Greetings and welcome to the Antero Resources Q3, 2020 Earnings Conference Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. As a reminder, this conference is being recorded. I would now like to turn the conference over to your host, Michael Kennedy, Senior Vice President of Finance.

Thank you for joining us for Antero's third quarter 2020 investor conference call. We'll spend a few minutes going through the financial and operational highlights and then we'll open it up for Q&A. I'd also like to direct you to the home page 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 first like to 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 and CEO; Glen Warren, President and CFO; and Dave Cannelongo, Vice President of Liquids Marketing & Transportation. I will now turn the call over to Paul.

Thank you, Mike. I'll open by commenting on the progress we've made on our asset sale program. As detailed on slide number 3 titled asset sale, refinancing and debt repurchase progress, we have closed $751 million of asset sale proceeds today. The proceeds we have received have enabled us to reduce debt by approximately $620 million since the asset sale program began in the fourth quarter of 2019. We continue to monitor the asset sale markets; any additional proceeds will be used for further debt reduction. Now let me update you on our cost savings momentum during the third quarter. Our well cost savings initiatives continue to drive our costs lower. Actual well costs during the third quarter averaged $640 per lateral foot, benefiting from long laterals that averaged 15,900 feet during the quarter. Normalized for a 12,000-foot lateral, well costs were $675 per foot, or 17% below the initial 2020 well cost target. Note that our well costs are all in and they include road, pads and facilities costs. We turned in line 27 Marcellus wells during the quarter, and these wells had an average lateral length of 11,900 feet. Fifteen of these wells have 60 days of production history and averaged 24 million cubic feet equivalent per day, helping to drive our strong production performance during the quarter. Now let's discuss a point regarding our firm transportation portfolio. Turning to slide 4 titled, Net Marketing Expense and Firm Transportation Commitments Declining. During the third quarter, we gave notice to release 300 million cubic feet a day of firm transportation capacity during 2021. Now let me clarify. What we're talking about here is releasing 300 million cubic feet a day of long-haul interstate transport, such as the big pipes to the Gulf, the Midwest and to the Appalachian m2 pool. We received a little feedback, some misunderstanding. Certain people thought that we were talking about Antero midstream capacity. That's not what we're talking about. We're talking about long-haul capacity. The reduced commitment is expected to lower our net marketing expense by $25 million next year, and $60 million in 2022. As shown in the chart on the left-hand side of the slide, our firm transportation commitments declined by 810 million cubic feet a day by year-end 2024. The chart on the right side highlights the approximate $100 million reduction in annual demand fees by 2024 resulting from the release of these 810 million cubic feet a day of firm commitments. To summarize, 2020 is our peak year for firm transportation expense as these commitments step down each year going forward. The result is a lower cost structure at Antero even in our sustained maintenance capital spending profile. Slide 5 titled Firm Transportation Provides Stability highlights the benefits of our firm transportation or FT portfolio. The red line in the chart represents the Appalachian basis differential, which has averaged $0.82 cents below NYMEX going back to 2014. Our premium firm transportation has delivered a $0.05 discount to NYMEX over that same timeframe. It's also worth noting that since gaining access to our entire FT portfolio in 2018, Antero has been able to realize a $0.06 premium to NYMEX to date. During the third quarter, this benefit was even more pronounced as Appalachian basis differentials widened. Given the limited excess takeaway capacity in Appalachia and maintenance downtime this fall, regional prices have recently traded at $1.50 below NYMEX. These weak prices have forced some producers who lack adequate takeaway capacity to shut in and curtail production which can lead to high volatility in cash flow and operational performance. Conversely, Antero's FT portfolio delivers reliable results, flow assurance, premium prices and the ability to readily hedge liquid NYMEX Henry hub prices. Now let's turn to slide 6, titled Appalachian Takeaway Capacity is a Strategic Advantage. This chart depicts the tightening takeaway capacity in the Appalachian basin, which has led to today's wide basis differentials. The solid red line is the historical production in Appalachia with the dotted red line showing the growth projection through 2023. The green line is the regional basis differential. As you can see, as capacity tightens, where there is white space on the chart, the regional basis widens, particularly during the summer and shoulder months. Even with the potential startup of new pipeline capacity such as MVP, the expected call on Appalachia supply is projected to lead to sustained, wide differentials in the basin. With what we refer to as right-sized premium, firm transport, Antero is the best positioned natural gas producer in Appalachia to take advantage of rising NYMEX natural gas prices without the risk of widening local basis or being forced to shut in production. When we talk about right-sized, we're considering both volume, tariffs and destination or delivery points dropping the unneeded or undesirable market destination, so it'll be quite strategic as we look to downsize our FT portfolio. In conclusion, I'm extremely proud of the job Antero's operating team has done with optimizing our drilling and completion operations and delivering significant cost reductions. These efforts not only lead to record low quarterly capital expenditures, but also to the quarterly production performance that exceeded expectations and delivered strong quarterly financial results. Through the first nine months of the year, we have turned in line 91% of our expected 105 completions in 2020. So we anticipate another decline in capital spending during our fourth quarter, resulting in annual drilling and completion capital expenditures of $750 million. Importantly, we expect to generate approximately $175 million to $200 million of free cash flow during the second half of 2020 based on today's strip prices. With that, I will turn it over to our Vice President of Liquids Marketing and Transportation, Dave Cannelongo for his comments.

Thanks, Paul. Let's turn to slide 7 and I'll begin by adding some color on the NGL and LPG macro environment. In the aftermath of the March OPEC plus price war and the COVID-19 pandemic, the resulting decline in rig and completion crew activity in oil-focused shale basins has set up expectations of a prolonged period of depressed US oil production. Thus far, that is what has materialized: a decline and flattening of oil production which has resulted in a decrease in associated NGL production from the oil-focused places. The chart on the left-hand side of the slide illustrates that US NGL supply forecasts have declined by 1.1 million barrels per day since the beginning of this year. We believe it may take three to four years for US NGL production to return to pre-COVID-19 levels. The chart on the right-hand side of the slide highlights the expected surplus of LPG export capacity along the Gulf Coast. Since the start of the shale revolution, we have enjoyed only a handful of periods when ample export capacity has been available. Looking forward, plentiful dock capacity will allow the US to fully access the international markets on a sustained basis, resulting in US Mont Belvieu prices closely linked to international markets. While Antero has enjoyed unrestricted access to these international markets through our Mariner's commitment for nearly two years now, this fundamental change on the US Gulf Coast will benefit Antero's share of NGL production that is sold domestically and linked to Mont Belvieu pricing. Turning to slide 8, titled NGL Price Recovery, we can see that the strength of NGL markets relative to WTI and Brent has continued to stay elevated as a result of resilient petrochemical and residential commercial markets during this pandemic. Here, we illustrate the outperformance of Mont Belvieu C3 plus pricing relative to WTI in 2020. On the right, we see the continued outperformance in propane relative to Brent at the Far East Index, or FEI, which is the benchmark in Asia. What we've witnessed is that demand for LPG in key Asian markets during the third quarter has actually increased year-over-year, and the strength of NGLs witnessed early in the pandemic was not temporary. Looking beyond the resilient residential and commercial demand, the relative preference of gasoline in the global transportation fuels market during this pandemic has also been favorable for NGL pricing on a relative basis to oil. Gasoline has been less affected than distillates, which has seen inventories increased significantly due to the more pronounced and prolonged decline in global jet fuel demand. Resulting weak distillate demand has led to reduced refinery runs in the US and globally, which in turn has lowered the production of refinery LPG and other gasoline blend components such as NAFTA. Ultimately, these downstream trends have been either supportive of blending Butane and C5 plus into the gasoline pool. In addition, the relatively tighter supply and demand dynamics for NAFTA has a knock-on effect for LPG, as there is some competition between NAFTA and LPG as a feedstock in select steam crackers in Europe and in Asia. Overall, we believe that global market dynamics are constructive for NGL prices at a minimum in the near to mid-term timeframe. Turning to slide 9 titled NGL Pricing Outlook. The chart illustrates the value that some third-party analytical teams, including the Citibank Commodities team shown here, continue to place on NGLs in 2021 and beyond, based on their bottoms-up global supply and demand models. Behind many of these forecasts is the realization that if oil were to stay range-bound throughout 2021 at $35 to $45 a barrel, the world will simply not be able to supply enough hydrocarbons in the subsequent years to meet demand in a post-pandemic environment, which undoubtedly will result in higher prices. Looking more closely at the Northeast takeaway capacity, slide number 10, titled Northeast LPG Supply and Demand highlights the reason for a tightening of the Northeast differentials to Mont Belvieu for LPG that has resulted from the Mariner East project. Realized Northeast differentials continue to improve year-over-year, with more and more volumes shipping out of the basin on the Mariner System, as Energy Transfer has added incremental capacity since initially placing Mariner 2 in service. With the Northeast LPG supply potentially at its peak here in 2020, we ultimately expect Northeast differentials to Mont Belvieu to strengthen even further in coming years. With that, I will turn it over to Glen.

Thank you, Dave. The bullish NGL price outlook is very encouraging for Antero due to our position as the second-largest NGL producer in the US, producing 146,000 barrels a day of C3 plus in the third quarter. At that production level, a $5 per barrel change or $0.12 per gallon in C3 plus pricing has a $225 million impact on our cash flow. So we have significant pricing leverage there. Continuing on the macro theme shown on slide 11, we are also encouraged by the natural gas outlook for the fourth quarter of 2020 and into next year following the dramatic decline in industry rig counts and completion spreads. 2020 natural gas production is forecast to exit approximately 6 Bcf a day lower than 2019 in the 86 to 87 Bcf a day range in the US. This reduced activity is expected to extend supply declines into 2021 with production 7 Bcf a day below the 2019 peak. On the demand side, we saw an impact from the global pandemic this past summer, but primarily through canceled LNG cargoes as US residential and commercial demand remained robust driven by above-average temperatures. Zero LNG cargo cancellations are forecast for this December, increasing US export volumes at year end to above pre-pandemic levels to over 10 Bcf a day from about 9 Bcf a day today. This demand recovery combined with a stubbornly flat to down supply forecast is expected to lead to an undersupplied gas market in 2021. Slide 12 at the top section of the page highlights a sharp 68% decline in horizontal rig counts in the oil-focused space such as the Permian, Eagle Ford, Bakken, SCOOP/Stack, and the DJ. On slide 13, you can see the 62% decline in total US completion spreads also in the oil-focused basins. This dramatic reduction in activity is expected to result in further declines in natural gas and NGL supplies as we exit 2020 and move into 2021. Note that 64% of US NGL supply comes from those shale oil basins compared to only 24% of natural gas. This indicates that the dramatic slowdown in activity in the oil-focused shale basins will have an even larger impact on NGL supply than it does on natural gas supply. These are some of the fundamentals behind the NGL slides that Dave has discussed. Slide 14 titled Liquidity Outlook illustrates our expected year-end 2020 liquidity of almost $1.4 billion circled in red. We continue to be proactive with debt repurchases during the third quarter, repurchasing $461 million of notional debt at a 13% weighted average discount, including our tender offer that closed in September. Since the start of our debt repurchase program in the fourth quarter of 2019, we have repurchased $1.3 billion of notional debt at a 17% weighted average discount, thereby reducing total debt by $220 million from the discount alone while reducing annual interest expense by $34 million. The remaining market value of the 2021 and 2022 senior notes net of what has been repurchased today is shown on the right-hand side of the slide and totals $915 million in market value. Antero had almost $1.1 billion of liquidity as of September 30, which is shown on the dark green bar on the left-hand side of the page. During the third quarter, we generated $272 million of EBITDAX and free cash flow of $88 million before working capital investments. The EBITDAX and free cash flow numbers exclude the $29 million hedge monetization, which we treated as an asset sale. We continue to expect to generate $175 million to $200 million of free cash flow in total during the second half of 2020 based on today's strip prices, providing additional liquidity to reduce debt. Including the override and royalty contingent payment of $51 million, which we will receive in the fourth quarter before hitting volume thresholds in the third quarter of this year, we will have $1.4 billion in liquidity at year-end 2020, more than sufficient to handle both the 2021 and 2022 maturities, which once again have a total market value of $915 million today. Finally, total debt has been reduced to under $3.2 billion. We expect that to go down to $3 billion by year-end, due to free cash flow, and debt to LTM EBITDAX was 3.2 times at quarter-end. Next, I'd like to highlight our annual corporate sustainability report that was published in October. The report highlights our outstanding environmental, social, and governance, or ESG performance, as shown in slide number 15. Since our inception, Antero has been committed to safety and environmental excellence. We have a safety record that rivals the majors, and we have one of the lowest greenhouse gas intensity metrics in the industry. Our methane leak loss rate of 0.46% in 2019 was significantly below the one future industry and sector targets of 1% and 0.28% respectively. Looking forward, we believe natural gas will be key to the energy transition in the coming decades as a complement to renewable energy. As one of the largest natural gas producers in the US, we're well-positioned to maintain our peer-leading ESG position and be a gas supplier of choice. Accordingly, we set 2025 environmental targets that include a 50% reduction in our already low methane leak loss rate, a 10% reduction in GHG intensity alignment with TCFD and SASB reporting guidelines, and endeavoring to achieve net-zero carbon emissions through operational improvements and carbon offsets. In conclusion, the Antero team has delivered exceptional execution over the last 12 months. Slide number 16 titled, Tremendous Execution Through the Downturn, highlights the progress we have made this year. Despite a challenging backdrop, we have executed our asset sale and refinancing plan raising over $1 billion, reduced total debt by $620 million, addressed our 2021 and 2022 maturities, lowered well costs by 17%, which supports a low maintenance capital budget of just $580 million for 2021. We have transitioned to a free cash flow model and bolstered our peer-leading focus on ESG. These achievements during truly historic challenges are a testament to the dedication of Antero's employees. And finally, it’s nice to have some tailwinds with the 2021 natural gas true-up, which is up 25%, and C3 plus NGL is up to 67% since the April trough. With that, I will now turn the call over to the operator for Q&A.

Our first question today comes from Neal Dingmann of Truist Securities.

Good morning, all. First, Paul or Glen, my question is just on debt repayment, which I'll consider further VPTs or further asset sales or would you even go as far as to consider giving your massive acreage your drilling partnerships rather strategies to maintain the lower spending and or even pay down debt further?

Yes, Neal, we certainly consider all those; they are also on the table. I think we can be more choosy now. The commodity price has moved both natural gas and NGL, as we forecast, we're pretty happy about that. So then we generate quite a bit more free cash flow and we can work our way down in that fashion. So we'll be very choosy. And we may or may not do further asset sales, depending on how commodity prices play out and how the markets behave. So uncertain at this point, but we certainly keep an eye on all those situations that you mentioned.

Okay, and just one follow-up, given just wondering given the large amount of hedges, you'll have some nice hedges. If I'm just wondering, would you all consider ramping activity next year if gas prices remained strong like this in order to take advantage of these higher prices? Or would that - would the higher prices change your growth strategy next year at all? Thank you.

Neal, we're completely focused on generating free cash flow. So, I would expect us to announce, this has not been board-approved yet, but maintenance-level capital for next year and maximize free cash flow to reduce that leverage. Our plan over the longer term is to reduce our debt by at least another million dollars and get it down to under $2 billion total debt and leverage, appropriately down under two times.

The next question is from David Deckelbaum of Cowen.

Good morning, Paul, Glen, and Mike team. Thanks for taking my questions. Just curious, maybe just to follow up on the Neil's question there around the growth strategy, you articulated that obviously with the successful re-determination on the borrowing base, you have enough liquidity to cover absent any other asset sales to retire 2021 and 2022 maturities? I guess as we think about maximizing free cash is this strip has obviously moved up considerably, even above where the hedge book is, do we think about just long-term reactivating growth and getting back to maybe parity or growing into that firm transport portfolio in this $3-ish world if we're beyond this $1 billion of debt pay down?

Well, fortunately, as we pointed out, David, the firm transport portfolio grows down to meet us, should we say, is maintenance capital, so it does shrink to well under $100 million of carry on that, which is a real benefit over the next few years. So we don't feel compelled to reach up to do that. But there may be other ways to fill that firm transport over time. So we're just showing you the numbers without any third-party gas purchases and there are various other ways to do that, like our firm transport, etc. So rather than reacting with the drill bit, like we've done in the past, I would say we are working via the transport portfolio, and working that down.

Got it. So I guess expand on that a bit, the firm transport you're giving notice, I guess, to release some of the capacity going down to the Gulf Coast. You talked about how that impacts and helps you on the net marketing side. What do you think the impact is, I guess, in 2021, in terms of where the strip is now to your dips on the gas side and resulting transport expense?

Yes, there really would be no impact in terms of, we're optimizing here and releasing pieces that are not the most optimal pieces of transport. So we don't see any negative impact on our net backs. So no concern over that. The net marketing expense would be impacted, but not the underlying transport expense. So it's that $0.11 cents per Mcfe that we had in the third quarter that gets impacted over time.

Right. So I guess for what you're going to be selling of your operated gas or produced gas. You're just - you're keeping the same sort of pro rata exposure.

That's right. Yes. It's a big book, and it's big scale. And back to the earlier question, we don't have a real need to grow volumes, right with being the third-largest gas producer, second-largest NGL producer. We're not strongly compelled by that today. It's really more about extracting the most cash flow we can from the business and repaying debt.

And if I could just add one quick on here; this next year, I know that there is an assumption of the shale cracker startup at some point around mid-year and obviously that's a decent uplift to your ethane volumes. What are you seeing today? It looks like the cracker is almost near completion; the pipeline there is effectively complete. When do you think you're going to start seeing first volumes kind of extracted there?

Yes, good question, David. Shale, I think recently put out some information that they were about 70% complete on the facility here probably in the last month or two. So a lot of progress made, but still ways to go. If you look back at their second quarter earnings slides, they had in the appendix kind of a reference to that project now being 2022 plus in that bucket of projects that they had, so we're not expecting it at all next year. Certainly, 2022 is a possibility, but still ways to go on the project there for them during a challenging construction environment. But for us, it's a significant ramp-up in our ethane volumes. And we're excited about the project and what it means for the region, but the overall impact on Antero is not tremendously material.

The next question is from Subash Chandra of Guggenheim Partners.

Hey, guys. Thank you. So I guess the value of FT improving, do you see opportunities or demand for some of that excess FT that might have us take down on net marketing expense next year?

Hi, Subash. Yes, there's definitely demand, there's distress gas in the m2 pool in Appalachia. And so every day we're buying pretty large volumes of third-party gas and moving it into our pipe and collecting the spread to places like Chicago and the Gulf. And so that helps to reduce our net marketing expense by buying and selling the premium third-party gas to distressed third-party gas in the m2 pool. The way things are shaping up; we see that those wide basis differentials continuing through 2021. And so the opportunity is there for us. And we are seeing that basis blowout. So I think we'll continue to see that in terms of releasing FT. It can become; it's not as straightforward as just buying the third-party gas and putting it into the pipe. We have our feelers out, we sometimes release some of our FTP seasonally, for example, releasing for five months during the winter and collecting much of the demand charge to offset our unutilized FT and reduce that net marketing expense. So other ways to do it and we do it here and there in many of our pipes, but the most straightforward way is buying the third-party gas.

Got it. Okay. And then on well cost, I guess we've been talking quite a bit about profit and so on. When do you think you get comfortable with either going with regional sand or not? And to just give a sense, maybe, in terms of magnitude, what that could do to well costs if you were to adopt that on a wide-scale basis?

Yes. So to make the distinction, we've moved away from the so-called northern white from Wisconsin, etc. Much of our sand is the equivalent, the geologic equivalent of the northern white, but it's from Missouri. And so we use mostly that from different sand suppliers, which barge right up to transload next door to our acreage. So that saved quite a bit of money. We continue to work things down and work our cost structure down. What can it mean in well costs? Time will tell; could it save $100,000; could it save $200,000 or more as prices get lower with the competition? So that would be $20, $30 per foot that we can still reduce beyond where we are now.

Okay, terrific, and if I could just ask this because you have your NGL expert on the call. Just curious when I'm looking at global LPG prices have come in a little bit here recently. How do you bracket sort of sensitivity to second wave COVID, etc.? And how much lower do you think prices could go on from an export basis?

That's a great question. It's a bit of a two-pronged answer here. I mean, the first piece is if there is a second pronounced wave, similar to what we saw back in the spring, the most immediate response would be a reduction in refinery runs, just a lack of transportation fuel demand. And so we're seeing refineries here in the US still running in the low 70% utilization rate, and globally similar pressure. If that goes lower that could create a situation where LPG supply is reduced during a time of year where residential/commercial demand really isn't expected to be all that affected by a second wave. In fact, you're starting to see expectations here in the US with more and more folks working at home that you could actually have roughly a 5% increase in residential/commercial demand for propane for home heat. So you'll see that around the world. And that's the potential upside to it. But it also does - you'll see propane and butane trade relative to oils. And we saw back in the start of the pandemic propane trading at 140% of oil, that's not a level that can be sustained probably for any great period of time, but it just highlights how the pricing can decouple. So it's tough to say what will happen in the second wave. If we think relative to the heavier hydrocarbons, NGLs will perform significantly better. But ultimately, none of us want to see the demand destruction that comes from a second wave across the board for all the commodities.

The next question is from Harry Halbach of Raymond James.

Hi, guys, you were around the 70% gas mix for 2019. It's kind of come down every quarter to around 65% this quarter. I was just curious where do you see that going moving forward, is that mainly just a consequence of where you're drilling or some sort of call on commodity prices going forward?

It's where we're drilling. But it is a bit of a call on commodity prices, we feel really good about NGL prices, as we've mentioned earlier, and natural gas too. So for us, the best economics in that kind of bullish scenario is the dollar liquid-rich acreage. And I think, if we stay on that course over the next few years, we do mix in some dry gas drilling here and there, but if we stay on that course, I think the percent gas could drop to as low as 60%. But that's probably the outside.

All right, thank you for that. And then, I was also just kind of wondering, obviously, consolidation has hit the energy space, and most of it that is focused on the Permian, but there have been a few deals with EQT, and even Southwest in Appalachia. I was just wondering, do you see any value for Antero pursuing M&A at this time?

We certainly keep our eyes on it all the time. It's been good to see; I think it is productive for the industry and has been productive for a long time. I do think we'll see more in Appalachia. So it's something that we monitor; whether we will participate, I don't know at this point. But it is very interesting, the development.

The next question is from Gregg Brody of Bank of America.

Good morning, guys. Interested, just I'm trying to reconcile production cadence for this year and just taking into account the VPP. Is 2020 production number that we're supposed to stay fine on is that 3.45 versus 3.5 Bcf per day?

It is 3.45. That's net of the VPP. The VPP is treated as a divestiture so it's not included in the volume. So you take the 3.5 original and subtract the 50 million a day from the VPP.

And as we think about this - the fourth quarter, was the third quarter greater because you processed more ethane or is it that we should expect the fourth quarter to decline to meet that number?

No. It had nothing to do with that. The third quarter was better just because of well results and the development plan exceeding expectations. I've got this question on the guidance. We don't adjust our guidance for 1% or 2% increase; that's kind of rounding when you deal with these kinds of large numbers. That can kind of result especially when there's only one quarter left with unreasonable thoughts around product in the fourth quarter, but rounding alone can mean 100 to 200 million a day for a fourth quarter when you're talking about 3.5 Bcf per day. So we just don't adjust our guidance 1% or 2%, it's not material.

Got it. We should be thinking about keeping production flat next year at 3.45.

This is correct.

Got it. Congrats on the bar base determination. That's great. Once you have success, it's - you have a moment and then you ask, well, what's next? So I'm going to ask. Just curious how you're thinking about the next re-determination? If what's sort of the temporary hedges rolling off, do you expect it to be the same?

Well, it's one day old. But commodity prices are higher than where we actually started this re-determination. So I would actually expect those prices to go higher in the spring. So I would expect our borrowing base to be higher as well; our borrowing base actually calculated well in excess of $2.85 billion. It's just you don't in today's markets; you don't really ask for an increase, but our borrowing base is well ahead of the $2.85 billion, so I don't see any issues there.

Got it. And then you touched on the asset monetization possibility. I'm curious how do you think about additional converts or common equity markets for de-leveraging?

Yes, as I said earlier, Gregg, I didn't say we want to be patient. But we've been patient. And that's really paid big dividends to be that way, and not to rush to exit this or that. And so I think we'll continue to look at the asset markets. And if we see real good value, we'll do something. But otherwise, we really do feel like the winds that are back of it here with commodity prices moving as they are; it's a volatile time. Will we see some downturn because of the second wave, third wave, whatever we could? But right now, it's looking pretty good. And we're just enjoying those tailwinds, and we'll be paying down debt over time. So don't see any dramatic moves. But you never know if we see some real value somewhere, then we'll take advantage of that.

Great. And last question for you. So you gave some great color on the NGL market, just trying to think about how to fix about ethane realizations going forward and maybe some goalposts as to how you think about it.

Most of the ethane in the basin is going to be consumed within a region. And there are really, I'd say, there are four existing petrochemical users: two open in Ontario, one down in Calvert City, Kentucky, and then obviously the shale project, that's what we talked about earlier. Most of those transactions, I think you're going to see producers based on a gas-based index. So they're going to be some kind of uplift relative to natural gas economics for the producers in the region. There's going to continue to be really through the end of this decade; the ATEX pipeline that flows down Mont Bellevieu. And so that's without a doubt, it's going to be Mont Belvieu linked, and there will be, I would say, an increasing percentage of gas-linked portfolio deals for the basin and for producers like Antero as some of these expansions and new projects come online for local and regional consumption. And then ATEX exposure is kind of a baseline that is probably not linked.

There are no additional questions. At this time, I would like to turn the call back to Michael Kennedy for closing remarks.

I want to thank everyone for participating in our conference call today. If there are any further questions, please feel free to reach out to us. Thanks again. Have a good day.

This concludes today's conference. You may disconnect your lines at this time. Thank you for your participation.