Greetings, and welcome to Antero Resources First Quarter 2020 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, Mike Kennedy, Senior Vice President of Finance.
Thank you for joining us for Antero's Q1 2020 investor conference call. We'll spend a few minutes going through the financial and operational highlights and then we will 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 would like to first remind you that during this call, Antero management will make forward looking statements. Such statements are based on our current judgments regarding factors that will impact the future performance of Antero and are subject to a number of risks and uncertainties, many of which are beyond Antero's control.
Actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Today's call may also contain certain non GAAP financial measures. Please refer to our earnings press release for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. Joining me on the call today are Paul Rady, Chairman 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. Let's start by discussing the cost reduction momentum across all of Antero's cost structure detailed on Slide 3 titled Cost Reduction Momentum. Over half of AR's reductions are expected to come from lower well costs as we have driven a $3,000,000 per well cost reduction in 2020 relative to our initial 2019 budget. This equates to roughly $320,000,000 in total well cost savings based on our updated development plan that assumes 105 completed wells in 2020 with an average lateral length of 11,400 feet. We deferred approximately 20 well completions from our 2020 plan to better align activity levels with today's depressed commodity price environment and resulting cash flow.
Lower midstream fees, net marketing expense, LOE and G and A make up the remaining savings of approximately $280,000,000 In total, we expect our capital and operating cost structure to be reduced by $600,000,000 in 2020 as compared to 2019. Now let's get a little more granular with Slide 4, titled Marcellus Well Cost Reductions, which provides an update to our Marcellus well cost targets. Driven by expanded flowback water blending operations during the Q1, continued step change improvements in our drilling and completion efficiencies and service cost deflation, we are now targeting $8,600,000 for a 12,000 foot lateral, a $3,000,000 per well savings relative to our 2019 budgeted well cost. The left hand side of the page illustrates AR's January 2019 budgeted well cost of $9.70 per lateral foot. As we exited the Q1 of 2020, AR's well costs averaged approximately $7.20 per foot during the month of March.
This also represents a $30 per foot improvement from our previously targeted AFE of $7.50 per foot announced earlier this year. These accelerated savings were primarily driven by more stages completed per day, improved lateral footage drilled per day and service cost deflation. We are expecting well costs to average $7.15 per lateral foot for the remainder of 2020. Now turning to Slide 5 titled Marcellus Drilling and Completion Efficiencies, let's discuss in more detail the drilling and completion efficiency gains that are helping drive our well costs slower. During the Q1, we have averaged 6,400 feet drilled per day sideways when drilling the lateral portion of the well, an 11% increase compared to the 2019 average.
We averaged only 10.7 days to drill and case a 12,000 foot lateral from spud to rig release. Further, the reduction in fresh water used in completions and the move to mostly 100 mesh sand has increased our completion efficiency to an average 7.1 stages per day during the quarter, an increase of 22% relative to the 2019 average. Last week, our 3 completion crews averaged 9.7 stages per day, including an Antero record for most stages in a day at 13 stages. Finally, we believe we have a pathway to take our well costs to $6.50 per lateral foot over the next 12 months. Antero's operating team has done a terrific job optimizing our drilling and completion operations and delivering cost reductions.
These integrated efforts have allowed us to now reduce our D and C capital budget to $750,000,000 flattening our production profile and maximizing free cash flow. As you can see on Slide 6 titled Cost Savings Momentum Leads to Lower Capital, Our new capital budget is 41% below the 2019 capital budget and 35% below the initial 2020 budget set in February of this year. We anticipate a decline in capital spending each subsequent quarter in 2020, reflecting continued efficiencies, the broader impact from service cost deflation and the release of 3 drilling rigs and 2 completion crews in the 2nd quarter. Importantly, we are projecting $175,000,000 of free cash flow in 2020 based on today's strip prices. With that, I'll turn it over to Dave Cannelongo for his comments.
Dave is our Vice President of Liquids Marketing and Transportation.
Thanks, Paul. I'll begin by providing an update on in basin condensate market dynamics. The COVID-nineteen pandemic and the nationwide stay at home order have severely impacted demand for transportation fuels, resulting in a dramatic decline in refinery runs. We have in turn witnessed a reduction in purchases of Appalachian oil condensate from the traditional buyers in the basin. Prior to the COVID-nineteen pandemic, Antero had developed a diverse set of buyers and sales points as well as off-site storage capacity.
Since then, we have expanded our customer base and nearly doubled our in basin storage capacity. To date, AR has not had to shut in or curtail any production as a result of storage constraints. We are confident today that we have firm sales and storage in place to produce our wells at full capacity at least through the summer. Due to the proactive steps taken at Antero to secure additional oil storage and sales, we expect that regional and national demand will be restored to a great extent before we would see any significant impacts to our production. Importantly, AR is 100% hedged on its oil and pentanes production in 2020, the two products most impacted by COVID-nineteen demand destruction at an average price of $55.63 per barrel.
There is still uncertainty about how long stay at home mandates will remain in place, reducing demand for oil, but we are set up to weather the storm with minimal impact on our production for a prolonged period. Now let's turn to Slide 7 and discuss the NGL macro environment. Global demand for NGL products has been much less impacted when compared to the significant decline in oil demand since COVID-nineteen. The restart of economic activity in Asia, coupled with lower refinery LPG production in the U. S.
And abroad, has led to strengthening prices for LPG on a relative basis to WTI as shown on the left hand side of the page. NGL prices have decoupled from WTI prices, highlighting the inelasticity of global NGL demand for petrochemical and residential commercial markets, further supported by government subsidies in countries like India. This is particularly evident as NGLs as a percentage of WTI has nearly doubled since February and the strengthening has occurred during the shoulder season when NGL prices are historically the weakest. The right hand side of the page illustrates Asia propane prices, which have already bottomed and continue to recover as economic activity resumes. Importantly, Antero is well positioned with access to international markets through Mariner East 2, where we have not seen any impacts on our ability to export LPGs.
As a reminder, Antero has the ability to adjust cargo destinations based on the most favorably priced markets, including taking advantage of strengthening prices in Asia. LPG prices in Europe have been slower to recover as economic activity has yet to return in a meaningful way and storage levels remain elevated. Consequently, Antero is targeting Asia destinations with our discretionary cargoes. Meanwhile, AR has hedged essentially all of its projected 2020 European propane exports at 0 point $5 per gallon at Marcus Hook net of shipping or 37% above current strip prices. Moving to the supply side of the equation on Slide 8.
The decline in North American oil production is expected to result in significant decline in associated NGL production. Everyone is familiar with the associated gas story, that is gas production associated with oil production, but the impact of the decline in associated NGLs is expected to be even more pronounced as we move into next year. Slide number 9 summarizes the NGL macro outlook. Oil shale plays comprise of 2 thirds of U. S.
NGL production, which is where we are seeing the steepest drop in drilling and completion activity today. Meanwhile, NGL demand is resilient as it is driven by petrochemical and rescom sectors as opposed to transportation fuels. In summary, the resilient global demand for NGLs combined with a decline in U. S. Associated NGLs and OPEC plus associated NGLs sets up well for continued NGL pricing improvement.
For several years now, the U. S. Has been critical to global LPG markets, responsible most recently for supplying well in excess of 50% of the world's waterborne LPG imports and growing. In our most recent NGL fundamentals analysis updated last quarter, the U. S.
Was expected to provide an incremental 445,000 barrels per day of LPG to world markets by 2022 to satisfy global growth driven by the residential, commercial and petrochemical markets. With both U. S. And OPEC plus NGL production anticipated to be in decline over this timeframe, the backdrop for NGLs begins to look similar to the scenario we saw play out in 2017 2018, resulting in strong NGL prices precipitated by a period of low oil prices and declining U. S.
Production. With that, I will turn it over to Glenn.
Thank you, Dave. Continuing on that theme in the macro outlook slide on Page 9, Slide 9, We're also encouraged by the natural gas macro outlook for the second half of twenty twenty and into next year following the dramatic decline seen in industry rig counts and frac spreads. 2020 natural gas production is forecast to exit 5.5 Bcf a day lower than 2019 exit with more substantial impacts in the near term driven by oil shut ins. Supply declines are expected to extend further to 8.5 Bcf a day in the aggregate by year end 2021. While demand certainly will be impacted from the global pandemic, it is expected to be a much lesser extent than oil and to be more short term in duration, leading to an undersupplied gas market by the end of 2020 and into 2021.
Slide number 10 highlights the sharp 43% decline in horizontal rig counts in the oil focused basin since early March, just in 7 or 8 weeks. On Slide number 11, you can see the dramatic decline in total U. S. Frac spreads that fell to just 85 crews this week, a 73% decline in under 2 months, 70% decline in the oil focus shale basins. This sharp production and activity will have substantial impact on associated natural gas and associated NGL volumes, leading to undersupplied markets.
Note that the 5 oil focused basins produce 26% of U. S. Natural gas supply and a whopping 67% of NGL supply. Antero is well positioned to benefit from higher natural gas prices with almost 70% gas production by volume and over 1200 dry gas locations in the Ohio, Utica and Marcellus shales. If dry gas economics are superior in 2021, which depends on how the NGL story develops, we may substitute up to 4 dry gas pads in our Ohio Utica acreage to drill those 4 pads, which would comprise roughly 50% of our 2021 development plan.
Turning to Slide number 12 titled Substantial Liquidity Enhancements, which illustrates our updated liquidity outlook and pathway forward. First, the borrowing base under our credit facility was approved at $2,850,000,000 just a few days ago, well in excess of lender commitments of 2.6 $4,000,000,000 As a reminder, this marks the 1st bank redetermination based on standalone financials following the midstream simplification and deconsolidation from Antero Midstream in March of 2019 and also reflects a significant drop in bank price decks, about 20% across the natural gas curve and 31% across the oil curve and you can see that in our appendix. Despite these developments, AR maintained its $1,000,000,000 of liquidity as of March 31, which is shown on the dark green bar on the left hand side of this page. Our updated development plan that Paul discussed is projected to generate about $175,000,000 of free cash flow in 2020, further improving our liquidity position. Here we have $160,000,000 because that's just the last three quarters of the year.
Our updated development plan is projected to generate $175,000,000 of cash flow in 2020, further improving our liquidity position. Assuming execution of our asset sale program of up to $900,000,000 we would have over $2,100,000,000 in liquidity at year end 2020, more than sufficient to handle both the 2021 2022 maturities, which had a total par value just under $1,500,000,000 at March 31, as you can see on the right hand side of that Page 12. Over the last two quarters, we have taken a proactive approach to debt reduction, repurchasing $608,000,000 of notional debt at a 20% weighted average discount, thereby reducing total debt by $120,000,000 and interest expense by $16,000,000 The remaining market value of the 2021 2020 2 senior notes net of what has been repurchased to date is shown on the right hand side of Page 12 and totals 1,100,000,000 dollars On the asset front, we continue to stay focused on executing our 2020 asset sale target range of $650,000,000 to 900,000,000 dollars Slide number 13, title asset sale monetization opportunity set. You can see we have a multitude of options available to us, which we've reviewed with the market in the past. While the recent market volatility has created a challenging backdrop, the 10% rise in the natural gas strip and improved outlook for NGLs has provided a catalyst to the market.
We are in substantive discussions with several counterparties, so we remain confident that we will achieve our asset sale targets this year. Now let's move on to Page 14, titled Well Protected from Near Term Gas Price Weakness. Antero has a long track record of hedging and selling production forward as we have generated $5,000,000,000 of net cash hedge gains since 2008. For 2020, AR has hedged 94% of its expected natural gas production at $2.87 per MMBtu, that's 23% above current strip pricing. AR is also well hedged in 2021 with 100 percent expected natural gas production hedged at $2.80 per MMBtu.
We also began hedging our deal with a goal of having the majority of projected natural gas production hedged before we enter 2022. As you can see on Slide number 15, significant oil and oil equivalent hedge position, Antero Resources is 100% hedged on 26,000 per day, 26,000 barrels per day of 2020 crude oil and pentane production at 55 point $6.3 per barrel or nearly 120% above current strip prices. As this quarter our strategy, we will continue to be opportunistic in adding to our natural gas and liquids hedge profile going forward. In conclusion, the recent borrowing base redetermination was an important step in enhancing our liquidity profile. The successful execution of our asset sale program will provide sufficient liquidity to manage our upcoming senior note maturities until refinancing alternatives emerge.
Our reduced capital budget puts us in a position to deliver substantial free cash flow estimated at $175,000,000 this year even at today's low commodity strip. Further, our reduced cost structure results in low maintenance capital of just $600,000,000 to hold 20 20 average volumes at around 3.5 Bcfe per day flat in 2021. If commodity prices remain depressed, we plan to spend at maintenance level in 2021 to preserve liquidity and maximize free cash flow with an increased focus on our dry gas drilling inventory. I'll close out by saying we continue to be pragmatic and diligent in response to the current uncertainty driven by the COVID-nineteen pandemic. And I would like to thank all of our employees for their dedication during these unprecedented times.
With that, I'll turn the call over to the operator for questions.
Thank you. At this time, we'll be conducting a question and answer session. Our first question today comes from Holly Stewart of Scotia Howard Weil. Please proceed with your question.
Good morning, gentlemen. Paul or I guess or Glenn, can you maybe just start off by talking a little bit about how you're thinking about the hedge book? You saw one of your peers monetize some of their hedges. It looks like 'twenty one is back to $275,000,000 We do have a fall off in 'twenty two, but just curious about how you're thinking about that portfolio and its evolution?
Well, in terms of our long term evolution, as we said in our prepared remarks, Holly, we expect to continue to hedge and so that much of our gas production or most of it will be hedged by the time we enter Cal 22. As you know, we're not afraid to monetize hedges. We've done it before. Rarely have we, I think, monetized and left ourselves naked. Instead, we've just monetized and repriced the hedge book at a lower strike price so that we still have protection on the downside.
So that's possible, although not necessarily an active idea at the moment. We're enjoying the curve move up. As you know, you've seen it move up through Cal 21 and into Cal 22, and we think that's positive and underpinned by fundamentals. So even though we've been hedging in the Q1, we're watching and rooting for it to go up a little bit more before we layer in anymore. So, pretty comfortable with our hedge book at this point and no active plans to monetize it.
Okay. That's great. And then maybe Glenn, you talked about the 4 different pads in the Ohio dry gas area. I think you said that comprised about 50% of the 2021 plan at this point. Can you sort of give us some color around maybe TILs in that 2021 guide at the maintenance level right now?
Yes. And that's we're talking about substitution there. So those would take the place of rich gas pads that we had on the schedule. We've not made the decision to make that move yet, Holly. As you can see, we're pretty bullish on the NGL story and think it may pay for us just to stay the course, but we want to develop that optionality to substitute in some dry gas pads.
But all in, we still would stick with about a 60, 65 wells turned in line next year in 2021 to maintain our production flat at 3.5 Bcfe a day. So time will tell.
Okay, that's great. And then maybe one final one for me. Just on that maintenance plan that you've outlined, do you have a free cash flow estimate at this point to highlight?
For next year, Holly?
Yes, for 2021.
If If we went to maintenance capital. Yes, I think we're pretty neutral in 2021 using the current strip.
Okay. Thank you, guys.
Free cash flow. Yes. Thank you.
The next question is from David Deckelbaum of Cowen. Please proceed with your question.
Good morning, guys. Thanks for the time. I just wanted to follow-up on Holli's last question just about the maintenance capital program. Based on current strip, is that where you're leaning right now in terms of planning for next year? I know that there's been there's a trade off obviously between your firm transport commitments and then maintaining But it But it seems like that would be the better course right now, would be the hold volumes flat.
Is that how you're thinking based on the current strip?
Yes, I think that's what we said in the releases and that's the new plan. And we had the key message for us from us is that we have a lot of flexibility of course. And if natural gas if NGL prices ran up significantly and gas even more, we can certainly do more. But right now given the current strip and that's the best indication we have, right? So we adjust our capital plan accordingly and it leaves us with net marketing expense in that $150,000,000 range while we stay flat.
But that will come down over time as we grow into that again eventually. I
guess as you think about, are you continuing this capital efficiency progression into 'twenty one? Are you assuming more frac stages per day executed, faster drilling times, just being able to accomplish that 60 to 65 wells with 2 rigs and a frac crew?
No, that's not really part of it. We have some other initiatives underway that we think will bring the cost down further. So not ready to talk about those yet today, but the point is there's continued momentum. We haven't hit the wall yet on cost per lateral foot.
Got it. But you do have lower cost per lateral foot baked into that $600,000,000
No. No, we do not. It's assuming the $7.15 per lateral foot. So if we went to $650,000,000 that would save another how much $50,000,000 probably off of the $600,000,000 next year.
Okay. Just the last one for me. The hedges that you added at $2.48 going out to 2022, you painted a fairly constructive picture on natural gas. Haven't seen a hedge down to $248,000,000 before. What was driving some of that decision?
Or was it times differently with how you saw the market kind of developing? Was this bank driven? I guess what's the thoughts behind layering in hedges at $2.48 instead of putting some collars to the upside?
Yes. Well, I think the as you it wasn't bank driven. It was opportunity driven, and we just saw prices moving, I think during the time that we were watching and rooting for it to go up, it probably went from $2.32 to $2.48 So we saw the opening there to add more hedges. We haven't hedged that low before. As you know, collars, of course, they are two way and so you'd have a floor in the collar.
If you wanted if the market were 248 midpoint, then if it's a symmetrical collar, as you know, then your downside protection is going to be in the 230s or lower. And so just a strategy to be more defensive for a portion of our production stream. So collars, yes, they give you the upside, but just in case, they don't fit the bill on protecting you quite as much on the downside. We've generally been a fan more of straight swaps and keeping it quite simple to lock in the highest floor for the part we're looking for protection for.
Appreciate the time guys.
Thank you.
The next question is from Brian Singer of Goldman Sachs.
I wanted to follow-up further on the maintenance capital in 2021 discussion. It seems like there's 3 factors that await clarity here, the gas strip and the potential for further upside there, asset sales and leverage, and then the third one is the refinancing of debt. And I guess my question is, do you need positives on each of these to spend above maintenance in 2021? Or if gas prices are materially higher, but the refinancing and the leverage hasn't been fully rebased, would you spend above maintenance?
I'd say it's unlikely we spend above maintenance in most any case. I think we're in a position of wanting to generate as much free cash flow as we can. So it would have to be very, very compelling and multiyear move and something that we could hedge to pull us above maintenance capital. And then like I said, Brian, that maintenance capital of 600, that's assuming about 60 wells at $8,600,000 each and then you have some pad and infrastructure spending on top of that. So that's how you get to the 600.
If we reduce that to 650 a foot for instance as a target, then it would be less than that. So that's the message in there. We're not trying to message towards potential increase in capital budget right now.
Great, thanks. And then can you discuss how the impact of the rig reduction to come and the timing of the shifting of the 20 well completions into 2021 from later this year would impact late 2020 or early 20 21 production levels?
Yes. We've completed, I think, 25 wells this quarter and complete 40 plus next Q2. So you're going to have growth in the 2nd quarter and growth into the 3rd and it flattens out from there. So your exit rates are right around that 3.5 Bcfe a day. I mean we were at 3.4 this quarter.
So it's a relatively flat profile and continues that way into 'twenty one.
The next question is from Arun Jayaram of JPMorgan. Please proceed with your question.
Yes. Good morning, gents. I was wondering if you could help us think about, you've guided to, I believe, 105 TILs for 2020. Just wondering if you could maybe just walk us through the quarterly progression and just how do you get there as you move down to 1 completion crew perhaps for the balance of the year? Because on our math, we can see you maybe getting in the 70s, just using your historical completion crew to pop ratio, but just maybe give us a little bit of color there.
And I did also want to talk about the $750,000,000 in CapEx guide this year for 105 TILs. We would we have a hard time maybe reconcile that lower CapEx number based on that Till activity, but maybe you could help us starting with those two questions.
Let me help you first. I mean, obviously, you have to build in cycle time, right? So if we're turning in line 105 wells this year, a lot of that capital occurred last year in 2019, there's carryover there. So that's part of it. And this is all highly engineered well by well.
We know what our URs are. We know what our well costs are. So you can bet it's all very stacked in.
Yes, I don't know if
you just heard my answer in the last question, but we're actually going to do $70,000,000 in the first half of this year. I don't know how you're getting to $70,000,000 that's pretty hard when we're almost already there year to date. So then going from there, it seems to be about $15,000,000 to $20,000,000 a quarter after that.
Yes, we should hit mid year at almost 70 turning lines, right, another 35.
Got it. That's helpful. And just on the sustaining CapEx number, Glenn, the 60 to 65 wells that you talked on the call, does that include the 20 deferrals from the 2020 program?
Yes, we're counting them as to what year we turn them in line, what time we turn what year we turn the sales. So yes, those are deferred into next year or counted in that 60, 65 wells next year.
Correct. Got it. And if we just included the CapEx on those 60 to 65 wells including some carryover, what would you estimate that your sustaining CapEx would be if you also counted the 20 wells? Because on our numbers, we estimate the sustaining CapEx just under 900,000,000 dollars but clearly costs are coming down. So just trying to maybe adjust our thoughts on sustaining CapEx.
Yes, I think a simple way to think about it is just if our well costs are now about $8,600,000 for 12,000 foot lateral, which is pretty close to our average expectation for next year, 60 wells times 8.6, you're a little bit over $500,000,000 and the rest of it is pad infrastructure type costs.
But it also had that 20 those 20 wells, it's only about $2,000,000 of drilling costs. So that only yes, out you by about $40,000,000 And if
you go down to that $650,000,000 which we think is achievable, that should more than offset that. And obviously, turn in line 60 wells, but we're also spudding a number of wells next year that will carry over into 2022.
Yes. And your $900,000,000 I mean, that's an interesting number. I mean, we're spending $750,000,000 this year to grow 9%. So I don't know how you'd have to spend $900,000,000 to stay flat. Yes, I
think that's an old number from probably a year and a half ago going into 2019. Right. It well cost of about $9.70 a foot and that's all changed dramatically, right, dollars 3,000,000 less per well.
Fair enough. It was a 1Q number, but fair enough.
No, I think it was off of higher probably higher production level in terms of going to maintenance that 900. Dollars That's the current number, dollars 600,000,000 stay flat at $3,500,000,000
Okay. All right, great. Thanks a lot.
Thank you.
Our next question comes from Greg Groge of Bank of America. Please go ahead.
Good morning, guys. Thank you for the confidence and update. Just on your free cash flow numbers for this year, appreciate all the color. Just a few questions there. There was last quarter you were talking about a payment from the WGL breach.
Is that still expected this year? And then also maybe you can comment a little bit about what type of working capital adjustments you may have from dropping rigs, sort of is there a negative outflow we should be thinking about?
Yes, we are assuming that payment from that lawsuit gets paid this year. That's not exact. It could certainly float into next year, but that's included in this year right now.
And then the free cash flow numbers before working capital changes. We've been able to get our hands around that. It's such a dynamic equation and a lot of factors in it that we just don't have a
good ability to forecast that.
Okay. And just maybe moving on to the asset sales, I know it's you pointed out all the things you've done, you've shown in the past. Is there anything moving to the front that's the front of the line based on what's happened with commodities and investor interests that we should be thinking about that you're seeing that's sort of developing to be better than people think?
Could you say that again?
What So just the asset sales, what's you've listed a number of asset sales off. I'm curious what do you think is moving to the front of the line in terms of opportunities?
No, I'd say we have a whole portfolio of discussions going on. So, I can't really characterize that at this point, Greg.
Got it. And just one more for me. Just noticed the letters of credit went up about $100,000,000 this quarter. What drove that and how should we be thinking about that in the surety market? How that should play through for the next year?
We actually talked about that in the February conference call that occurred in January with kind of the downgrades that from the rating agencies that occurred in January. We haven't had any further LCs. That number was actually $710,000,000 at year end of LCs and we actually accessed the surety bonds for 80,000,000 dollars It brought it down to $630,000,000 at year end and we did have that tick up of $100,000,000 that we talked about in February to 7.30, but that's where we see it right now.
Thanks for the clarity. And maybe just one more if I can. Just your program here, how should we think about the mix of production changing relative to today for next year?
It stays the same. Yes.
If we started to mix in gas drilling next year, you really wouldn't see much of an impact until probably 2022, Greg. And we have such a big production base, it would take a while to change that mix very much. So right now, we're still on the call it 68% gas and 32% liquids range.
The next question comes from Welles Fitzpatrick of SunTrust. Please proceed with your question.
Hey, good morning.
Hi, Welles.
I noticed VPPs have kind of hopped into the potential menu for monetizations. Can you talk to how those got in there? I mean, is that is the override market maybe just a little bit soft like we're seeing in the public mineral company multiples or does that broaden the potential list of buyers that you could transact with?
Well, VPPs are somewhat similar to overrides obviously. So it is a bit of a similar market and the VPPs tend to be more of a bank market. And it's just something it's another tool in the tool chest that's I think very viable right now along with overrides and other things too. But really all the assets that we laid out there are becoming more and more rise in the natural gas strip and we think eventually a nice move in NGL prices.
Okay. And then just one clarification on my end. So 'twenty one has 40 to 45 new wells, obviously excluding the DUCs with 2 rigs. Am I getting that right? That seems like a little bit of a slower pace than you guys have been turning in?
No, I think that's more like 1.5 rigs.
Each rig gets you about 30 wells. We're drilling these wells by the rig release in 10.5 days now, 12,000 foot lateral. So it's a pretty hefty pace. This gets better.
Okay, perfect.
Yes.
Thanks so much, guys.
Yes. Thank you, Wills.
There are
no additional questions at this time. I would like to turn the call back to Mike Kennedy for closing remarks.
Thank you for listening to our Q1 conference call. If you have any further questions, please feel free to reach out to us. Thanks again.