Antero Resources Corporation

Greetings and welcome to Intero 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. 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. 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 Intero'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 would also like to direct you to the homepage of our website at www.interoresources.com, where we've 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, Intero management will make forward-looking statements. Such statements are based on our current judgments regarding factors that will impact the future performance of Intero and are subject to a number of risks and uncertainties, many of which are beyond Intero'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, Glenn Warren, President and CFO, and Dave Conolongo, Vice President of Liquids Marketing and 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 three, titled Asset Sale, Refinancing, and Debt Repurchase Progress, we have closed $751 million of asset sale proceeds to date. 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, pad, 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 out regarding our firm transportation portfolio. Turning to slide number four, titled, net marketing expense, and FT commitments declining. During the third quarter, we gave notice to release 300 million a day, 300 million cubic feet a day, of firm transportation capacity during 2021. Now let me just make a clarification. What we're talking about here is releasing 300 million 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 bit of feedback, a little misunderstanding. Certain people thought that we were talking about Antero midstream capacity. That's not what we're talking about. We're talking about the long-haul capacity. To reduce commitment, it 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 decline by 810 million cubic feet a day by year end 24. The chart on the right side highlights the approximate $100 million reduction in annual demand fees by 2024, resulting from from the release of this 810 million cubic feet a day of firm commitments. To summarize this point, 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 spend profile. Slide number five, titled Firm transportation provides stability. This highlights the benefits of our firm transportation or FT portfolio. The red line in the chart represents the Appalachian basis differential, which has averaged 82 cents below NYMEX going back to 2014. Our premium firm transportation has delivered a 5-cent discount to NYMEX over that same time frame. It's also worth noting that since gaining access to our entire FT portfolio in 2018, Antero has been able to realize a 6-cent premium to NYMEX to date. During the third quarter, this benefit was even more pronounced as Appalachian basis differentials blew out. 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 number six, titled Appalachian Takeaway Capacity is a Strategic Advantage. This chart depicts the tightening takeaway capacity in the Appalachian Basin in the vicinity of the yellow arrow on the chart, 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 blows out, particularly during the summer and shoulder months. Even with the potential startup of new pipeline capacities 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 led 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 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 Canalongo for his comments.

Thanks, Paul. Let's turn to slide number seven and begin by adding some color on the NGL and LPG macro environment. In the aftermath of the March OPEC Plus price war and 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 U.S. oil production. Thus far, that is what has materialized, a decline in flattening of oil production, which has resulted in a decrease in associated NGL production from the oil focus plays. The chart on the left-hand side of the slide illustrates that U.S. 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 U.S. Mont Bellevue prices closely linked to international markets. While Antero has enjoyed unrestricted access to these international markets through our marineries commitment for nearly two years now, this fundamental change on the U.S. Gulf Coast will benefit Antero's share of NGL production that is sold domestically and linked to Mont Bellevue pricing. Turning to slide number eight, titled NGL Price Recovery, we can see that the strength of NGL markets relative to WTI in 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 Montbellevue 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 that 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 effective than distillates, which has seen inventories increase 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 U.S. and globally, which in turn has lowered the production of refinery LPG and other gasoline blend components, such as naphtha. Ultimately, these downstream trends have been even further supportive of blending butanes and C5 plus into the gasoline pool. In addition, the relative 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 number nine, 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 was 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 Montbellevue for LPG that has resulted from the Mariner East project. Realized Northeast differentials continue to improve year over year with more and more volume shipping out of the basin on the Mariner East system as energy transfer has added incremental capacity since initially placing Mariner East 2 in service. With the Northeast LPG supply potentially at its peak here in 2020, we ultimately expect Northeast differentials to Mount Bellevue to strengthen even further in coming years. With that, I will turn it over to Glenn.

Thank you, Dave. A bullish NGL price outlook is very encouraging for Antero due to our position as the second largest NGL producer in the U.S., producing 146,000 barrels a day of C3 plus in the third quarter. At that production level, a $5 per barrel change, or 12 cents 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 six BCF a day lower than 2019 in the 86 to 87 BCF a day range in the U.S. This reduced activity is expected to extend supply declines into 2021 with production seven 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 U.S. residential and commercial demand remained robust, driven by above average temperatures. zero LNG cargo cancellations or forecasts for this December, increasing U.S. 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 number 12. The top section of the page highlights the sharp 68% decline in horizontal rig counts in the oil-focused basins. That's the Permian, Eagleford, Bakken, Scoopstack, and the DJ. On slide number 13, you can see the 62% decline in total U.S. completion spreads, also in the oil-focused basins. This dramatic reduction in activity is expected to result in further declines in natural gas and in GL supplies. as we exit 2020 and move into 2021. Note that 64% of U.S. 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 number 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 this slide. and totals $915 million in market value. AR had almost $1.1 billion of liquidity as of September 30th, 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 to $200 million of free cash flow in total during the second half of 2020, based on today's stroke 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, for hitting volume thresholds in the third quarter 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 billion 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 the free cash flow. And debt to LTM EVA DAX 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, which is 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 have one of the lowest greenhouse gas intensity metrics in the industry. Our methane leak loss rate of 0.046% 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 U.S., we are 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, transitioned to a free cash flow model, and bolstered our peer-leading focus on ESG. These achievements during truly historic challenges is a true testament to the dedication of Ontario's employees. And finally, it's nice to have some tailwinds with the 2021 natural gas trip up 25% and C3 plus NGLs up 67% since the April trough. With that, I will now turn the call over to the operator for Q&A.

Thank you. At this time, we'll be conducting a question and answer session. If you would like to ask a question, please press star 1 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 Neil Dingham of Truist Securities. Please proceed with your question.

Morning, Paul. My question is just on debt repayment. Would you all consider further VPPs or further asset sales, or would you even go as far as to consider giving your massive acreage, your drilling partnerships, or other strategies to maintain the lower spending or even pay down debt further?

Yeah, Neil, we certainly would consider all those. They're all still on the table. I think we can be more choosy now. The commodity price has moved, both natural gas and NGLs, as we forecast, so 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, kind of depending on how commodity prices play out and how the markets behave. So uncertain at this point, but we certainly keep our eye on all those situations that you mentioned.

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

You know, I mean, we're completely focused on generating free cash flow. So, you know, 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 billion dollars and get it down under $2 billion total debt and leverage appropriately down under two times.

Yeah, that makes sense. Thank you.

Thank you. Thank you.

The next question is from David Deckelbaum of Cohen. Please proceed with your question.

Morning, Paul, Glenn, Mike, team. Thanks for taking my questions. Just curious, maybe just to follow up on Neil's question there around the growth strategy, you articulated that obviously with the successful redetermination on the borrowing base, you have enough liquidity cover absent any other asset sales to retire 21 and 22 maturities. I guess as we think about maximizing free cash, is this This trip 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 paydown?

Well, you know, fortunately, as we pointed out, David, the firm transport portfolio grows down to meet us if we stay at maintenance capital. So, you know, 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 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, late and off-firm transport, et cetera. So rather than reacting with the drill bit like we've done in the past, I would say it would be more working the transport portfolio and working that down.

Got it. Just to, 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's the impact, I guess, in 21 in terms of where the strip is now to your dips on the gas side and resulting transport expense?

Yeah, there really would be no impact in terms of, you know, we're optimizing here and releasing pieces that, you know, are not the most optimal pieces of transport. So we don't see any negative impact on our netbacks. So no concern over that. The net marketing expense would be impacted, but not the underlying, you know, transport expense. So it's that $0.11 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 keeping the same sort of pro rata exposure.

That's right. Yeah. Okay. You know, it's a big book. It's big scale. And, you know, back to the earlier question, you know, we don't have a real need to grow volumes, right, with, you know, being the third largest gas producer, second largest NGO 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.

If I could just add one quick one here. Next year, I know that there is an assumption of the shellcrackers start up at some point around mid-year. 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?

Yeah, that's a good question, David. You know, Shell, 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, So a lot of progress made, but still a 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 in the realm of possibility, but still a 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.

Thank you, guys.

Thank you.

The next question is from Subhas Chandra of Guggenheim Partners. Please proceed with your question.

There you go. 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 our net marketing expense next year?

Hi, Subhash. Yeah, there's definitely demand. There's distressed gas in the M2 pool in Appalachia, and so every day we're buying – pretty large volume of third-party gas and moving it through 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 at a premium the third-party gas, the distressed third-party gas in the M2 pool. The way things are shaping up, we see those wide basis differentials continuing through Cal 21. And so the opportunity is there for us and, uh, we are seeing that basis blow out. So, uh, yeah, I think we'll continue to see that in terms of releasing FT, it can become, uh, it's not as straightforward as just buying the third party gas and putting into the pipe. We, we have our feelers out. We sometimes release some of our FT seasonally, for example, uh, releasing for five months during the winter and collecting much of the demand charge to offset our unutilized FT and reducing 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 costs, I guess, you know, 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 could you just give a sense maybe of, in terms of magnitude, what that could do to well costs if you were to adopt that on a wide scale basis?

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. We use mostly that from the different sand suppliers. It's barged right up to a transload next to our acreage. That's saved quite a bit of money. We continue to work things down and work our cost structure down. What can it mean in well cost? Well, 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 could still reduce beyond where we are now.

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

Yeah, it's a great question. You know, 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, you know, the most immediate response is a reduction in refinery runs, you know, just a lack of transportation fuel demand. And so, you know, we're seeing refineries here in the U.S. still running in the low 70% utilization rate. and globally similar pressure. And so if that goes lower, that actually could create a situation where LPG supply is reduced during a time of the year where ResCom 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 U.S. with more folks working at home that you could actually have a roughly 5% increase in ResCom demand for propane for home heat. So you'll see that around the world, and that's That's the potential upside to it. But, you know, it also does, you know, you'll see propane and butane trade relative to oil. And, you know, we saw back in the start of the pandemic, propane trading at 140% of oil. You know, that's not a level that can be sustained probably for any, you know, great period of time. But it just kind of highlights how the pricing can decouple. So, you know, tough to say what will happen in the second wave. You know, we think relative to, to heavier hydrocarbons, NGLs, will perform significantly better. But, you know, ultimately, none of us want to see the demand disruption that does come from a second wave across the board for all the commodities.

Thank you.

Thanks, Sebastian.

The next question is from Harry Halbach of Raymond James. Please proceed with your question.

Hi, guys. Y'all were around the 70% gas mix for 2019, and it's kind of come down every quarter to around 65% this quarter. I was just curious, where do y'all see that going moving forward? Is that mainly just a consequence of where you're drilling, or is it 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 mentioned earlier, and natural gas, too. So For us, the best economics in that kind of bullish, bullish scenario is to drill our liquids-rich acreage. And I think if we stay on that course over the next few years, and 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 that is focused on the Permian, but there have been a few deals, you know, with EQT and even Southwestern and Appalachian. I was just wondering, do you all see any value for Intero pursuing E&A at this time?

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

All right. Thank you for that. That's a great quarter, guys. Thank you. Thank you.

The next question is from Greg Brody of Bank of America. Please proceed with your question. Good morning, guys.

Hey, Greg.

Hi, Greg. Just trying to reconcile production guidance for this year and just taking into account the VPP and the and the Martica transaction. Is your 2020 production number that you're supposed to take flight on, is that 3.45 or is it 3.5 BCL per day?

It's 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 the fourth quarter, Was 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 ethane. The third quarter was better just because of well results and the development plan exceeding expectations. I have got this question on the guidance. We don't adjust our guidance for a 1% or 2% increase, or that's kind of rounding when you deal with these kind of large numbers. That can kind of result, especially when there's only one quarter left, with unreasonable thoughts around production in the fourth quarter. But just the rounding alone, you know, can mean $1 million to $200 million a day for a fourth quarter when you're talking about 3.5 BCFE a day. So we just don't adjust our guidance 1% or 2%. It's not material.

Got it. But we should be thinking about keeping production flat next year at 3.45 BCFE. That's correct. Got it. Congrats on the borrowing-based redetermination. It looks great. You know, once you have a success, 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 redetermination. If what's sort of what's on your head is rolling off, or do you expect it to be the same?

Well, it's one day old, so... But... You know, the commodity prices are higher than where we actually started this redetermination, so I would actually expect those price decks 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 bank markets, you don't really ask for an increase, but our borrowing base is well ahead of the $2.85, so I don't see any issues there.

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

Yeah, I think, as I said earlier, Greg, you know, I didn't say we want to be patient, but, you know, we've been patient, and that's really paid, you know, big dividends to be that way and not 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 at our back a bit 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 with that. 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 have some great color on the NGL market. Just trying to think about how to think about ethane realizations going forward and maybe some goalposts as to how you think about it.

Yeah, you know, most of the ethane in the basin that's going to be consumed within region, and there's really, you know, I'd say there's four existing petrochemical users, two up in Ontario, one down in Calvert City, Kentucky, and then, you know, obviously the Shell project that we talked about earlier. You know, most of those transactions, I think you're going to see producers basing those deals 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 to Montbelview. And so that, without a doubt, is going to be Montbelview-linked. And so there will be, you know, 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, you know, local and regional consumption. And then the ATEX exposure is kind of a baseload that's Montbelview-linked.

Got it. Thank you very much.

Thanks, Greg.

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.