Greetings, and welcome to the Antero Resources 2Q 2022 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. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Brendan Krueger, Vice President of Finance. You may begin. Thank you, operator. Thank you for joining us for Antero's second 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. Before we start our comments, I would like to first remind you that during this call, Antero management will make forward-looking statements. Such statements are based on our current judgments regarding factors that will impact the future performance of Antero and are subject to a number of risks and uncertainties, many of which are beyond Antero's control. Actual outcomes and results could materially differ from what is expressed, implied, or forecast in such statements. Today's call may also 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, Justin Fowler, Senior Vice President of Gas Marketing & Transportation, and Dave Cannelongo, Senior Vice President of Liquids Marketing & Transportation. I will now turn the call over to Paul. Thanks, Brendan. The second quarter was an exceptional quarter for Antero, both operationally and financially. We delivered quarterly company records for adjusted EBITDAX and free cash flow. We reduced debt by nearly $400 million while also accelerating capital returns to our shareholders. Behind these excellent results is consistently strong well performance. I'd like to begin the call by highlighting some outstanding well results from recent pads that we placed to sales during this year. The plots on slide number three show the cumulative equivalent production over the first 100 to 180 days of the well. As you can see, the pads we have recently placed to sales have outperformed the average production from our average 2018 through average 2021 wells. One of our pads located in the Ohio Utica is comprised of six wells with an average lateral length of over 15,000 feet, and they averaged on a per well basis 29 million cubic feet equivalent per day for the first 60 days of production, including a company record 1,750 barrels a day of liquids per well. Just to emphasize the magnitude of this pad's production, this totals 175 million a day in over 10,000 barrels of liquids for the total pad. This is 28% higher than the 2020 average and 25% higher than the 2021 average. Another pad located in the Marcellus, also comprised of six wells with an average lateral length of 14,500 feet, averaged over 32 million cubic feet equivalent per day per well in the first 60 days, including 1,630 barrels of liquids per well. Again, this pad totals over a hundred and eighty million cubic feet a day and 9,000 barrels of liquids. This is 36% and 33% higher than the 2020 and 2021 average, respectively. Most notably, both these pads are projected to have payout periods of less than five months from the date that they were turned to sales. One of the factors driving this impressive performance is the strong liquids volume. Turning to slide four, I'd like to point out the progression of our average wells cumulative C3+ NGL and oil production for the first 150 to 180 days by year since 2018. The average per well liquids production of our 2022 wells for the first 100 days represents a 23% increase from the previous year and a 109% increase from 2018. The performance of the recent wells and the continued improvement year over year is a testament to the quality and depth of our liquids-rich core position and our strategy on the development of this inventory. These pads are located in the liquids-rich fairway of Tyler and Wetzel Counties, where our five-year development plan is focused. Turning to slide five, titled Marcellus Peer Well Performance Comparison, let's take a look at how our wells stack up against some of our close peers on an equivalent production basis based on a recent Enverus report that has just recently been published. The plot on the page compares Antero's average cumulative production per well since 2020 to that of our Southwest Marcellus peers. As illustrated on the page, Antero's average cumulative equivalent production per well is 22% greater than the peer average since 2020. This is another testament to the quality and depth of our core liquids-rich position. Further, while some peers may be experiencing inventory exhaustion, we have tremendous confidence in our five-year plan and beyond as we have been drilling some of the best wells in company history. Now, to expand on the discussion of inventory, let's turn to slide number six, titled Organic Land Acquisition. Across the oil and gas industry, we have seen an increase in both public and private corporate acquisitions over the last couple of years. During this time, we've continued to maintain our focus on our core acreage footprint, with a particular emphasis on spending capital on organic lease acquisitions. As opposed to larger transactions that can dilute your equity, create a large overhang on your stock, or lever up your balance sheet, we preferred to pick up smaller, more tailored acreage packages within our core liquids-rich position in West Virginia, where we continue to see very strong well results. As an example, during the quarter, we spent $49 million on land, a portion of which was used to add 25 additional drilling locations at less than $1 million per location. Since 2020, we have added approximately 100 drilling locations in the liquids-rich window of Tyler and Wetzel Counties, which equates to a year and a half of drilling inventory at an average of 65 wells per year under our maintenance capital plan. We believe this approach is much more cost-effective relative to many of the recent larger M&A transactions that averaged $1.5-$3 million per location. What makes this even more attractive, these locations are in our core areas where we are currently focused, providing further liquids-rich development runway and improving our overall operating efficiencies. Now let me turn to commodities and our hedging strategy. We continue to see a supportive macro outlook for all of our products, whether it be natural gas, NGLs, or oil. We have a strong balance sheet that gets stronger by the day, and we're confident in our drilling inventory and our ability to deliver our results. This leads us to our current view that we are not planning to add hedges on any of our products for the foreseeable future. Now, to expand on the current gas fundamentals and how they directly benefit Antero, I'm going to turn the call over to our Senior Vice President of Gas Marketing and Transportation, Justin Fowler. Thanks, Paul. Despite some inter-quarter volatility driven primarily by the Freeport LNG facility outage in Texas, natural gas prices are higher today than at the time of our last conference call. A combination of strong industrial demand, LNG exports that are 20% above last year, even with the Freeport outage, and record power generation demand continue to push natural gas prices higher. In addition, the supply response continues to underwhelm due to pipeline constraints in the major gas-producing basins, along with labor and equipment tightness that makes it difficult to grow U.S. natural gas production. Now, let's turn to slide number seven, titled Antero's Peer Leading Exposure to Premium Markets. This slide highlights Antero's unique ability to benefit from rising NYMEX prices and the premium hubs accessed by the Antero firm transportation portfolio. Antero owns 2.3 Bcf a day of firm transportation to the U.S. Gulf Coast LNG fairway into the Mid-Atlantic Cove Point LNG terminal, which represents approximately 75% of Antero's total natural gas production. Driven by the LNG export build-out in recent years, basis differentials at these premium hubs have improved dramatically. On the Tennessee Gas 500L, where Antero owns 570 MMcf a day of firm transport, the fourth quarter 2022 forecast implies the basis will improve by $0.24 to a $0.17 premium to NYMEX since the end of 2020. On the ANR Pipeline, where Antero ships 600 MMcf a day of southbound to the U.S. Gulf Coast, basis improved by $0.10 to a $0.07 premium to NYMEX. This increase in positive basis differentials directly led to the increase in our natural gas price realization guidance to a premium of NYMEX + 30-40 cents in 2022. Conversely, you can see the local negative pricing differential that many of our Appalachian peers sell their gas into has deteriorated by 41 cents to $1.10 below NYMEX. As additional LNG trains and terminals are completed, we expect that the pricing hubs where we sell the majority of our gas to see larger and larger basis premiums to 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 increases more dramatically than NYMEX as they are linked directly to international prices. This environment will provide further support to Antero's strategic position today accessing LNG markets. Next, let's turn to slide eight, titled Historically High Power Burn Demand. We continue to see very strong U.S. demand across industrials, power generation, and LNG exports. Looking specifically at power generation relative to the five-year average, demand is up more than 4 Bcf in the past three months. So far in July, demand is up 9% from a year ago and 11% from the five-year average. Low coal supplies leading to the inability for switching, combined with the summer heat, is expected to keep natural gas demand high despite rising natural gas prices. Recently, a 50 Bcf power burn was recorded on July 21st, 2022. This strong demand growth, combined with numerous supply constraints, supports our positive outlook for natural gas prices going forward. With that, I will turn it over to Mike. Thanks, Justin. This is Dave here. Paul and Justin already discussed our positive outlook for natural gas, so I'll keep my remarks brief this morning, but we'll be available for questions following our prepared remarks. Turning to slide number nine, titled Propane Market Fundamentals, highlights the supportive environment for propane prices today. Propane inventories are 4% below the year ago level and 13% below the five-year average. At the same time, we are beginning to see propane exports accelerate, driven primarily by China reopening its economy. In recent weeks, we have seen PDH plant utilization in China increase to nearly 80% from the low levels of the second quarter that averaged under 70%. As China reopens further, this utilization rate is expected to climb to the upper 80% range. This higher utilization rate, combined with an estimated 500,000 barrels per day of new PDH capacity coming online in China and over 100,000 barrels per day of new capacity in Europe and North America over the next 18 months, is expected to lead to a tightening propane market as we enter winter. With over 50% of our NGL volumes being exported, Antero is well positioned to benefit from increasing NGL demand. With that, I will turn it over to Mike. Thanks, Dave. Antero is in the strongest financial position in company history. During the second quarter, we generated over $650 million in free cash flow, which was used to reduce debt by nearly $400 million and to purchase $250 million in stock. I'll start on slide number 10, titled Strong and Sustainable Balance Sheet. During the quarter, we paid down our credit facility by $317 million, and we're able to repurchase $64 million of our higher cost 2026 and 2029 senior notes in the open market. During the second quarter of 2022, we also purchased 6.7 million shares at an average weighted price of $36.66 per share for $247 million. For the first six months of 2022, Antero purchased 11 million shares at a weighted average price of $32.44 per share for $358 million, a more than 15% discount to today's share price. With the credit facility being paid off in July, and based on our current commodity prices, we are targeting greater than 50% of free cash flow to be used for the share repurchase program in the second half of 2022. For the full year 2022, we now expect to be at or above the high end of our initial target of returning 25%-50% of annual free cash flow to our shareholders. When the initial $1 billion share repurchase plan is fully utilized, we will likely announce an additional buyback program by year-end. The next slide highlights our free cash flow targets. Antero's 2022 development plan is expected to generate over $2.5 billion of free cash flow. We are also expecting higher free cash flow in 2023 despite the backwardated strip prices as our hedges roll off. This brings our current five-year cumulative free cash flow target to over $10 billion. This substantial free cash flow will enable us to continue returning capital to our shareholders while also continuing to pay down debt. Slide number 12, titled five-Year Corporate Free Cash Flow Yield, highlights the attractiveness of repurchasing our shares at today's valuation. Over the past 18 months, we have cut our debt in half while our five-year corporate free cash flow yield increased from 38% to 80+%. The key takeaway here is that despite the stock price more than doubling since the fourth quarter of 2021 and debt being reduced by over $500 million. Our five-year free cash flow yield is higher today. Our stock is cheaper today than it was six months ago, and that is why we'll continue to focus on share buybacks as the primary method for returning capital to shareholders. Turning to slide number 13 and the continued emphasis on our ESG initiatives. We are proud to report that Rystad Energy recently re-released its annual ESG scorecard, and Antero was ranked number one for the environment. Antero was recognized for having industry-leading emissions performance and zero routine flaring. Our ranking also benefited from our 2025 net zero commitment and water management strategy. While we are happy that our team's efforts were recognized in this scorecard, we look forward to keeping this momentum going with the publication of our 2021 ESG report later this quarter. To summarize, on slide number 14, titled Antero Investment Highlights. Antero is well-positioned to execute in Shale 3.0. Antero has the strongest balance sheet in Appalachia, with $1.6 billion of debt and 0.6x leverage. We have significant scale as the fifth-largest natural gas producer and second-largest NGL producer in the U.S., providing product diversity at attractive prices and unmatched drilling inventory, including more than a decade of premium core liquids-rich locations. Our limited hedge position and industry-leading firm transport portfolio provide direct exposure to rising natural gas and liquids prices, driven by rising global demand. Lastly, with the lowest leverage and highest free cash flow yield of our peer group and a trading multiple well below 4x, we believe Antero is uniquely positioned to continue to deliver attractive multiple expansion and value to our shareholders. With that, I will now turn the call over to the operator for questions. Thank you. We will now be conducting a question-and-answer session. If you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star two if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. Our first question today comes from Arun Jayaram of JPMorgan. Please proceed with your question. Yeah, my first question is perhaps for Mike. Mike, you mentioned how you continue to see buybacks as a good use or an attractive use of free cash flow. I know you did, you know, paid down some debt in 2Q, but I guess our first question would be just the potential trajectory of buybacks in the second half. In our model, you know, we have about $1.6 billion of free cash flow in the second half. And given how you don't have a lot more debt to pay down, we're wondering if there's potential to completely exhaust the billion-dollar buyback and perhaps, you know, potentially reload, if the strip holds. Yeah, good question. We do plan to continue to pay down debt, Arun. You know, in the third quarter right now, we're targeting that $70 million that we had on the credit facility. Plus, as we've mentioned in the past, we are contemplating a $200-$300 million tender for the bonds outstanding. We don't have anything that's currently callable, but hopeful to get some in that way. Assuming we're at the midpoint of that, so call it $250 million plus the $70 million on the credit facility, we do plan on paying down approximately $320 million of debt in Q3. You look at our current free cash flow for that quarter based on today's prices, it's $700+ million. That would result in, you know, call it a high 300s of share buybacks just based on today's current commodity prices for the quarter. Heading into Q4, that would leave the majority for further share buybacks, although we probably would still try to repurchase some bonds in the open market. We are forecasting to exhaust that $1 billion authorization from the board sometime in Q4 and would most likely reload it then. Great. Thanks for that, color. I had a follow-up, and I wanted to go through the well productivity slide that you released. I wanna ask you about slide four. I wanted to see if you could maybe talk about what's driving that. Is the data lateral length adjusted? But just give us a sense of what's driving that. Is it completion design? Just wanna get more thoughts on that. I think it's, you know, we're going up the trend up into Tyler and Wetzel County more and more, and it represents a greater proportion of each of these years' plan, and it's getting higher BTU levels to 1,275-1,300 BTU. We're seeing higher BTUs on average per well, and we're actually seeing a big increase in gross wellhead gas from those wells when we were just assuming that would be similar gross wellhead gas. I believe it's similar completions, just better rock. Okay, great. Thanks a lot. Yeah. The next question is from Neal Dingmann of Truist. Please proceed with your question. Good morning, all. First question just on LNG. I'm just wondering specifically, Paul, for you or Mike, do y'all anticipate being able to complete or arrange further deals or contracts to boost, you know, what I think you already have a sizable existing contract to the Gulf. I'm just wondering, are you seeing anything? Is it too early to tell, or is that a focus on trying to add some more of those contracts down with the Gulf and contract some things down there? Hi, Neal. It's Paul here. Well, you know, we've been a leader in tying up firm transportation to quality areas, as you're aware, so both Cove Point on Mid-Atlantic and then LNG facilities down in the Gulf. There are other projects and expansions that are put out there. You know, we follow them. We may be interested depending on where it takes us and at what tariff, of course. So we keep our eye on it, but feel pretty good right now with the portfolio that we have, transportation portfolio taking us to quality markets. So very little of our gas is left behind in Appalachia. So we'll follow it, but remains to be seen whether we sign on for anything more. Yeah. Great. Then, Paul, just to follow up, I guess, on M&A specifically. When you and Mike look at and continue to talk about, you know, stress the buybacks, does that still look like a better value, cheaper value than. You know, it sounds like to me there's some deals out there even in Appalachian. Obviously, you guys have done some things. One, are there some things still available out there? If so, though, is buying your stock back still a better return in your opinion? Yeah. We like buying our stock back, and we like organic leasing and taking leases on other people's minerals or buying minerals ourselves. I think both of those are better bargains for us. Even though, yes, there is M&A out there, whether it's in other basins, and of course, we follow all that, whether it's Haynesville or other things that come up for sale. We really do plan to stay in our backyard. We know it so well and you know, really understand the land quite well. See more opportunity in organic leasing and just adding to our inventory or adding to our NRI on the wells that we do drill, and really don't plan on doing anything else in other basins for a long time. I was hoping to hear it. Thanks, guys. Great strategy. All right. Thank you. The next question is from Umang Choudhary of Goldman Sachs. Please proceed with your question. Hi. Good morning, and thank you for taking my questions. My first question was on the 2023 plans. Great to see the strong results. Any initial thoughts around spending and production growth for next year? Can you remind us when we should expect the overriding royalty to be reconvened back to the company? Yeah. No. Good point on the override. That's something definitely to look forward to in 2023. They stop participating wells anything after March 31st, 2023. Our NRI will increase by approximately 4% for wells after that. That's definitely something we're looking forward to. In 2023, it'll be a similar capital program to this year, and it'll be maintenance capital. It'll be flat to that second half of 2022 kind of production levels in that 3.3-3.4 range. Gotcha. Any initial color on the spending side? Like, given the inflation, what are we looking for on a D&C spend next year? Is it up 10% or is it similar status? Yeah. I think that remains to be seen. You know, that 7% that we raised for this year captures the completion contracts that we entered into that go through the end of 2023. There won't be any more inflation around that. There may be a little bit on the drilling rig side, and it's to be determined on the other components, but really dependent on commodity prices and diesel and fuel. Hopefully, if those are high next year, that'll obviously translate into substantial free cash flow for us. You know, to be determined yet, but probably up a little bit from 2022. Gotcha. That's helpful. Appreciate all the great macro color. I wanted your perspective on propane prices, which have come up a bit here. As we head into the propane winter heating season, do you see a setup which is very similar to last year, acknowledging that there might still be risk to demand here? Yes. Thanks for the question, Umang, and let me turn it over to Dave Cannelongo. You heard from him earlier in the call that he's our VP of Liquids Marketing. I'll throw it to you, Dave. Yeah, it's a great question. I think starting at looking at it from the supply side first, you know, we saw a lot of incremental LPG come on over the last year as OPEC was winding down its voluntary cuts. You know, that dynamic looks stable going forward. You know, there's been a fair amount of US LPG production growth this year. But you know, also, I would say a very moderate pace of that expected going forward and a tremendous amount of demand expectations coming. You know, we saw here in the second quarter, if you look at mobility and use daily flights in China as an indicator that, you know, the lockdowns that they went through here in the second quarter were nearly identical in terms of the number of flights, reductions on a daily basis as what we saw, you know, from the Wuhan lockdowns back in 2020. You know, they've not yet recovered to the levels that they were really in 2021, you know, leading into these latest measures that they've taken. We've got about 270,000 barrels a day of PDH capacity that's coming online here just in the second half of 2022. In China, about 170,000 on 2023. Projects in Canada, Poland, you know, Belgium, the US, all over the next year and a half. Things set up very well. The other piece I would remind everybody is last year we had a very mild winter here in the US. That remains to be seen as to what type of res comm demand we'll have this winter. Certainly the potential is there. I think the market's not paying as close attention to it this year as they did last year. I think there's a lot of distracting factors. They're paying more attention to gas here in the immediate term, which has certainly been rising strongly through the year. you know, we're optimistic that we're gonna see propane prices rally into the winter season. Got it. That's really helpful. Thank you. Thank you. The next question is from Subash Chandra of Benchmark Company. Please proceed with your question. Yeah, thanks. On the QL Capital drilling partnership, is there a change to that in the 2023 program, what we saw or what we will see with the override reverting? That QL is a separate transaction that will continue into 2023 and 2024. It ends at the end of 2024. It is an annual election, solely by Antero, whether they participate in the 15%-20% level. This year in 2022, we elected 15%. Obviously, where commodity prices are, that would tell you that we would elect for them to participate at the same level at 15% in 2023 and 2024. It ends after 2024. Okay, got it. I guess, you know, seeing the Utica update today, I presume that's a West Virginia, not a Point Pleasant, Utica. No. No, Subash. That is actually Ohio Utica. It's the Point Pleasant, but it's over in Noble County, so in, you know, south central of the Utica fairway. We still have inventory that is quality, and so this was an example of it. We've drilled a few pads over there in this last year and through the first half of 2022 with good results. We were just citing an example of one of our new pads where we focus more on the liquid side. Liquids with, you know, a substantial amount of gas with it. It's not to say that we're gonna shift a major part of our budget over to the Utica. We still have good inventory and good infrastructure over there, including processing and fractionation capacity. can go over there when we want to, but really 90%-95% of our budget will be directed towards Marcellus and the liquids-rich fairway, mostly in Tyler and Wetzel counties. Got it. You know, sort of seeing this liquids, you know, that you show in the slides. Can you just kinda remind us what your, I guess, liquids handling capacity is currently? How, you know, fully utilized or not it might be. I assume the Shell Cracker gives you wiggle room there too, but, you know, how dependent it is on the Shell Cracker? It's not dependent on the Shell Cracker. We have 2.8 Bcf a day of processing in the Marcellus, and it's relatively full. We have a little bit of capacity, but that processing's relatively full. Utica, we do have some capacity. Yeah, we have about 600 million a day. We're utilizing maybe half of it right now. 600 million a day of rich gas processing capacity. We do have the capability of open capacity there that we can go through. You know, the liquids, the Y-grade will flow up to Hopedale and get fractionated there. There's capacity there with MPLX. We have the ability to do it. Everything is a lot in line. We don't have MVCs on that idle capacity. It's paid for in kind of a basket case with Marcellus mixed in. We have open capacity there to do what we want there. Don't have to add any commitments, so it's just up to us as to when we wanna feather in a rich Utica pad or not as we go on. Got it. Thanks so much, guys. The next question is from Kevin MacCurdy of Pickering. Please proceed with your question. Hey, good morning, guys, and great free cash flow outlook for the back half of this year. My question is, given the delay of the Shell Cracker, are there any key milestones that are holding up that start? Yes, Dave. I maybe wanna clarify in our earnings release, it may have implied you know some kind of a delay, but really it was just an updating of our guidance. You know, when we first put that in place, they had announced to the market a second half 2022 start. I think we kinda. You will have seen in their earnings call slides this morning, they reported completion of construction on that cracker. It's really just in the commissioning phase and how long that takes and what volume they call on from each producer on any given day will vary until it reaches commercial operation. What we've seen with other facilities in the industry is that, you know, commissioning phase can take anywhere from a handful of months to, you know, worst case with some that have found equipment challenges or errors. You know, it's taken over a year. Right now, we don't expect anything like that with the Shell asset. Really just us updating kind of a stale forecast there around when we would start recovering significantly more ethane related to that. We have other ethane customers that we were ramping up volume with here in 2022 as well as in 2023 that all play a role in that forecast as well. Great. That's nice to hear. My next question is, under what conditions do you not max out the buyback authorization this year? It would just be dependent on commodities. You know, we're already at our debt goals, truly trying to be opportunistic around the debt as well. Around the free cash flow generation, it's really at $320 million of debt, and then the remainder is a real share buyback. It would just have to be commodity prices come off, or we have less than $1 billion of free cash flow in the second half of 2022. Thanks for taking my questions. Sure. Yeah, thanks, Kevin. The next question is from David Deckelbaum of Cowen. Please proceed with your question. Thanks for your time this morning, guys. Just have a few quick ones for you. Yes. Just one is, as you envision reloading a buyback program, should we always think about Antero communicating sort of a one-year targeted buyback? Or, is there sort of a specific time reference when you think about initiating an authorization? No, there's generally no time around it. You know, it's to be determined. You know, this one I think just happened to be one where we're able to complete it within a year. We really don't have a formula or methodology predetermined. We just look at the markets and whatever seems reasonable at the time is what we discuss with the board and get authorization for. Yep. Then just on some of the land and mineral acquisitions. When these scenarios happen, is it typically a reactive process, or is this proactivity on the part of AR to try to acquire minerals or, you know, wherever their core areas are? It's proactive. Yeah. You know, we do get some inbounds, but mostly it's us touching base with, you know. We go through courthouse records and figure out who owns what and who to approach and all of that spotted on our map. It's generated by Antero, by our land department. We all follow it pretty closely and decide what we wanna do and what's a good value and what's not. Yep. Then my last one is just on the propane macro. I think you referenced some of the PDH plants in China operating at 70% of capacity during the COVID-initiated lockdowns in the second quarter, and you've seen them rebound recently to 80%. Do you have a sense of what propane inventory levels were at these plants? Do you think that this is going to be kind of like a delayed response or due to working down inventory levels that might have been bloated? Or do you think that inventory levels were already kind of managed down in first and second quarters? Yeah, I'll take that one. I mean, it was a number of factors. You know, everything from port congestion and challenges on the downstream resin side. You know, how they were operating their refineries and the utilization rates of those around their export quotas. You know, we've seen them step back into the market in a pretty significant way here. Just in the last number of weeks, we've seen a utilization rate creep up. We've seen very little change to the PDH new build completion dates. I think one may have slipped two months was all. Not expecting a significant overhang that could delay that. I'd say 2021 was interesting just with, you know, we kind of entered the September with power rationing and things around the spike in LNG prices. We moved into, you know, Beijing Olympic related emissions controls and then, you know, expected to be ramping up from there right into what became the significant COVID lockdown. I would say it's been a kind of a tumultuous, you know, nine or 12 months in the world's largest, you know, propane market for the industry. Seeing the tailwinds there for us and others as we're coming out of these latest round of lockdowns. Yep. Thanks for the responses, guys. Yeah, thanks, Dave. The next question is from [Inaudible]. Please proceed with your question. Yeah, thanks for the time. I guess this kind of links back to propane. Our world is, you know, clearly starving for energy molecules. I'm wondering if you guys have had any incremental conversations with potential international buyers of your NGL stream, just for the sake of energy and thermal security? Thanks. conversations every day with buyers who wanna buy our LPG or ethane for domestic or even export use. I'd say to the marketing team, it looks kind of similar to what we've been seeing for quite some time now. The Mariner asset has really been a great program for us, and we've enjoyed strong demand out of that facility really the entire time we've been shipping on it. I would say nothing that I would report different from what's just been very consistent interest in our commodities. Yeah. I would add on to that, not only a desire on the NGL side, but on the natural gas side that Justin can attest to. We get calls all the time whether we can double up on our cargoes, whether we can spare more into many different international countries. There is an appetite, strong appetite out there. Yeah, that's correct. You know, talking to multiple buyers at various LNG facilities in the U.S. Gulf Coast that directly links with the Antero firm transportation portfolio. You know, the Calcasieu Pass facility from Venture Global, and then our Tennessee Gas 500L deliveries should also match up nicely with the Plaquemines LNG facility. As offtake increases at those second wave projects, continuing to have discussions with multiple potential international buyers. Got it. Good to hear. I mean, I guess my follow-up is kind of tied to that. It was good to see the bump in gas price realizations guide linked to, you know, the Gulf Coast demand. I was wondering if you had any thoughts to share conceptually as to how the market for the gas in the Gulf Coast could evolve as, you know, demand kind of becomes more and more weighted to the export centers there. Thanks. Sure. You know, as we mentioned in the earnings transcript, we've been witnessing basis appreciation in several locations, one being the 500L location. You know, it used to trade -6 versus NYMEX. We've seen it trade as high as +25, +$0.40 recently. We feel that we are starting to see that Gulf basis evolve into a premium market, and we just continue and you know to see basis improvement and physical gas demand across that Louisiana and Mississippi region for molecules. Our outlook is, you know, as we go into the winter, we could continue to see the basis rise at those Gulf locations as the international prices in Europe and Asia also climb. Great. Thanks, guys. Yep. Thanks, Neal Dingmann. We have a follow-up question from Subash Chandra of The Benchmark Company. Please proceed with your question. Yeah. Hi, Dave. A question first, RSG. Are you seeing it sort of a premium market, you know, develop there on your pipelines, you know, maybe Tennessee Gas? The second is, you know, on the LPG side, initiatives you might take for sort of better butane price capture? I'll take the first part. You know, we have yet to see the RSG pricing, but we are working on a couple initiatives internally. Stay tuned on that one. That could result in premium pricing. Then I'll turn over the butane question to Dave. Yeah. We're not looking ourselves at any type of, you know, butane upgrade projects like we've seen some other folks invest in the Gulf Coast. I would say the biggest thing we do on a routine basis is, you know, the butane that we produce gets fractionated into purity iso and purity normal. When you've seen the wide iso-butane spreads to normal this summer, we've enjoyed all of that. That's probably the main thing that we do for butane price enhancement. Also just around how we, you know, flex what we ship during the summer and winter on the Mariner East pipeline to try and optimize the value for both propane and butane, kind of the seasonality, the basis that we see seasonality with those two products to try and find the optimum, you know, recipe for what we send out that line. Okay. Thanks, guys. Very helpful. Thanks, Subash. There are no further questions at this time. I'd like to turn the floor back over to Brendan Krueger for closing comments. Yes. Thank you for joining us on today's conference call. Please reach out with any further questions. Thank you. This concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation.