulf. So we can measure that on variable costs, et cetera, and make that decision over time.

Yes, Arun, we've done that now. This is Dave. We've done that flex, in particular, in the shoulder to shoulder season through the summer. It will be reported in our second and third quarter results where it shows the amount of volume that we export versus domestic, and those percentages go higher in the summer where we are, at times, well over 80% of our propane in particular is going to the dock. So we've flexed that already. I think there are some ways to take that higher if the market called for it, but we don't have a lot left in the domestic pool during those times of the year to begin with. And then on the freight rates, I mean things have improved dramatically since where we were late last year, you had all the concerns about the Panama Canal and how much that was going to de-optimize the global LPG shipping fleet and what actually happened. What we're seeing is more LPG ships getting through the Panama Canal since that announcement was made. I think first, the canal has been able to move more ships, in general, through the canal than they initially had forecasted when they announced those restrictions. So we've seen now freight rates collapse dramatically from where we were in the fourth quarter. And that's ultimately allowing prices at the dock to be closer linked to the international price. And we had a large build-out of VLGC vessels last year, over 40 VLGCs. We're kind of waiting for that to have its effect, and you're now seeing that today in the forward freight pricing.

Probably for Dave first. Dave, what do you think on dock capacity is? And that 2.3 million was a shocking number, are we pretty close? And I guess those propane hedges, you kind of added there show some caution through December. Maybe some updated commentary there.

Yes. I think we are there on the dock capacity, Subhasish. The number, the 2.3 million, it is a bit of a head-scratcher that can happen just based on timing of when ships officially loaded. If they kind of fall a minute into the next week, that can certainly allow a number like that to happen. But we ultimately believe that's well above the kind of average rate that you could run across the U.S. dock. So it's somewhere in that 1.85 million to 1.9 million barrels a day of propane because you still have butane that needs to move across those docks as well. So we'll see what they're able to hit this summer. It's sometimes when it's hotter, it de-optimizes their refrigeration a bit. So I think we'll expect to see those docks highly utilized this summer, but I think we're at about the levels of what we expect that they can do until the second half of next year when there are some expansion projects on the way from the Gulf Coast midstream players. And then on the hedges, yes, great question. We've talked about our concerns around propane pricing and kind of a decoupling of Mont Belvieu if you saw inventory levels rise as a result of these docks being fully utilized. And so we just thought it was prudent to while we do export the vast majority of our propane, we still had some domestic exposure, and we just wanted to be conservative with that and take that risk off the table if we saw things play out similar to what we saw last year when propane was down in the $0.65 per gallon range. I thought it was a wise move at this time.

Yes. But put some context around that's 10,000 barrels a day, which is on 15% of our total propane production because the vast majority gets international pricing.

Yes, Subhasish, the zipper fracs have been in use for quite some time. However, in earlier stages, there was a lot of decoupling and re-hooking for different wells. We've now improved our efficiency significantly. By simply flipping some switches and turning some valves, we can switch the zipper frac to different wells while pumping. This has greatly reduced downtime, which used to take at least an hour when changing zipper fracs.

Just wanted to ask around the data center demand question a little bit differently. You've continued to kind of avoid the temptation to go overseas with an LNG contract. Is there maybe a thought process that if we see a data center-driven boost, maybe there's no reason to lead to the U.S.? And does that lead you to maybe trying to lock in a long-term contract in the U.S.

Yes. No, it wasn't around the data centers. It's just around we're the only company that can really get molecules to the docks or to the LNG actual facilities. So we didn't have any need to enter into long-term contracts around that. We've already done our commitments on the pipeline in itself. And so we just wanted to stay floating and retain optionality for us on what that pricing would look like when they have to compete for our gas. But with the data centers, that actually adds more, obviously, demand for that gas. So that competition just continues to grow. Yes, it's really dominated by liquids pricing. I mentioned on prior calls, we do have one pad. I mean we're only running 2 rigs and 1 completion through. We do have 1 pad in the capital program that's a spot we have had for the third quarter of this year, and that's one that's still to be determined. If it was based on current month prices today, that was one that would potentially be deferred and then that would put you at the low end of the capital guidance range. The other pad is just one completion line. So running that with our 2 rigs is very efficient, and it's very much 1,275 to 1,300 Btu gas, so very high in the liquids content. So that's what drives the economics. I think in the first quarter of our revenue, 55% was liquids and only 45% was gas. So you can see how much the liquids prices really influence the economics of these wells.

I had a couple of questions on capital allocation. The first one on Slide 10, you've done a great job of getting your debt down to this level, and you talk about the next area to deploy free cash flow is to pay down your credit facility balance. So maybe curious on your perspective of how shareholder return specifically buybacks fit into this equation. And given the strengthening of the balance sheet, when do you think you're at that inflection point to buy back stock?

Yes. I said in the remarks, the first call on that free cash flow is to pay down the credit facility and that near-term maturity in '26. So that's about $500 million. And then after that, we'll return to our 50-50 strategy of paying down debt plus buying back shares. It will depend on commodity prices when we actually achieve those. But based on today's commodity prices, it'd be in the first half of next year.

Dave, I wanted to circle back to the liquids market, and I apologize if you did hit on this in your answers, I may have missed it, but I was hoping you could comment just on storage levels at the moment. Specifically, them being above the 5-year it appears as well as the production coming out of PADD 3 and just where do you see those playing out through the summer?

Jacob, this is Dave. If you go back to the first quarter, we actually had that polar vortex in January went from the top of the 5-year range to the 5-year average and then kind of continued along that trend until the last 5 or 6 weeks. We've had I would say some pretty unusual EIA data. It didn't really change at all for 1 month, 1.5 months, and then we had significant change last week and then a below expectation build this week. So we are back kind of in that between the 5-year range and the top of the range below last year, but above that 5-year average. And we'll see what the inflection point looks like, how does that slope rise over the summer. I think there's a lot of different forecasts out there on propane production this year. Hard to say exactly who's right on that. We do pay attention to the rig count in all the basins and watch that. And so that's, again, part of what drove our earlier comments on just taking that small amount of domestic Mont Belvieu propane exposure we have doing some hedging there this year. But sorry, I answered all your questions there, Jacob?

Yes. As you correctly noted, they no longer participate in our wells that concluded on March 31, 2023, but there is still a runoff of the PDP base. That will revert back to us once they reach certain rates of return. Currently, we are forecasting this to begin in 2026.

There are no further questions in the queue. I'd like to hand it back to management for closing remarks.

Yes. Thank you for joining us on today's call. Please reach out if any further questions. Thanks.

Ladies and gentlemen, this does conclude today's teleconference. Thank you for your participation. You may disconnect your lines at this time, and have a wonderful day.