Greetings, and welcome to 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 Q3 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 and 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'd 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 and CEO Glenn Warren, President and CFO and Dave Conalango, 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 3 titled Asset Sale, Refinancing and Debt Repurchase Progress, we have closed $751,000,000 of asset sale proceeds to date. The proceeds we have received have enabled us to reduce debt by approximately $620,000,000 since the asset sale program began in the Q4 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 Q3. Our well cost savings initiatives continue to drive our costs lower. Actual well costs during the Q3 averaged $6.40 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 $6.75 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. 15 of these wells have 60 days of production history and averaged 24,000,000 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 4, titled Net Marketing Expense and Feet Commitments Declining.
During the Q3, we gave notice to release 300,000,000 a day 300,000,000 cubic feet a day of firm transportation capacity during 2021. Now let me just make a clarification. What we're talking about here here is releasing $300,000,000 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 of little misunderstanding. Certain people thought that we are talking about Antero Midstream capacity.
That's not what we're talking about. We're talking about the long haul capacity. The reduced commitment is expected to lower our net marketing expense by $25,000,000 next year and $60,000,000 in 2022. As shown in the chart on the left hand side of the slide, our firm transportation commitments declined by 810,000,000 cubic feet a day by year end 'twenty four. The chart on the right side highlights the approximate $100,000,000 reduction in annual demand fees by 2024 resulting from the release of this 810,000,000 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 5, titled Firm Transportation provides stability. This highlights the benefits of our firm transportation or Feet portfolio. The red line in the chart represents the Appalachian basis differential, which has averaged $0.82 below NYMEX going back to 2014.
Our premium firm transportation has delivered a $0.05 discount to NYMEX over that same time frame. It's also worth noting that since gaining access to our entire Feet portfolio in 2018, Antero has been able to realize a $0.06 premium to NYMEX to date. During the Q3, 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 Feet portfolio delivers reliable results, flow assurance, premium prices and the ability to readily hedge, leverage and 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 start up 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 talked about rightsized, we're considering both volume, tariffs and destination or delivery points, dropping the unneeded or undesirable market 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 1st 9 months of the year, we have turned in line 90 expected 105 completions in 2020, so we anticipate another decline in capital spending during our Q4, resulting in annual drilling and completion capital expenditures of $750,000,000 Importantly, we expect to generate approximately $175,000,000 to $200,000,000 of free cash flow during the second half of twenty twenty 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 begin by adding some color on the NGL and LPG macro environment. In the aftermath of the March OPEC plus price war and COVID-nineteen 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 1,100,000 barrels per day since the beginning of this year. We believe it may take 3 to 4 years for U.
S. NGL production to return to pre COVID-nineteen 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 U.
S. To fully access the international markets on a sustained basis, resulting in U. S. Mont Belvieu prices closely linked to international markets. While Antero has enjoyed unrestricted access to these international markets through our Mariner East commitment for nearly 2 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 Belvieu pricing. Turning to Slide number 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 Q3 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 naphtha has a knock on effect for LPG as there is some competition between naphtha 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 midterm timeframe.
Turning to Slide number 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 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 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 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 Mont Belvieu 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 2nd largest NGL producer in the U. S, producing 146,000 barrels a day of C3 plus in the 3rd quarter. At that production level, a $5 per barrel change or $0.12 per gallon in C3 plus pricing has a $225,000,000 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 Q4 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 Bcf to 87 Bcf a day range in the U. S. 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 U.
S. Residential and commercial demand remained robust driven by above average temperatures. 0 LNG cargo cancellations were forecast 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 at the top section of the page highlights the sharp 68% decline in horizontal rig counts in the oil focus space since that's the Permian, Eagle Ford, 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 focus basins.
This dramatic reduction in activity is expected to result natural gas and NGL 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 $400,000,000 circled in rent. We continue to be proactive with debt repurchases during the Q3, repurchasing $461,000,000 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 Q4 of 2019, we have repurchased $1,300,000,000 of notional debt at a 17% weighted average discount, thereby reducing total debt by $220,000,000 from the discount alone, while reducing annual interest expense by $34,000,000 The remaining market value of the 2021 2022 senior notes net of what has been repurchased to date is shown on the right hand side of this slide and totals $915,000,000,000 in market value. AR had almost $1,100,000,000 of liquidity as of September 30, which is shown on the dark green bar on the left hand side of the page.
During the Q3, we generated $272,000,000 of EBITDAX and free cash flow of $88,000,000 before working capital investments. The EBITDAX and free cash flow numbers exclude the $29,000,000 hedge monetization, which we treated as an asset sale. We continue to expect to generate $175,000,000 to $200,000,000 of free cash flow in total during the second half of twenty twenty based on today's strip prices, providing additional liquidity to reduce debt. Including the override in royalty contingent payment of $51,000,000 which we will receive in the Q4 for hitting volume thresholds in the Q3 this year, We will have $1,400,000,000 in liquidity at year end 2020, more than sufficient to handle both the 2021 2022 maturities, which once again have a total market value of $915,000,000 today. Finally, total debt has been reduced to under 3,200,000,000 dollars We expect that to go down to $3,000,000,000 by year end due to free cash flow.
And debt to LTM EBITDAX was 3.2x 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 on 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 1 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 0 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 Downstream highlights the progress we have made this year. Despite a challenging backdrop, we have executed on our asset sale and refinancing plan raising over $1,000,000,000 reduced total debt by $620,000,000 addressed our 2021 2022 maturities, lowered well costs by 17%, which supports a low maintenance capital budget of just $580,000,000 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 Antero's employees. And finally, it's nice to have some tailwinds with the 2021 natural gas strip 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 and A.
Thank you.
Our first question today comes from Neil Dingim of Truist Securities. Please proceed with your question.
Good morning, all. First, Paul, again, 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 consider, given your massive acreage, your drilling partnerships or other strategies to maintain the lower spending or even pay down debt further?
Yes, Neal, we certainly would consider all those are also on the table. I think we can be more choosy now. The commodity price has moved both natural gas and NGLs 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 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 then just one follow-up. Just wanted to give the large amount of hedges, you all have some nice hedges. If I'm just wondering, would you all consider ramping activity next year if gas prices remain strong like this in order to take advantage of these higher prices? Or would that would the higher prices change your kind of growth or that strategy next year at all?
Thank you.
Neil, I mean, 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 $1,000,000,000 and get it down under $2,000,000,000 of total debt and leverage appropriately down under 2x.
Thank you.
The next question is from David Deckelbaum of Cowen. Please proceed with your question.
Morning, Paul, Glenn, Mike, team. Thanks for taking my questions. Yes. 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 'twenty one and 'twenty two maturities.
I guess as we think about maximizing free cash, is this the 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 $1,000,000,000 of debt pay down?
Well, fortunately, as we pointed out, David, the firm transport portfolio grows down to meet us if we stay at maintenance capital. So it does shrink to well under $100,000,000 of carry on that, which is a real benefit over the next few years. So we don't feel compelled to reach out 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 off from transport, etcetera. So rather than reacting with the drill bit like we've done in the past, I would say it'd 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 do you think that what's the impact, I guess, in 'twenty one in terms of where the strip is now to your dips on the gas side
and resulting transport expense? Yes. There's are not the most optimal pieces of transport. So we 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 transport expense. So it's that $0.11 per Mcfe that we had in the 3rd 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.
Okay.
It's a big book. It's big scale. And back to the earlier question, we don't have a real need to grow volumes, right, with being the 3rd largest gas producer, 2nd 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.
Got it. And if I could just add one quick one here. Just next year, I know there is an assumption of the Shell cracker startup at some point around mid year. And obviously, it'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 1st volumes kind of extracted there?
Yes. It's a good question, David. Shell, I think recently put out some information that they were about 70% complete on the facility here probably in the last month or 2. So a lot of progress made, but still a ways to go. If you look back at their Q2 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 have.
So we're not expecting it at all next year. Certainly, 2022 is in the realm of possibility, but still the 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. Please proceed with your question.
There you go. Thank you. So the I guess the value of Feet improving, do you see opportunities or demand for some of that excess Feet that might have us take down our net marketing expense next year?
Hi, Subash. Yes, there's definitely demand. There's distressed gas in the M2 pool in Appalachia. And so every day, we're buying a pretty large volume of 3rd 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 3rd party gas, the distressed 3rd 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 we are seeing that basis blow out. So yes, I think we'll continue to see that. In terms of releasing Feet, it can become it's not as straightforward as just buying the 3rd party gas and putting it into the pipe. We have our feelers out.
We sometimes release some of our Feet seasonally. For example, releasing for 5 months during the winter and collecting much of the demand charge to offset our unutilized Feet 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 most straightforward way is buying the 3rd party gas.
Got it. Okay. And then on well costs, I guess, we've been talking quite a bit about proppant and so on. When do you think you'll 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?
Yes. So to make the distinction, we've moved away from the so called Northern White from Wisconsin, etcetera. And so 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 the different sand suppliers. It's barged right up to a transload next 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 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 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 2nd wave, COVID, etcetera? And how much lower do you think prices could go on from an export basis?
Yes, it's a great question.
It's a bit of a 2 pronged answer here. I mean, the first piece is, if there is a second pronounced wave similar to what we saw back in spring, the most immediate response is a reduction in refinery runs, just a lack of transportation fuel demand. And so, 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 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 the potential upside to it.
But it also does you'll see propane and butane trade to oil. 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 just kind of highlights how the pricing can decouple. So it's tough to say what will happen in the 2nd wave. We think relative to heavier hydrocarbons, NGLs will perform significantly better.
But ultimately, none of us want to see the demand destruction that does come from a second wave across the board for
all the commodities.
The next question is from Harry Holback of Raymond James. Please proceed with your question.
Hi, guys. You all were around 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 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 it that is focused on the Permian, but there has been a few deals with EQT and even Southwestern and Appalachian. I was just wondering, do you all see any value for Antero pursuant to U and 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 for the industry it's been predicted 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. Congrats on a great quarter, guys.
Thank you. Thank you.
The next question is from Gregg Brody of Bank of America. Please proceed with your question.
Good morning, guys.
Hey, Gregg. Hey, Gregg.
And just trying to reconcile production guidance for this year and just taking into account the VPP and the Martica transaction. Is your the 2020 production number that you're supposed to stay flat on, is that 3.45 or is it 3.5 Bcf 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 $3,500,000 original and subtract the $50,000,000 a day from the VPP.
And as we think about this the 4th quarter, it was was Q3 greater because you processed more ethane or is it that we should expect the 4th quarter to decline to meet that number? No, it had nothing
to do with ethane. The Q3 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 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 1 quarter left with unreasonable thoughts around production in the Q4, but just the rounding alone can mean $100,000,000 to $200,000,000 a day for a 4th quarter when you're talking about 3.5 Bcfe a day. So we just don't adjust our guidance 1% or 2%, not material.
Got it. But we should be thinking about keeping production flat next year at 3.45%.
That's correct.
Got it. Congrats on the borrowing base redetermination. That's great. Once you have a success, it's you have a moment and 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 how just rolling off is or do you
the the commodity prices are higher than where we actually started this redetermination. So I would actually expect those price checks 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 $2,850,000,000 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 $2.85,000,000 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 deleveraging?
Yes. I think as I said earlier, Greg, 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 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 a bit here with commodity prices moving as they are. It's a volatile time.
Will we see some downturn because of the 2nd wave, 3rd 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 gave some great color on the NGL market. Just trying to think about how to think about ethane realizations going forward and maybe some goalpost as to how you think about it?
Yes. Most of the ethane in the basin that's going to be consumed within region. And there's really I'd say there's 4 existing petrochemical users, 2 up in Ontario, 1 down in Calvert City, Kentucky and then obviously the Shell project that we talked about earlier. Most of those transactions, I think you're going to see producers basing those deals on a gas based index. There are going to be some kind of uplift relative to natural gas economics for the producers in the region.
There is going to continue to be really through the end of this decade the ATEX pipeline that flows down to Mont Belvieu. And so that without a doubt is going to be Mont Belvieu linked. And so 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 the Paytex exposure is kind of a base load that's Mont Belvieu 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.