Q1 2020 Earnings Call
Greetings and welcome to Antero resources first quarter Twentytwenty Conference call.
At this time, all participants are and I'll listen only mode.
Oh sure 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 the kind of conference over to your host Mike Kennedy Senior Vice President Finance.
[music]. Thank you for joining us for Antero first quarter.
2020 Investor Conference call.
Well spend a few minutes going through the financial and operational highlights and then we'll open it up Q and <unk>.
I'd also like to direct to the home page of our website at Www Dot Antero resources Dot com.
Where we have provided a separate earnings call presentation that will be reviewed during today's call.
Before we start or comments I would like to first remind you that during this call and Taro 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 anteros control.
Actual outcomes and results could materially differ from what has expressed or implied or forecast and such statements.
Today's call May also contain certain non-GAAP financial measures.
Please refer to our earnings press release for information for important disclosures regarding such measures, including reconciliations most comparable GAAP financial measures.
Joining me on the call today, our poll ready Chairman and CEO, Glenn Warren President and CFO, and Dave kind of long ago, Vice president of liquids marketing and transportation.
I'll now turn the call over to Paul.
[noise]. Thank you Mike.
[music].
By discussing the cost reduction momentum across all of anteros cost structure detailed on slide number three titled cost reduction momentum.
Over half of a ours reductions are expected to come from lower well cost as we have driven 83 million dollar 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 lengths of 11400 feet.
We deferred approximately 20, well completions from our 2020 plan to better align activity levels with today's depressed commodity price environment at resulting cash flow.
Lower midstream phase that marketing expense aloe eat and Gionee make up the remaining savings of approximately $280 million.
In total we expect our capital and operating cost structure can be reduced by $600 million in 2020 as compared to 29 team.
Now.
Let's get a little more granularity on slide number four titled Marcellus, well cost reductions, which provides an update to our Marcellus well cost targets.
Driven by expanding flowback water blending operations during the first quarter.
Continued step change improvements in our drilling and completion efficiencies and service cost deflation, we're now targeting $8.6 million for a 12000 foot lateral a 3 million dollar per well savings relative to our 2019 budgeted well cost.
Well left hand side of the page illustrates a ours January 2019 budgeted well costs.
$970 per lateral foot.
As we exited the first quarter of 2028 hours well costs averaged approximately $720 per foot during the month of March.
This also represents a $30 per foot improvement from our previously targeted a copy 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.
[noise], we're expecting well costs to average $715 per lateral foot for the remainder of 2020.
Now 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 6400 feet drilled per day sideways when drilling the lateral portion of the well and 11% increase compared to the 2019 average.
We averaged only 10.7 days to drill in case and 12000 foot lateral from spud to rig release.
Further the reduction in freshwater used in our completions and the move to mostly hundred mesh sand.
Has increased our completion efficiency to an average 7.1 stages per day during the quarter, an increase of 22% <unk>, 22% relative to the 2019 average.
Last week, our three completion crews averaged 9.7 stages per day.
Including and 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.
Anteros 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 DNC capital budget to $750 million flattening, our production profile and maximizing free cash flow.
[noise] as you can see on slide number six titled cost savings on that 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 attitude completion crews in the second quarter.
Importantly, we are projecting a $175 million of free cash flow in 2020 based on today's strip crisis.
With that I'll turn it over to Dave Channel on go 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 Cobot, 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 haven't turned witnessed a reduction in purchases of Appalachia oil condensate from the traditional buyers in the basin.
Prior to the Coven 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. They are 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's sales and storage in place to produce our wells at full capacity at least through the summer.
Due to the proactive steps taken at Interoil 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, they are as 100% hedged on its oil and Pentanes production in 2020, the two products most impacted by cobot 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 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 cobot 19.
The restart of economic activity in Asia, coupled with lower refinery LPG production in the U.S. and abroad.
Lets to strengthening prices for LPG on a relative basis to WT API as shown on the left hand side of the page.
NGL prices have decouple from W.G.I. prices, highlighting the elasticity 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 WT ATI has nearly doubled since February and the strengthening as occurred during the shoulder season, when NGL prices are historically the weakest.
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 two 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.
BG prices in Europe had been slower to recover as economic activity has yet to return in a meaningful way in storage levels remain elevated.
Consequently, Antero is targeting Asia destinations with our discretionary cargos. Meanwhile, our has hedged essentially all of its projected 2020 European propane exports at 55 cents 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 significant decline and 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 nine summarizes the NGL macro outlook.
Oil shale plays comprise of two thirds of US 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 the rest comp sectors as opposed to transportation fuels in summary, the resilient global demand for Ngls combined with the decline in us associated Ngls and OPEC plus associated Ngls sets up well for continued NGL pricing.
Proven.
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 445000 barrels per day of LPG to world markets by 2022 to satisfy global growth driven by the residential commercial and petrochemical markets.
With both us 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 in 2018, resulting in strong NGL prices precipitated by a period of low oil prices and declining us production with that I will.
Turn it over to Glenn.
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 an industry rig counts in frac spreads.
2020 natural gas production is forecast to exit 5.5 Bcf a day lower than 20, nineteenx it 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 aggregate by year.
In 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 undersupply gas market by the end of 2020 and into 2021.
Slide number 10 highlights the sharp 43% decline the horizontal rig counts in the oil focused base basins since early March Justin seven or eight weeks.
On slide number 11, you can see the dramatic decline in total us frac spreads that fell to just 85 Christmas week, 73% decline two months, 70% decline in that will focus shale basins. The sharp production in activity will have substantial impact on associated natural gas.
Yes, 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, 570% gas production by volume and over 1200 dry gas locations in the Ohio, Utica and Marcellus shales.
Sure I guess economics are superior 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 title substantial liquidity enhancements, which illustrates our updated liquidity out look in 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 the significant drop in bank price decks about 20% across the natural gas curve and 30.
1% across the oil curve and you can see that in our appendix.
Despite these developments are maintained is $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 or free cash flow in 2020 further improving our liquidity position.
Here, we have won 60 because that's just.
The last three quarters of the year, our updated development plan is projected to generate $175 million 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 liquidity at year end 2020.
More than sufficient to handle both the 2021 at 20 to 22.
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 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 repurchase today is shown on the right hand side on 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 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 outlet for Ngls has provided a catalyst to the market.
We are at substantive discussions with several counterparties. So we remain confident that we will achieve our asset sales targets. This year.
Now, let's move on to page 14 title well protected from near term gas price weakness.
Antero has a long track record of hedging in selling production forward as we have generated $5 billion net cash hedge gains since 2008.
For 2020, Hey, ours hedged 94% of its expected natural gas production at $2.87 per annum Beach, you, that's 23% above current strip pricing.
Hey, ours also well hedged in 2021.
With 100% expected natural gas production hedged at $2.80 per annum each year.
We also began hedging our 2022 natural gas production, adding 688 VBT huge per day of natural gas hedges at an average price in $2.48 per unit, which you with a goal of having the majority of projected natural gas production hedged before we enter 2022.
As you can see on slide 15, significant oil and oil equivalent hedge position.
Our resources is 100% hedged on 26000 per day.
The 6000 barrels per day of 2020 crude oil and pentane production at $55 at 63 cents per barrel or nearly 120% above current strip prices.
As this quarter our strategy, we will continue to be auction this opportunistic and adding to our natural gas and liquids hedge profile going forward.
In conclusion, the recent borrowing base Redetermination was an important step and enhancing our liquidity profile.
Successful execution of our asset sale program will provide sufficient liquidity to manage our upcoming senior note maturities until refinancing alternatives merge 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 commodities.
Yup.
Further reduce cost structure results in low maintenance capital of just $600 million to hold 2020 average volumes at around 3.5 Bcf per day flat in 2021.
If commodity prices remained depressed we plan to spend that maintenance level in 2021 to preserve liquidity and maximize free cash flow with an increased focus on our dry gas drilling inventory.
Close out by saying, we continue to be pragmatic and diligence in response to the current uncertainty driven by the cobot 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 to the operator for questions.
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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.
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.
21 is back to 75, we did have a fall off in 22, but just curious about how you're thinking about that portfolio in any any evolution.
Well.
In terms of our long term evolution as as we said in our prepared remarks, Sally we expect to continue to hedge and so that much of our gas production. Our most of it will be hedged by the time, we entered Cal 22.
As you know we have.
We were not afraid to monetize hedges we've done it before.
Rarely have we I think monetized and left ourselves naked instead, we've just.
Monetize Dan Reprice, 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 were enjoying the curve move up as you know you've seen it move up through Cal 21, it into Cal 22, and we think thats positive and underpinned by fundamentals so.
Weve, even though we've been hedging in the first quarter, where.
Watching and.
Rooting for it to go up a little bit more before we layer in anymore. So.
City comfortable with our hedge book at this point and no active plans to monetize it.
Okay.
Great and then maybe Glenn you talked about that four four different pad and the Ohio dry gas area and I think you said that kind of compromise comprised about 50% of the 21 plan at this point can you sort of give us some color around maybe tilt in.
That 21 guide.
At the maintenance level right now.
Yes thats.
That's it we're talking about substitution there so those would take the place of rich gas pads that we had on that 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 and think it may pay for us as a stay the course, but we want to develop that optionality to substitute and 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 three and a half Bcf a day.
So time will tell.
Okay. That's great and then maybe one final one for me just on that maintenance plane, you've outlined to you have a free cash flow estimate at this point to highlight.
For for next year Holly.
Yes between one.
We went to maintenance capital, Yes, I think we're pretty neutral and in 2021 using the current strip.
Our cash flow. Thank you guys recast yes. Thank you.
The next question is from David Deckelbaum of Cowen. Please proceed with your question.
Good morning, guys. Thanks for the time.
Just wanted to follow up on on Holly's last question, just about the maintenance capital program.
Based on current strip is that where you are leaning right now in terms of planning for next year I know that there has been theres a trade off obviously between your firm transport commitments.
And then maintaining liquidity here, but seems like you outlined.
Slowing down would equate to about 50 million increase in that marketing expense.
But it seems like that would be that better course, right now would be the whole volumes flat is that how youre thinking based on the current stripped yes, I think thats, what we said in the releases and that's the that's the new plan and we did the.
The key message for us from US is that we have a lot of flexibility of course and.
If natural gas.
Ill prices ran up significantly in 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.
It leaves us with.
Net marketing expense that $150 million range, while we stay flat.
But that will come down over time as we as we grow into that again eventually.
Okay. 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 our Frac crew.
No thats 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 havent hit the wall yet on that.
Cost per lateral foot.
Got it, but but you do have lower cost per lateral foot baked into that 600 no.
No we do not.
It's assuming the $715 per lateral foot. So if we went to 650 that would save another.
Yes.
That was $50 million probably.
Right.
For the 600 million next year just.
Okay.
And just the last one for me.
Hedges that you added.
At 248 going out to 2022.
You painted a fairly constructive pitcher on natural gas.
Yes, I havent seen your hedge down the to 48 before.
What was driving some of that decision or or was it was a 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 248 incentive.
Getting some colors to the upside.
Yes, I think feet.
As it Wasnt bank driven.
It was opportunity driven and we just saw prices moving.
During the time that we were.
Watching and rooting for it to go out that probably went from 232 to 248. So we saw the opening there too.
To add more hedges we havent.
Hedge that low before as you know collars of course, they are two way and so you'd you'd have a floor in the collar if you want it.
If the market where to 48 midpoint then.
If it's a sum.
Symmetrical collar has you know than your downside protection is going to be in that two thirtys are lower and so.
Just a strategy to be more defensive for a portion of our.
Production stream so.
Others, Yes, they give you the upside but just in case they they don't.
Bill and protecting your quite as much on the downside. We've we've generally been fan more 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 goes.
Yes. Thank you.
The next question is from Bryan singer of Goldman Sachs. Please proceed with your question.
Thank you and good morning.
Good 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 and I guess my question is do you need positive on each of these extended maintenance in 2021.
Or if gas prices are materially higher but the refinancing in the leverage has it been fully rebates would you spend about maintenance.
It's I'd say, it's unlikely we spend above maintenance and most any case I think we're a position of wanting to generate much free cash flow as we can so it would have to be very very compelling in multi year move and something that we get we can hedge to pull spot maintenance capital and then like I said, Brian that means.
As capital 600, that's assuming.
All about 60 wells at $8.6 million, each and then you have some.
Patent infrastructure spending on top of that so thats, how you get to the 600, if we if we reduce that to 650 a foot for instance, as a target than it would be less than that so that's the that's the messaging there we're not we're truck we're not trying to message torch.
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 completion into Twentytwenty. One from from later this year would impact late 2020 or early 2021 production levels.
Yes, we've completed I think 25 wells this quarter and complete 40, plus this next.
Second quarter, if you're going to growth in the second quarter and growth into the third and the flattens out from there. So your exit rates are right around that 3.5 Bcf a day and we were at 3.4 at this quarter. So throat relatively flat profile continues that way into 21.
Great. Thank you.
Thanks, Brian.
The next question is from a rune Jay Hichrom of JP Morgan. Please proceed with your question.
Yeah. Good morning, Gents I was wondering if you could.
But.
Think about.
You guided I believe 105 pills for for 2020, just wondering if you could maybe walk us through the quarterly progression and just how how do you get there as you.
As you move down to one.
Completion crew, perhaps for the balance a year 'cause on our math, we can see maybe getting the seventies.
Using your historical.
Completion crew to pop ratio, but just maybe give us a little bit of color there and I also want to talk about the 750 million in Capex guide this year for 105 pillars.
We would.
We have a hard time, maybe Rick reconcile that lower capex number based on that till activity, but maybe you could help us.
Starting with those two questions.
Help me first I mean, obviously you have to build and cycle time right. So if we're turning in line. The 105 wells. This year a lot of that capital occurred last year in 2019. This carry over there. So that's that's part of it and yeah. This is all highly engineered well by well. We know what are you ours are we know what our well costs are so so you can bet. It's all very.
Stacked in.
If you just heard my answer to my last question, but.
We're actually going to 70 in the first half of this year. So I don't know how you're getting the 70 thats pretty hard when were almost already there year to date so.
Then going from there it seems that would be about 15 to 20 million a quarter after that.
Yes, we should hit mid year at almost 70 turn in lines from.
The 35, Canada.
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 what year, we turned them in line with time, we turned what your return sale. So yes. Those are deferred into next year and are counted in that 60 65 wells next year.
Correct got it and if we just included the Capex on the 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 our on our numbers, we estimate the sustaining capex just under 900 million, but clearly costs are coming down so just trying to.
Maybe adjust our thoughts on sustaining capex.
Yes, I think simple way to think about it is just.
Our well costs are now about $8.6 million for 12000 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 it's Pat infrastructure type costs.
But it also at that 20, those 20 wells, it's only about $2 million drilling costs. So that only yeah helped by about $40 million and if you go down that Thats 650, which we think is achievable that more than offset that so and obviously you know turned in line 60 wells, but we're also spudding a number of wells next year that will carry over into 2022, So yes on your.
900 million I mean, that's an interesting number I mean, we're spending 750 million. This year to grew 9%. So I don't know how you'd have to spend 900 million to stay flat I think thats, an old number from probably a year and a half ago going into 2019, right well cost of about 970, yet but.
Thats all changed dramatically right.
$3 million less per well.
Yes fair enough it wasn't one could ever but fair enough.
No I think it was off of higher probably higher production level in terms of go into maintenance that 900 number.
Well, that's the current number 600 million stay flat at three and a half.
Okay.
All right great. Thanks, a lot.
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. Thank you for the second largest uptick.
Just on your free cash flow numbers for this year appreciate all the color just a few questions there.
I see there was last quarter, you were talking about a payment from the W. GL bleach.
Does that does that still expected. This year and then also maybe you can comment a little bit about what what type of.
Working capital adjustments you may have some dropping rigs sort of as there are negative outflow should be thinking about.
Yes, we are assuming that that.
Payment from that lawsuit gets paid this year.
That's not exactly can certainly flowed into next year, but thats included in this year right now.
Then the free cash flow numbers before working capital changes.
Is there can you give us a sense of how much that should how much would drain that should be firmed up in the rights.
Great. We've tried in years past it really forecasts that weve never really been able to get our.
Our hands around that there's such a dynamic equation and a lot of factors and if that were just we just don't have a good ability.
Jeff.
Okay, and just maybe when they want to ask sales I know it's.
You pointed out on things Youve shown in the past is there is there anything moving to the front that further the line based on what's happened commodities and just investor interest that we should be thinking about.
You are seeing that's that's that's sort of up that's developing.
To be better than people think.
Could you state that again whats so yes.
Sales what's.
What's the number what's the number of asset sales off I'm curious, what what do you six moving to the from 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 million this quarter.
What's.
What drove that how should we be thinking about that and the shirdi market. How that's quite how that should play through last year, we actually talked about that into 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 access surety bonds for 80 million that brought it down to $630 million at year end than we did have that pickup of 100 million that we talked about in February to 730, but thats, where we see it right now.
And so the clarity maybe just one more if I can just your program here, how should we think about the mix of production changing.
Relative to today.
Next year.
Face the same.
Yes.
Yes, we started to mix in gas drilling next year, you really wouldn't see much of an impact until probably 2022.
Craig 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 enough.
Well at 68%.
Gas and 32% liquids range.
Well volumes through time.
You very much.
Appreciate it.
The next question comes from Bells Fitzpatrick Suntrust. Please proceed with your question.
Hey, good morning.
Hi wells.
Yes, I notice VP piece of have kind of popped into the potential menu for.
For Monetizations can you can you talk to to how those got in there I mean is that is to override market, maybe just a little bit.
Soft like were seen in the public mineral company multiples there does that broaden the potential lift the buyers that that that you could transact with.
Well ppps are somewhat similar to overrides, obviously, so it it is a bit of a similar market in the BPP tend to be more of a bank market.
And it's just something it's another tool the tool chest, it'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 rise in the natural gas are up and we think eventually a nice move in NGL prices.
Okay and then just just one clarification on my end. So 21 has 40 to 45, new wells, obviously, excluding the ducks with with two rigs and am I getting that right that seems like a little bit of a slower pace and you guys have been turning then.
No I think that's more like one and a half rigs.
Each rig gets you about 30 wells so.
Where we know we're drilling these wells spud to rig release, and Chad and a half days now 12000 foot lateral so.
It's a pretty hefty pace.
Just gets better okay perfect yeah. Thanks, so much.
Yes, Thank you wells.
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 first quarter conference call. If you have any further questions. Please feel free to reach out to thanks again.
That concludes today's conference you may disconnect. Your lines at this time. Thank you for your participation.
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