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. 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 Antero's First Quarter 2020 Investor Conference Call. We'll spend a few minutes going through the financial and operational highlights, and then we'll open it up for Q&A. I'd also like to direct you to the 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, Glen Warren, President and CFO, and Dave Cannelongo, 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 number three, titled "Cost Reduction Momentum." Over half of AR's reductions are expected to come from lower well costs, as we have driven a $3 million per well cost reduction in 2020 relative to our initial 2019 budget. This equates to roughly $320 million 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&A make up the remaining savings of approximately $280 million.
In total, we expect our capital and operating cost structure to be reduced by $600 million in 2020 as compared to 2019. Let's get a little more granular with slide number four, titled "Marcellus Well Cost Reductions," which provides an update to our Marcellus well cost targets. Driven by expanded flow back water blending operations during the first quarter, continued step change improvements in our drilling and completion efficiencies, and service cost deflation, we are now targeting $8.6 million for a 12,000-foot lateral, a $3 million 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 $970 per lateral foot. As we exited the first quarter of 2020, AR's well costs averaged approximately $720 per foot during the month of March.
This also represents a $30 per foot improvement from our previously targeted AFE of $750 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 $715 per lateral foot for the remainder of 2020. Turning to slide number five, 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 lower. During the first quarter, 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 our 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 three 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 $650 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&C capital budget to $750 million, flattening our production profile and maximizing free cash flow.
As you can see on slide number six, 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 three drilling rigs and two completion crews in the second quarter. Importantly, we are projecting $175 million 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-19 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-19 pandemic, Antero had developed a diverse set of buyers and sales points, as well as offsite 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 the 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-19 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. We are set up to weather the storm with minimal impact on our production for a prolonged period. Now let's turn to slide seven 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-19.
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 % 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 $0.55 per gallon at Marcus Hook net of shipping, or 37% above current strip prices. Moving to the supply side of the equation on slide eight, the decline in North American oil production is expected to result in a significant decline in associated NGL production. Everyone is familiar with the associated gas story. That is gas production associated with oil production.
The impact of the decline in associated NGLs is expected to be even more pronounced as we move into next year. Slide number nine summarizes the NGL macro outlook. Oil shale plays comprise of two-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+ associated NGLs, sets up well for a 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+ 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 and 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 Glen.
Thank you, Dave. Continuing on that theme in the macro outlook slide on page nine, slide nine, we're also encouraged by the natural gas macro outlook for the second half of 2020 and into next year, following the dramatic decline seen in industry rig counts and frack 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 basins since early March, just in seven or eight weeks. On slide number 11, you can see the dramatic decline in total U.S. frack spreads that fell to just 85 crews this week. A 73% decline in under two months, 70% decline in the oil-focused shale basins. This sharp reduction in activity will have a substantial impact on associated natural gas and associated NGL volumes, leading to undersupplied markets. Note that the five 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 1,200 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 four dry gas pads in our Ohio Utica acreage to drill those four 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 $2.85 billion just a few days ago, well in excess of lender commitments of $2.64 billion. As a reminder, this marks the first 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 billion 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 million of free cash flow in 2020, further improving our liquidity position. Here we have 160 because that's just the last three quarters of the year. Our updated development plan is projected to generate $175 million of cash flow in 2020, further improving our liquidity position. Assuming execution of our asset sale program of up to $900 million, we would have over $2.1 billion in liquidity at year-end 2020. More than sufficient to handle both the 2021 and 2022 maturities, which had a total par value just under $1.5 billion 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 million of notional debt at a 20% weighted average discount, thereby reducing total debt by $120 million and interest expense by $16 million. The remaining market value of the 2021 and 2022 senior notes, net of what has been repurchased to date, is shown on the right-hand side of page 12 and totals $1.1 billion. On the asset front, we continue to stay focused on executing our 2020 asset sale target range of $650 million-$900 million. Slide number 13, titled "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. 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 billion 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% of expected natural gas production hedged at $2.80 per MMBtu.
We also began hedging 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 barrels per day of 2020 crude oil and pentane production at $55.63 per barrel, or nearly 120% above current strip prices. As is core to 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 million this year, even at today's low commodity strip. Further, our reduced cost structure results in low maintenance capital of just $600 million to hold 2020 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-19 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. If you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star two if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. One moment please while we pull for questions. Our first question today comes from Holly Stewart of Scotia Howard Weil. Please proceed with your question.
Good morning, gentlemen.
Good morning, Holly.
Good morning.
Paul, I guess, or Glen, 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 '21 is back to $2.75. We do have a fall off in '22, 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. 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.
Even though we've been hedging in the first quarter, we're watching and rooting for it to go up a little bit more before we layer in any more. Pretty comfortable with our hedge book at this point, and no active plans to monetize it.
Okay. That's great. Maybe, Glen, you talked about the four 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 details in that 2021 guide at the maintenance level right now?
Yeah. We're talking about substitution there. 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. All in, we still would stick with about a 60-65 wells turn in line next year in 2021 to maintain our production flat at 3.5 Bcfe a day. Time will tell.
Okay, that's great. 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?
Yeah, for 2021.
If we went to maintenance capital, yeah, I think we're pretty neutral in 2021 using the current strip from cash flow.
Okay. Thank you, guys.
Free cash flow. Yeah. Thank you.
The next question is from David Deckelbaum of Cowen. Please proceed with your question.
Morning, guys. Thanks for the time. I just wanted to follow up on Holly'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 a trade-off, obviously, between your firm transport commitments and then maintaining liquidity here, it seems like you outlined slowing down would equate to about a $50 million increase in net marketing expense. It seems like that would be the better course right now, would be to hold volumes flat. Is that how you're thinking based on the current strip?
Yeah, I think that's what we said in the releases, that's the new plan. The key message from us is that we have a lot of flexibility, of course. If natural gas, if NGL prices ran up significantly and gas even more, we could certainly do more. Right now, given the current strip, that's the best indication we have, right? We adjust our capital plan accordingly, it leaves us with net marketing expense in that $150 million range while we stay flat. 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 2021? Are you assuming more frack stages per day executed, faster drilling times, just being able to accomplish that 60-65 wells with two rigs and a frack crew?
No, that's not really part of it. We have some other initiatives underway that we think will bring the cost down further. 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. You do have lower cost per lateral foot baked into that 600?
No. No, we do not.
Okay
$715 per lateral foot. If we went to 650, that would save another, how much? $50 million probably.
Roughly. Off of the $600 million next year.
Okay. Just the last one for me. The hedges that you added at 248 going out to 2022, you painted a fairly constructive picture on natural gas. I haven't seen you hedge down to 248 before. What was driving some of that decision, or was it timed 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 248 instead of putting some collars to the upside?
Well, I think it wasn't bank-driven. It was opportunity-driven, 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 $232 - $248. 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, you'd have a floor in the collar. If the market were $248 midpoint, if it's a symmetrical collar, as you know, your downside protection is going to be in the $230s or lower. Just a strategy to be more defensive for a portion of our production stream. Collars, yes, they give you the upside, 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. Please proceed with your question.
Thank you. Good morning.
Morning, Brian.
Wanted to follow up further on the maintenance capital and 2021 discussion. It seems like there's three 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. I guess my question is, do you need positives on each of these to spend above maintenance in 2021? 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. It would have to be very compelling and multi-year move and something that we could hedge to pull us above maintenance capital. Then, like I said, Brian, that maintenance capital is $600. That's assuming about 60 wells at $8.6 million each. Then you have some pad and infrastructure spending on top of that. 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. That's the messaging there. We're not trying to message towards potential increase in capital budget right now.
Great. Thanks. 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 2021 production levels?
Yeah. We've completed, I think, 25 wells this quarter and complete 40-plus this next second quarter. You're going to have growth in the second quarter and growth into the third, and then it flattens out from there. 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 2021.
Great. Thank you.
Thanks, Brian.
The next question is from Arun Jayaram of JPMorgan. Please proceed with your question.
Yeah. Good morning, gents. I was wondering if you could help us think about, you've guided to, I believe, 105 P.O.P.s 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 one completion crew, perhaps for the balance of the year? On our math, we could see you maybe getting in the 70s, just using your historical completion crew to POP ratio. To just maybe give us a little bit of color there. I did also want to talk about the $750 million in CapEx guide this year for 105 P.O.P.s. We have a hard time maybe reconciling that low a CapEx number based on that P.O.P. activity. Maybe you could help us, starting with those two questions.
Let me help you first. Obviously, you have to build in cycle time, right? If we're turning in line 105 wells this year, a lot of that capital occurred last year in 2019. There's carryover there. That's part of it. This is all highly engineered well by well. We know what our EURs are, and we know what our well costs are. You can bet it's all very stacked in.
I don't know if you just heard my answer to the last question, but we're actually going to do 70 in the first half of this year. I don't know how you're getting to 70. That's pretty hard when we're almost already there year to date. Going from there, it seems there'll be about $15 million-$20 million a quarter after that.
Yes. We should hit mid-year at almost 70 turning lines, right?
Another 35.
Got it. That's helpful. Just on the sustaining CapEx number, Glen, the 60-65 wells that you talked about on the call, does that include the 20 deferrals from the 2020 program?
Yeah. We're counting them as to what year we turn them in line, what year we turn them to sale. Yes, those are deferred into next year or counted in that 60, 65 wells next year.
Correct.
Got it. 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? On our numbers, we estimate a sustaining CapEx just under $900 million. Clearly costs are coming down, just trying to maybe adjust our thoughts on sustaining CapEx.
Yeah. I think, a simple way to think about it is just if our well costs are now about $8.6 million 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 million, and the rest of it is pad infrastructure type costs.
Also add those 20 wells, it's only about $2 million of drilling costs.
Yeah
Helps you by about $40 million. If you go down to that $650 million, which we think is achievable, that should more than offset that.
Obviously, turning line 60 wells, but we're also spudding a number of wells next year that will carry over into 2022.
Yeah, your $900 million, that's an interesting number. We're spending $750 million this year to grow 9%. I don't know how you'd have to spend $900 million to stay flat, so.
Yeah, I think that's an old number from probably a year and a half ago, going into 2019.
Right.
At well cost of about $970 a foot, that's all changed dramatically, right? $3 million less per well.
Yeah, fair enough. It was a one key number, but fair enough.
No, I think it was off of probably higher production level in terms of going to maintenance, that 900. Anyway, that's the current number, $600 million to stay flat at three and a half Bcfe.
Okay. All right, great. Thanks a lot.
Yeah. Thank you.
Thank you.
As a reminder, if you would like to ask a question, please press star then one on your telephone keypad. Our next question comes from Gregg Brody of Bank of America. Please go ahead.
Good morning, guys, and thank you for the comprehensive update. On your free cash flow numbers for this year, appreciate all the color. Just a few questions there. Last quarter, you were talking about a payment from the WGL breach. Is that still expected this year? Then also, maybe you can comment a little bit about what type of working capital adjustments you may have from dropping rigs. Is there a negative outflow we should be thinking about?
Yeah, 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 this year right now.
The free cash flow numbers before working capital changes.
Right.
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.
That's right.
Yeah.
Okay. Just maybe moving on to the asset sales. I know you pointed out all the things you've shown in the past. Is there anything moving to the front of the line based on what's happened with commodities and just investor interest that we should be thinking about, that you're seeing that's developing to be better than people think?
Could you state that again?
Just the asset sales.
Oh, asset sales.
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 can't really characterize that at this point, Gregg.
Got it. Just one more from me. Just noticed the Letters of Credit went up about $100 million this quarter. What drove that, and how should we be thinking about that and 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 the downgrades from the rating agencies that occurred in January. We haven't had any further LCs. That number was actually $710 million at year-end of LCs, and we actually accessed the surety bonds for $80 million. It brought it down to $630 million at year-end. We did have that pickup of $100 million that we talked about in February to $730 million, but that's where we see it right now.
Thanks for the clarity. Maybe just one more, if I can? Your program here, how should we think about the mix of production changing, relative to today, for next year?
It stays the same.
It does? Okay.
Yeah, if we started to mix in gas drilling next year, you really wouldn't see much of an impact until probably 2022, Gregg. We have such a big production base, it would take a while to change that mix very much. Right now we're still in the call it 68% gas and 32% liquids range.
Thanks for the time. Thank you very much for the time. Appreciate it.
Thank you. See you, Gregg.
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 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. It is a bit of a similar market. VPPs tend to be more of a bank market. 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. Really all the assets that we laid out there are becoming more and more attractive with the rise in the natural gas strip, and we think eventually a nice move in NGL prices.
Okay. Just one clarification on my end. 2021 has 40-45 new wells, obviously excluding the DUCs. With two 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 one and a half rigs. Each rig gets you about 30 wells, so.
We're drilling these wells spud to rig release in 10 and a half days now, 12,000-foot lateral. It's a pretty hefty pace. Just gets better.
Okay, perfect.
Yeah.
Thanks so much, guys.
Yeah. Thank you, Welles.
There are no additional questions at this time. I would like to turn the call back to Michael Kennedy for closing remarks.
Thank you for listening to our first quarter conference call. If you have any further questions, please feel free to reach out to us. Thanks again.
This concludes today's conference. You may disconnect your lines at this time. Thank you for your participation.