Antero Resources Corporation (NYSE:AR) Q1 2020 Results Earnings Conference Call April 30, 2020 1:00 PM ET
Mike Kennedy – SVP Finance
Paul Rady – Chairman and CEO
Glen Warren – President and CFO
Dave Cannelongo – Vice President of Liquids Marketing & Transportation.
Conference Call Participants
Holly Stewart – Scotia Howard Weil
David Deckelbaum – Cowen
Brian Singer – Goldman Sachs
Arun Jayaram – JP Morgan
Gregg Brody – Bank of America
Welles Fitzpatrick – SunTrust
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. [Operator Instructions]. 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 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 home page of our website at www.anteroresources.com where we have provided a separate earnings call presentation that will be reviewed during today’s call.
Before we start our comments, I would first like to remind you that during this call Antero management will make forward-looking statements. Such statements are based on our current judgments regarding factors that will impact future performance of Antero and are subject to a number of risks and uncertainties, many of which are beyond Antero’s control. Actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.
Today’s call may also contain certain non-GAAP financial measures. Please refer to our earnings press release for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. Joining me on the call today are Paul Rady, Chairman and CEO; Glen Warren, President and CFO; and Dave Cannelongo, Vice President of Liquids Marketing & Transportation.
I will now turn the call over to Paul.
Thank you, Mike. Let’s start by discussing the cost reduction momentum across all of Antero’s cost structure detailed on Slide number 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 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.
Now, let’s get a little more granular with slide number 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 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 costs.
The left hand side of the page illustrates AR’s January 2019 budgeted well costs 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.
Now turning to slide number 5 titled Marcellus Drilling and Completion Efficiencies, let’s discuss in more detail the drilling and completion efficiency gates 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 in case a 12,000 foot lateral from spud to rig release.
Further, the reduction in fresh water used in our completions now been moved 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 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 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 & 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 mostly 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, 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-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 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 as storage levels remain elevated. Consequently, Antero was targeting Asia destinations with our discretionary cargoes. Meanwhile, AR has had 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 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 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 res/comm sectors as opposed to transportation fuels.
In summary, the resilient global demand for NGLs combined with the 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. And 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 lower oil prices and declining U.S. production.
With that, I will turn it over to Glen.
Thank you, Dave. Continuing on that theme and the macro outlook slide on Page 9 — Slide 9, 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 frac spreads.
2020 natural gas production is forecasting 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 a global pandemic, it is expected to be a much lesser extent than oil and to be more short-term in duration leading to an undersupply of gas market by the end of 2020 and into 2021.
Slide number 10 highlights the sharp 43% decline in horizontal rig counts and 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. frac spreads that fell to just 85 crew this week, a 73% decline in only 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 produced 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. The 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 acres to drill those four pads which will 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 since 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. 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 million 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 with 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 have 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 the interest expense by $16 million. The remaining market value of the 2021 to 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 to $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. Although recent market volatility has created a challenging backdrop a 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 for 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% expected natural gas production hedged at $2.80 per MMBtu.
We also began hedging our 2022 natural gas production, adding 688 BBtus per day of natural gas hedges at an average price of $2.48 per MMBtu, 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 and total 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 lower 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.
[Operator Instructions]. Our first question today comes from Holly Stewart of Scotia Howard Weil. Please proceed with your question.
Paul 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 275 million. 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’ve — 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 that’s necessarily an active idea at the moment. We are 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 first quarter, 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, Glen, you talked about the four different pads in the Ohio dry gas area. I think you said that comprise about 50% of the ‘21 plan at this point. Can you sort of give us some color around maybe TIL in that ‘21 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 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 from me. Just on that maintenance plan you’ve outlined, do you have a free cash flow estimate at this point to highlight?
For next year, Holly?
Yes for ‘21?
If you went to maintenance capital, yes, I think we’re pretty neutral in 2021 using the current strip for cash flow.
The next question is from David Deckelbaum of Cowen. Please proceed with your question.
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 been — there’s a trade off obviously between your firm transport commitments and then maintaining liquidity here. But it seems like you outlined slowing down would equate to rather $50 million increase in net marketing expense. But 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?
Yes. I think that’s what we said in the release 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 a net marketing expense in that $150 million 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 ‘21? Are you assuming more frac stages per day executed faster drilling times just being able to accomplish that 60 to 65 wells with two 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 million?
No, we do not. It’s assuming the $715 per lateral foot. So if we went to $650 million, that would save another, how much $50 million probably off of the $600 million next year.
Okay. Just the last one from 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 you hedged down to $2.48 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 level before. As you know collars, of course, they are two way. And so you have a floor in the collar. If you wanted — if the market were $2.48 midpoint, then — if it’s a symmetrical collar as you know then your downside protection is going to be in the $2.30s 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.
The next question is from Brian Singer of Goldman Sachs. Please proceed with your question.
Wanted to follow up further on the maintenance capital in 2021 discussion. It seems like there’s three factors that await clarity here, the gas strips 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. So I think we’re in a position of wanting to generate much free cash flow as we can. So it would have to be very, very compelling and multi-year move and something that we could hedge to pull us above maintenance capital. And then, like I said, Brian, that maintenance capital of 600 million, that’s assuming about 60 wells at $8.6 million each. And then you have some pad and infrastructure spending on top of that. So that’s how you get to the 600 million. If we reduce that to 650 a foot instance, as a target, then it would be less than that. So that’s the messaging there. We’re not trying not to message towards a 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 2021 production levels?
Yes, we’ve completed I think 25 wells this quarter, we’ll complete 40 plus this next — second quarter. So you’re going to have growth in the second quarter and growth into the third, and then it flattens out from there. So your exit rates were right around that 3.5 Bcfe a day. And we were at 3.4 this quarter. So it’s a relatively flat profile and continues that way into ‘21.
The next question is from Arun Jayaram of JP Morgan. Please proceed with your question.
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 one completion crew perhaps for the balance of the year? Because on our math, we can see maybe getting in the 70s just using your historical completion crew to pop the ratio but just maybe give us a little bit of color there? And I did also want to talk about the $750 million in CapEx guide this year for the 105 TILs. We would — we have a hard time to maybe reconcile that lower CapEx number based on that TIL 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, alright? So if we’re turning in line, the 105 well this year, a lot of that capital occurred last year in 2019, there’s carry over there. So that’s part of it. And this is all highly engineered well by well. We know what our EURs are, we know what our well costs are. So, you can bet it’s all very stacked in.
Yes. And I don’t know if you’ve just heard my answer to the last question, but we’re actually going to do 70 in the first half of this year. So I don’t know how you’re getting to 70. That’s pretty hard when we’re almost already there year-to-date. So then going from there it seems there’ll be about 15 million to 20 million a quarter after that.
Yes, we should get mid-year at almost 70 turning lines, and then another 35.
And just on the sustaining CapEx number going to 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 turned them in line. What time we turn — what year we return the sales. So yes, those are deferred into next year or counted in that 60, 65 wells next year.
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 we also counted the 20 wells? Because in our numbers we estimate the sustaining CapEx just under 900 million, but the quarterly 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 for 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 sums 8.6, you are a little bit over 500 million and the rest of it is pad infrastructure type costs.
But I’d also add that 20 — those 20 wells, it’s only about 2 million of drilling costs, so that only helps you by about $40 million. And if you go down to that 650 million, which we think is achievable, that more than offset that. So …
And obviously, turn in line 60 wells but we’re also spudding another well next year that will carry over in 2022. So…
Yes. And your 900 million, I mean that’s an interesting number. I mean, we’re spending 750 million this year to grow 9%. So I don’t know how you have to spend 900 million to stay flat. So…
Yes. I think that’s an old number from probably a year and a half ago, going into 2019 at well cost of about 970 a foot and that’s all changed dramatically, right. $3 million less per well.
Yes. Fair enough. It was 1Q number, but fair enough.
It was off of higher — probably higher production level in terms of going to maintenance, that 900 million. That’s the current number 600 million to stay flat at 3.5.
Our next question comes from Gregg Brody of Bank of America. Please go ahead.
Just on your free cash flow numbers for this year, appreciate all the color. Just a few questions there. Last quarter you were talking about 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’re assuming that payment for that lawsuit gets paid this year. That’s not exact. It can certainly flow into next year, but that’s included this year right now. And then the free cash flow numbers before working capital change.
Is there a — can you give us a sense of how much that should — how much would drain that should be from dropping the rigs?
Gregg, we’ve tried in years past to really forecast that and we’ve never really been able to get our hands around that. There’s such a dynamic equation, a lot of factors in it that we just don’t have a good ability to forecast that yet.
Okay. And just maybe moving on to the asset sales, I know that you pointed out, and you’ve shown in the past. Is there anything moving to the front that — 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 sort of developing better than people think?
Could you say that again, what…?
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?
Yes, I’d say we have a whole portfolio of discussions going on, so can’t really characterize that at this point, Gregg.
Got it. And just one more from me. Just noticed the letters of credit went up about a 100 million this quarter. What drove that and how should we be thinking about that in the surety market, how that should play through to the next year?
We actually talked about that in the February conference call that occurred in January with the 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 million at year end of LCs and we actually accessed surety bonds for 80 million. It brought it down to 630 million at year end and we did have that pickup of a 100 million that we talked about in February to 730 million. But that’s where we see it right now.
Gregg Brody — Bank of America
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’s the same.
Yes, if we start to mix in gas drilling next year, you really wouldn’t see much of an impact until probably 2022 Gregg and with such a big production base, it would take a while to change that mix for very much. So right now we’re still on the 68% gas and 32% liquids range.
The next question comes from Welles Fitzpatrick of SunTrust. Please proceed with your question.
I noticed VPPs have kind of hopped into the potential menu for monetization. Can you talk to how those got in there? I mean is that — is 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 as overrides, obviously. So it is a bit of a similar market and VPP tend to be more of a bank market. And it’s just something — it’s another tool, in 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 attractive with the rise in the natural gas strip and we think eventually nice move in NGL prices.
Okay. And then just one clarification on buy-in. So ‘21 has 40 to 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?
Now, I think that’s more like 1.5 rigs. Now each rig gets you about 30 wells.
We’re drilling these wells by the rig release 10.5 days now, 12,000 foot lateral, so it’s a pretty hefty pace, just gets better.
There are no additional questions at this time. I’d like to turn the call back to Mike 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.