Greetings, and welcome to Antero Resources Third Quarter 2022 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Brendan Krueger, Vice President of Finance. Thank you. You may begin.

Thank you, operator. Thank you for joining us for Antero's third quarter 2022 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; and Justin Fowler, Senior Vice President of Gas Marketing and Transportation; and Dave Cannelongo, Senior Vice President of Liquids Marketing and Transportation. We will start today's call off with some initial comments for Mike.

Thank you, Brendan. Before we get into our more prepared quarterly remarks, we thought it was important to start by discussing the consistency in our financial performance highlighted by Antero's progress year-to-date on our return of capital efforts and debt reduction program. Slide #3 summarizes the consistent and repeatable results that you can expect from Antero as we continue to deliver on our stated goals of having a best-in-class balance sheet while also returning significant cash back to our shareholders. The top of the slide illustrates the increasing return of capital through each quarter this year because we began focusing so aggressively on reducing debt several years ago, we are now in position to return higher percentages of our free cash flow to our shareholders. This is an important distinction compared to many of our peers who will need to continue taking a balanced approach between debt reduction and cash return in order to improve their balance sheets. As you can see on the top of the slide, we have purchased 21.5 million shares for a total of $730 million during the first nine months of this year. At the bottom of the slide, you see we continue to aggressively reduce debt, including more than $400 million in this quarter alone. This brings our year-to-date debt reduction total to nearly $1 billion. Since the beginning of our debt reduction program in the fourth quarter of 2019, we have now reduced debt by $2.6 billion from $3.8 billion to less than $1.2 billion at the end of the third quarter. Just yesterday, we announced a $1 billion increase in our share repurchase program, bringing the total program to $2 billion. This increase highlights the confidence we have in the predictability of Antero's business and our continued ability to repurchase a significant amount of shares in 2023. With that, I will now turn the call over to our Chairman, CEO and President, Paul Rady.

Thanks, Mike. This repeatable business model that Mike just discussed incorporates a strong balance sheet, scale with a diverse product mix and access to premium-priced markets utilizing our firm transportation portfolio. Also important to delivering predictable results is a large core inventory position with low breakeven costs. Let's turn to Slide # 4 titled Largest Low Cost Inventory. This chart is based on a recent Enverus analysis. It ranks Appalachia producers by the amount of Marcellus inventory that they have with breakeven cost below $2 per Mcf. As you can see, Antero has the greatest amount of low-cost inventory in the basin, more than 800 future locations which will continue to drive our consistent performance well into the future. Now to expand on Antero's predictable business model, let's discuss our inventory depth. Turning to Slide #5 titled Organic Land Acquisitions, we see that across the oil and gas industry, we've seen an increase in both public and private corporate acquisitions over the last couple of years including several large transactions during the third quarter alone. These larger acquisitions were close to $5 million per location. Over this time, we have continued to maintain our focus on our core acreage footprint with a particular emphasis of spending capital on organic lease acquisitions. As opposed to larger transactions that can dilute our equity, create a large overhang on the stock and lever our balance sheet we have preferred to pick up smaller, more tailored acreage packages within our core liquids-rich position in West Virginia, where we continue to see tremendous well results. As an example, during the quarter, we spent $46 million on land, a portion of which was used to add 25 additional drilling locations at less than $1 million per location. During the first nine months of 2022, Antero's organic leasing program has added approximately 60 drilling locations at an average cost of less than $1 million per location essentially offsetting our maintenance capital plan that assumes an average of 60 to 65 wells per year. We believe this organic leasing program is the most cost-efficient approach to extending our core inventory position. This approach adds another layer to the predictability of our business strategy, and it lessens any need to make a large M&A transaction. Now to touch on the current natural gas fundamentals and how they directly favor Antero, I'm going to turn it over to our Senior Vice President of Gas Marketing and Transportation, Justin Fowler.

Thanks, Paul. Nothing demonstrates Antero's predictable business more than our firm transportation portfolio. Let's turn to Slide #6 titled Antero's Peer-Leading Exposure To Premium Markets. This slide highlights Antero's unique ability to avoid the pitfalls of regional capacity constraints and wide basis discounts, which we saw once again during the third quarter. Antero owns 2.3 Bcf per day of firm transportation to the U.S. Gulf Coast LNG fairway into the midline Cove Point LNG terminal, which represents approximately 75% of Antero's total natural gas production. This firm transport allowed Antero to achieve a $0.49 per Mcf premium to NYMEX Henry Hub in the quarter despite the wide basis differentials realized by the industry. Looking ahead to 2023, we expect regional basis differentials in Appalachia, the Permian Basin and the Haynesville to remain wide with deeper discounts due to the pipeline capacity constraints. In the Permian, we do not expect basis improvement or meaningful supply growth reaching markets until the third quarter of 2023 when incremental pipeline capacity is expected to be completed. This Permian Basin lack of pipeline outlets was highlighted this week through the negative absolute Waha cash price, the lowest price in two years. The Haynesville is in a similar constrained position over the next nine to 12 months as it awaits incremental pipeline capacity. Having the firm transport capacity is important in avoiding the price volatility from regional basis blowouts. However, equally as important as having access to the premium-priced hubs. The slide illustrates that the primary hubs that Antero sell its gas into have all seen basis improvement over the last few years. Conversely, you can see that the local negative pricing differential that many of our Appalachian peers sell their gas into has deteriorated by $0.38 to approximately $1 below NYMEX Henry Hub. As additional LNG trains and terminals are completed, we expect that the pricing hubs where we sell the majority of our gas will see larger and larger positive basis premiums in NYMEX. With the expected increase in LNG exports, both on an absolute and relative percentage of overall U. S. supply, we believe these premium hubs will see price increase more dramatically than NYMEX as they link directly to international prices. This environment will provide further support to Antero's strategic position today accessing LNG markets. Looking ahead, we continue to believe that the labor and equipment tightness along with infrastructure constraints will make natural gas growth challenging. Historically, low coal storage leading to the inability for switching and a wide global arbitrage spread that suggests LNG exports will remain at above maximum utilization this winter supports our positive outlook for natural gas prices going forward. With that, I will turn it over to our Senior Vice President of Liquids Marketing and Transportation, Dave Cannelongo for his comments.

Thanks, Justin. Over the past few months, liquids pricing has been volatile as the market weighs macroeconomic concerns against continued supply uncertainty and elevated geopolitical risk. Oil prices have retreated from the highs seen this spring immediately following the invasion of Ukraine, largely due to China's COVID-Zero policy, supply chain bottlenecks and high levels of inflation impacting GDP growth and currency values worldwide. U.S. C3+ NGL prices have mirrored the drop in oil over the past two quarters. Looking at propane specifically, Slide #7 titled Propane Market Fundamentals shows that propane inventories saw sizable injections during the third quarter and are now in line with the five-year average levels. However, we will note that the rate of stock builds has leveled off in reasonably as we are entering the start of winter demand season. And importantly, days of supply remains 13% below the five-year average. Turning to Slide #8 titled Global NGL Production versus LPG Export. Looking on the supply side the graph on the lower left highlights the growth environment for U.S. NGL production compared with stagnant to declining production expected in the rest of the world. Industry forecast show U.S. NGL production growing 8% year-over-year from 2022 to 2023, while anticipating a 2% decline in supply from the rest of the world over that same period with additional downside risks from further OPEC+ cuts. Taken together, the anticipated decline in supply of NGLs and the rest of the world, and the normalization of demand growth expected in the market and a bullish picture for U.S. NGL pricing. Continuing on Slide #8, the graph on the right shows the relative weakness in export levels observed during second quarter and third quarter this year that fueled the strong injection season for propane. However, we anticipate a return to healthier export…

Thanks, Dave. Let's turn to Slide #10 titled Antero Free Cash Flow Profile. Antero's in the strongest financial position in company history. During the third quarter, we generated approximately $800 million in free cash flow, which was used to reduce debt by over $400 million and to purchase $380 million of stock, as I mentioned in my opening remarks. Following the completion of our $300 million tender offer during the third quarter, we are now targeting greater than 50% of free cash flow to be used through the share repurchase program. As shown on the chart, Antero's 2022 development plan is expected to generate just over $2 billion of free cash flow. In 2023, we expect free cash flow to be similar to $22 million despite the backwardated strip prices as the vast majority of our hedges roll off by January 1, 2023. Based on today's commodity prices, we do not expect to pay cash taxes in 2023 with first cash taxes being paid in 2024. This substantial free cash flow will enable us to continue returning capital to our shareholders while also continuing to pay down debt. Turning to Slide #11. Let's discuss the continued progress on our ESG initiatives. During 2022, we took significant steps towards achieving our 2025 climate targets. We have now reduced our methane leak loss rate by 65%, surpassing our initial 2025 target of a 50% reduction. Our Scope 1 GHG intensity has been reduced by 39%, well ahead of our initial 2025 target of 10%. And lastly, we remain on track to be net zero on both Scope 1 and Scope 2 GHG emissions by 2025, with a 36% reduction to date driven by operational initiatives. Turning to Slide #12, you can see that Antero is ranked #1 for the lowest GHG intensity among our peers. While we are incredibly proud of these accomplishments to date, we look forward to maintaining our peer-leading ESG position in the years ahead. With that, I will now turn the call over to the operator for questions.

[Operator Instructions] Our first question comes from the line of Neal Dingmann with Truist.

As you've done a good job you all referenced, I think, very accurately the constraints we've seen in the Haynesville as well as in the Northeast. So I'm just wondering would it be safe to say -- I guess, looking at Slide 6, particularly, would it be safe to say that you all are expecting higher differentials or you're guiding to maybe higher differentials as we turn into '23?

Higher differentials for the industry; but for us, it will be very similar to what we experienced in '22.

Yes, that's what I was getting at, exactly right. I guess your point is for you all you think would be the same? Or could we see an improvement based on would there be any change in takeaway? Or are you thinking just more of the same, which has obviously been quite good for you all.

Yes, more of the same. It will be a premium. I think this year or in the third quarter, it was a $0.49 premium, it will be similar in the fourth quarter. Next year on $5 gas, I would assume more than a $0.25 premium to NYMEX.

Great. And then, Paul, obviously, this new environment now that the market's been in or the E&Ps have been enough for quite some time, you guys really done a good job embracing it with this obviously fantastic buybacks going forward. When you -- I look at your inventory, you all have accurately described having a material amount -- is there any thoughts about maybe given the high returns if gas continues to move back up, maybe accelerating production into '23? Or is it still the focus with this type of buyback potential, just more of the same?

Yes, I would say more of the same, Neal, that yes, you're right that we do have a very impressive inventory that we can go to, but we're pretty committed to our maintenance capital level to go higher than that creates quite a few more come commitments, say, in processing, fractionation, all along the line. So we're really happy at this level and have a clear path to the debt paydowns and share buybacks. So that's pretty much our strategy for the near term.

Our next question comes from the line of Subhash Chandra with Benchmark.

Yes, Slide 10. Maybe ask for some detail there or some color there with the free cash flow outlook. Any color on CapEx? And we've had some peers here talk about 20% type inflation for next year. So if you have any thoughts on that? And then on OpEx, which of the OpEx items you might consider sticky versus variable?

Thanks, Subhash. We don't see the 20% level. I think we see more around the 10% level for inflation in '23 versus '22. And then on the OpEx, we do have some variable components. Really, they're based on natural gas prices. Just the fuel needed to compress our gas and then transport it on the long-haul pipe adds a little bit of variable costs. So I think you saw that in the third quarter. Costs from the GP&T were up approximately $0.20 and up $0.05 in production taxes when gas went to $8 to $9, but those costs come off going into the fourth quarter at a $6 level. Those will retreat back to the level we saw in the second quarter. So it seems there would be about $0.10 variable component based on every dollar of natural gas prices.

Okay. Excellent. And then on uses of free cash flow. Some companies, I think, have express a formula that you guys have. But even, I guess, in the formula, they're still looking at some level of cash wording for lack of a better term. But how do you think about buying back stock and you've expressed your debt repurchase ambitions. But then finally, in terms of the stockpiling cash, do you feel any need to do that?

No. We try not to stockpile cash. We'd rather use it to pay down debt or buy back shares. Every quarter, we take a look at what our free cash flow estimates are going to be in design our program around maximizing the use of that free cash flow by first paying down debt and then buying back shares. Now that we're down the $1.1 billion of debt, those reversed. Now it's more of the majority going towards buying back shares and then whatever we can find in the open market, we try to execute on those debt reduction transactions as well.

Our next question comes from the line of Arun Jayaram with JPMorgan.

Mike, maybe start with you. I was wondering if you could provide any kind of soft guidance or commentary on 2023. We heard your comments on now expecting no cash taxes, but I want to get your thoughts on thoughts on maybe CapEx, land spend and just general volume thoughts for next year?

Yes, I think we talked about capital, the 10% inflation versus '22 and then land, we've been much more successful than we thought this year, which has been terrific and adding those locations, great land spend this year. Probably, we'll first think we won't be quite as successful next year, so probably lower. But hopefully, we could have a repeat of this year. But right now, I'm not expecting that.

Got it. And that would be largely sort of maintenance-type program?

Yes, maintenance capital, three rigs, two completion crews.

I hate to use one of my bullets on hedging in terms of my questions. But Mike, you did post a hedge portfolio slide on your deck last night. So I just wanted to give us a sense of how the -- how should we be accounting for the hedges on the VPPs and the ORRI?

Those were obviously entered into 2020, and they put on hedges at that timeframe for the length of those transactions. So the ORRI goes through '23 and the VPP goes through '27 or -- yes, '27. So they put hedges in place. Those hedges are on their account, but we consolidate them in our results. So going forward, you should model those hedges when you get our estimates and drive our estimates you should include the hedges in those estimates.

Our next question comes from the line of Umang Choudhary with Goldman Sachs.

My first question was on cash cost. I wanted to follow up on that comment on sticky costs versus variable cost, especially as it relates to gathering, processing and transportation costs what portion of the cost increase do you believe will be sticky next year, which is linked, I guess, more to CPI? And then can you give us a kind of a read-through as to how we should think about 2023 cost structure -- cash cost structure given all the moving pieces on gas prices, diesel prices and the CPI numbers?

Yes. So the cash costs will come down in '23, they'll be more similar to I think what we'll see in the fourth quarter because it's around $5 gas and $40 NGLs. But we do have about 3% to 4% of our costs are variable, I would say, when it comes to fuel transport and compression and then it's about 4.5% on production taxes versus realized price, that's variable as well. And then Sherwood and Smithburg the largest processing facility in North America and the greatest consumer of electricity in the State of West Virginia. So we do have exposure to electricity costs there as well. So you add that all up, like I said, it's about a $0.10 per dollar variable cost for natural gas prices. But it should come down in '23, just due to lower commodity prices. I hope it goes up because that means gas would go higher and we're unhedged starting January 1, and it would be terrific if natural gas prices continue to be at these elevated levels, but it should come back down to more of a Q2 level starting here in Q4.

Got it. That's really helpful. And then as you think about 2023, right, like I'm just trying to understand the path your production will take given your accelerating activity in the fourth quarter. Should we expect the tails to be lower next year or similar to the 60 to 65 levels in 2023, just trying to understand all the moving pieces when it comes to activity and production cadence following the change in your spending this year?

Yes, same level. There was a pad accelerated into late December but that's really just going to contribute to production in 2023. I have a couple of percent growth in Q4, and then we'll have similar amount of growth in the Q1 and these wells continue to come on. So we call it a maintenance capital level, but it's flat to up going forward.

Our next question comes from the line of Kevin MacCurdy with Pickering Energy Partners.

Just a follow up on that. I wondered if you could talk a little bit about your decision to add that activity and pull it forward into the fourth quarter instead of completing those wells in the first quarter of next year.

Yes. Well, throughout the year, what we've noted is in order to keep our three rig and two completion crew development program moving forward, we had to sign longer-term agreements with the rigs and the completion crews. And then doing that it just made sense to continue to drill and complete the wells and not have our typical holiday normally in November and December around completion. So with our new rig contracts and completion crew contracts that are signed up for the entirety of '22 and '23, it's very efficient, just to continue to have them running. And with our development program, and with our Antero Midstream's terrific service of our wells and our ability to get wells on, it seems like that's a particular competitive advantage for us. So we continue to enjoy that, and we'll continue to bring on wells as efficiently as possible.

So if I'm reading that right, that kind of implies that production will be a little bit higher into 2023 than it otherwise would have been?

Pad would have come on in January or maybe getting a month of extra production. But yes, '23 production should be higher than '22 production.

Great. And as a follow-up, any liquidity limitations on your buybacks heading forwards? Or do you expect that you can kind of do a similar amount roughly that $400 million each quarter heading forward?

Will depend on the free cash flow, but the majority of the free cash flow will be buying back shares. Our stock is actually very liquid. So there are no liquidity constraints around us buying it back.

Our next question comes from the line of David Deckelbaum with Cowen.

I wanted to just ask a quick confirmation. Could you give any guidance on how many incremental ethane barrels you're expecting in the fourth quarter? Should we be sort of modeling I guess, just in regards to the commissioning of the Shell Cracker?

Yes, the commissioning is going fairly well. We should have -- right now, it looks like we're around 55,000 barrels of ethane in the third quarter, that should approach 75,000 barrels a day for the fourth quarter.

Okay. Perfect, Mike. And then just to revisit it. I think it's your earliest or next debt issuance that you can call in 2024, but I guess given where debt is now at roughly $1 billion, is it fair to say that you're kind of done with your debt reduction goals over the next couple of years?

Obviously, the majority of it because we've paid down the vast majority of the debt. But we'll continue to try to be opportunistic, David, really looking at the open market, if it's available to even transact or they're not very liquid. So the ability to get those in going forward is limited, but we'll continue to see if there's any opportunities for us. But our thoughts are that it's really going to be more weighted towards buying back the shares.

And then maybe this is a little bit more difficult of a question to answer. But when you looked at some of the land spend this year, do you view a better use of capital picking up some of those additional locations on a valuation basis or repurchasing your own shares?

Part of the land, land -- each stick. I think we looked at it at today's prices were $30 million to $40 million. So if you're spending $1 million per location and it generates after drilling net of all the costs $30 million to $40 million that’s best we can do, and it's probably in the heart of our development area. So it's as efficient as possible capital we can spend and we have all the Midstream there. We have all the infrastructure, all the transport. We have the processing and it just lengthens that inventory. So we continue to prioritize that. That's the best capital we can spend.

Got it. Hence, I guess the suggestion you wouldn't be able to necessarily replicate that spend in '23?

That's -- yes. I doubt we'll guide to that, but hopefully, we can achieve '22 results.

Our next question is a follow-up question from Subhash Chandra.

Yes. Two questions. First on the cash tax commentary. I know it's out there, but what sort of scale of cash taxes do you expect maybe based on strip in '24.

It comes to a full -- close all full, I mean, you obviously can deduct your capital and deduct some stock comp expense and you have some other deductions, but it comes close to that 20%.

Got it. Okay. And should ask a clarification on the Shell commentary. Those were gross sales or gross consumption?

No. Net ethane for us. You're talking about 55,000 barrels and going to 75,000. Fourth quarter it’s net.

Net. Okay.

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

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

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.